1 TABLE OF CONTENTS

3.2 CO2 Reduction Potential from Generation Shifts Among Affected EGUs (Building Block 2) ..... 2 3.2.1 Ability of shifting generation among existing EGUs to reduce CO2 emissions ..................... ....... 2 3.2.2 Magnitude of generation shifts among existing EGUs ............................................. ................... 100 3.2.3 Natural Gas Supply ..........................

................................................... ........................................... 224
3.2.4 Technical Considerations ....................

................................................... ....................................... 236 3.2.5 Analysis of Cost-Effectiveness...............

................................................... ..................................... 366 3.2.6 Natural Gas Price Impacts ...................

................................................... ...................................... 403 3.2.7 Co-firing ...................................

................................................... ................................................... . 435
3.2.8 New NGCC ....................................

................................................... .............................................. 438 3.2.9 Regional approach ...........................

................................................... ........................................... 444 3.2.10 Setting a floor ............................

................................................... ................................................ 46 5
3.2.11 Glide Path .................................

................................................... ................................................. 4 78
3.2.12 Other ......................................

................................................... ................................................... . 5242

3.2 CO2 REDUCTION POTENTIAL FROM GENERATION SHIFTS AMONG AFFECTED EGUS (BUILDING BLOCK 2)

This section addresses comments on CO2 Reduction Po tential from Generation Shifts Among Affected EGUs (Building Block 2). We have organized the comments in this section under 12 subsections, 3.2.1 to 3.2.12. Responses to the comm ent topics of these subsections are discussed below along with summaries the specific public comm ents.

At proposal, we referred to building block 2 as “Re -Dispatch of Existing Units,” and consequently this is the terminology used by the co mmenters on building block 2. We have retained the original words of the commenters in th e comment summaries in this section, although for purposes of the final rulemaking we no w refer to building block 2 as “Generation Shifts Among Affected EGUs.”

3.2.1 Ability of shifting generation among existing EGUs to reduce CO2 emissions

This section discusses specifics of the EPA’s asses sment of the ability to reduce CO2 emissions by shifting generation from existing coal-fired EGU s to existing NGCC units.

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

Comment 1: Commenters stated that trying to squeeze coal out of the energy equation is not only unrealistic, but it's also dangerous and irres ponsible.

Response 1: The EPA disagrees with the interpretation of the R ule. In response to additional analysis and many comments, we have modified the pr oposal and RIA. The 111(d) final rule requires that states develop plans that establish e mission standards for affected EGUs. We are providing states with substantial flexibility as to how they structure those plans to achieve the 111(d) requirements. The flexibility includes, for example, the choice of approaches, trading, time to develop plans, additional time before the s tart of the interim performance period (postponed from 2020 until 2022), and the ability t o shift emission rate achievement between performance periods. The Building Blocks are not pr escriptive, and states may consider local circumstances as they develop their plans, includin g other regulatory requirements and planning.

EPA does not believe that achievement of the final rule requirements will result in overconstruction of new generation. See sections V.D, V III.A, VIII.C and VIII.G of the final rule preamble of the CPP and Chapter 3 of the GHG Mitiga tion Measures TSD for the CPP Final Rule supporting the final CPP.3

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

Commenters referenced a study and stated the study finds that short-term natural gas may be worse than burning coal. Commenters stated these re sults contribute to the argument that building new baseload gas plants is unadvisable.

Comment 2: Commenters said that re-dispatching generation from coal to natural gas, co-firing, and conversion of coal plants to operate on natural gas are all adequately demonstrated and costeffective.

Response 2: The EPA generally agrees. See section V.D of the fi nal rule preamble of the CPP and Chapter 3 of the GHG Mitigation Measures TSD fo r the CPP Final Rule supporting the final CPP for EPA’s detailed approach to the issues.

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

Commenters said that the potential to reduce carbon pollution at the point of combustion by using natural gas in lieu of coal is fully demonstr ated. Commenters stated that the states in the Clean Power Plan Implementation Group have experien ced increased utilization of more efficient NGCC units while experiencing decreased g eneration at the most carbon-intensive
fossil-fired EGUs. Commenters elaborated that that for that group of states, electricity generation from natural gas-fired EGUs increased 37 percent be tween 2005 and 2012, while generation
from more carbon-intensive coal-fired EGUs has decr eased 36 percent over the same period. 50

Commenters stated this shift to less carbon-intensi ve fossil fuel-fired generation was a major factor in the 23 percent reduction in carbon emissi ons achieved by those states over the same period of time. Commenters referred to success achi eved by the RGGI and California's Global Warming Solutions Act which focuses on shifting gen eration from more carbon-intensive EGUs
to less carbon-intensive EGUs. Commenters added tha t the power sector has been constructing and generating electricity with natural gas in comb ined cycle natural gas plants for many decades and a significant switch of baseload capacity from coal-fired steam generation to NGCC has
occurred. Commenters cited EIA data that indicate f rom 2003 to 2012, coal generation fell from about 2 million GWh to 1.5 million GWh.478, and dur ing the same period, natural gas capacity increased from 165 GW to 242 GW and generation clim bed from about 650 thousand GWh to over 1.2 million GWh, as a result of both increased capacity factors at existing plants and new facility construction; commenters stated that natur al gas consumption for electricity generation increased 20 percent from 2011 to 2012. Commenters said that today natural gas plants are commonly operating as baseload plants, providing 27 percent of U.S. net power generation in 2013, compared to only 10 percent in 1994. Likewise , commenters added, the use of natural gas to co-fire alongside coal in steam generating plant s and the conversion of coal-fired power plants to operate on natural gas is well established. Comm enters said that potential carbon pollution reductions are well established; burning coal to ge nerate a given unit of energy generates nearly twice the carbon at the stack as does burning natur al gas to generate the same unit of energy.

Commenters agreed with the EPA's proposal that incr easing utilization of existing NGCC units is a component of the BSER, and noted that this has be en demonstrated by the experience of the4

states in the Clean Power Plan Implementation Group . Commenters stated that NGCC units that were operating in their states in 2005 increased th eir generation 21 percent by 2012. 51 Commenters added that this significant increase in utilization at existing NGCCs is a significant component of the system our states have collectivel y used to achieve emission reductions and improve emissions intensity.

Comment 3: Commenters agreed that significant CO2 reductions a re available by re-dispatching the electric generating fleet.

Response 3: EPA agrees that generation shifting among affected EGU’s is a cost-effective and proven approach to reduce emissions. See section V .D of the final rule preamble of the CPP and Chapter 3 of the GHG Mitigation Measures TSD for th e CPP Final Rule supporting the final CPP for EPA’s response to this comment.

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

Commenters said that the use of natural gas for pow er generation has proven to be an effective method of lowering carbon dioxide emissions. Accord ing to the Energy Information Administration, commenters said, US energy-related carbon dioxide emissions have declined in four of the last seven years since 2007 and are dow n a total of 10 percent from 2005 levels due in part to increased natural gas-fired generation. Com menters described the large role natural gas has played in GHG emissions reductions in the US ov er the last several years and noted that the proposed Clean Power Plan looks to natural gas to c ontinue this trend. According to the Sustainable Energy in America Factbook, commenters said, natural gas provided the US with 27 percent of its total energy supply, and 28 percent of US electricity in 2013, up from 22 percent in 2012. In the proposed rule's base case year of 2012 , commenters added, power generation from combined cycle units and other natural gas generato rs reached an all-time high of 30 percent and contributed to carbon dioxide emissions falling to a 20 year low. Commenters said that these reductions demonstrate the ability of the natural g as industry and competitive markets to reliably deliver emission reductions without additional regu lations. Commenters concluded that natural gas generation has a proven track record of lowerin g emissions, and its inclusion in the proposed rule recognizes its environmental benefits.

Commenters stated that a recent "bottom-up" analysi s of the potential carbon mitigation from redispatching the fleet of coal generating units to N GCCs by researchers at the National Renewable Energy Laboratory (NREL) found that this strategy holds the technical potential to mitigate over 500 million metric tons of CO2, or ab out 25 percent of the power sector's total emissions in 2012. Commenters stated the study foun d that over 300 million metric tons of CO2 could be avoided at EPA's proposed 70 percent NGCC utilization "ceiling"

Commenters stated that dispatch switches from coal to gas can be taken exclusively by regulated sources (EGUs) and provide a key, near-term source of emission reductions. Commenters supported the EPA's approach regarding the increase d dispatch of existing NGCC and stated that, significantly, re-dispatch of existing plants alone can achieve almost half, or more, of the 30% reductions targeted by the ESPS program. Commen ters stated that various studies show5

EPA's assumption of 13% emission reductions to be n ot only feasible, but that dispatch changes could bring about emission reductions of 20% or mor e. Commenters referenced the following studies: (1) the Massachusetts Institute of Technol ogy has found that NGCC could displace roughly one-third of U.S. coal generation, reducing CO2 emissions from the power sector by 20%; (2) a recent NREL study found increased NGCC d ispatch could reduce about 25% of the sector's total emissions; and (3) a report by SNL F inancial found that output from existing units could be increased by as much as 23 percent, 41 per cent, and 55 percent in the areas covered by the SPP, MISO and PJM.

Commenters indicated that to some extent, the syste m has already demonstrated the viability of this approach, noting that in 2012 NGCC facilities in the United State increased their annual capacity factors to an average of 51.1 percent and coal-fired EGUs reduced their annual capacity factors by more than 10 percent (from 63.7 to 56.7 percent), according to EIA's Electric Power Monthly. Commenters pointed out that as a result, e lectric sector CO2 emissions were at their lowest level since 1996. Commenters added, however, that this shift in utilization was not consistent across all states, and there are operati onal considerations that the commenters believe should be reflected in the standard setting calcula tions.

Commenters stated the significant underutilization of NGCC facilities is a presently existing condition, and these NGCC facilities represent an e ffective means for achieving roughly a 50 percent reduction in GHG emissions. Commenters stat ed these reductions are within reach in the near term and states should be encouraged to seize such opportunities. Commenters stated that, while concerns have been raised regarding infrastru cture and other limitations, those discussions fail to reflect the extent to which many NGCC plant s do have sufficient existing infrastructure and stand ready and able to operate at and above th e target capacity factors.

Commenters stated NGCC units can produce as much as 46 percent more electricity from a given quantity of natural gas than steam EGUs, maki ng re-dispatch from coal and oil-fired EGUs a significantly less expensive way to reduce CO2 em issions than through natural gas conversions or co-firing. Commenters noted this estimate assume s an average heat rate of 10,434 Btu/kWh
for coal fossil fuel-fired steam units between 400 and 600 MW and 7,130 Btu/kWh for NGCC
units between 400 and 600 MW.

Comment 4 : A number of commenters expressed general concerns about whether the reliability of the electric system can be maintained under prop osed building block 2. Commenters addressed reliability with respect to NGCC capacity , gas supply, load following, local reliability rules, regional impacts, single fuel dependence, sy stem requirements, timing, transmission adequacy.

Response 4: The EPA disagrees. The rule does not mandate that c ertain units are run. In response to additional analysis and many comments, we have modified the proposal and RIA –

the establishment of CO2 emission reduction standar ds is regionally based. The 111(d) final rule requires that states develop plans that establish e mission standards for affected EGUs. We are providing states with substantial flexibility as to how they structure those plans to achieve the 111(d) requirements. The flexibility includes, for example, the choice of approaches, trading,6

time to develop plans, additional time before the s tart of the interim performance period (postponed from 2020 until 2022), and the ability t o shift emission rate achievement between performance periods. The Building Blocks are not pr escriptive, and states may consider local circumstances as they develop their plans, includin g system reliability, fuel diversity, other regulatory requirements and infrastructure. EPA doe s not believe that achievement of the final rule requirements will result in over-construction of new generation. See sections V.D, VIII.A, VIII.C and VIII.G of the final rule preamble of the CPP and Chapter 3 of the GHG Mitigation Measures TSD for the CPP Final Rule supporting the final CPP.

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

General

Commenters briefly listed many general concerns rel ated to re-dispatch and reliability, as noted
below.

Commenters stated the EPA has not adequately consid ered the feasibility or costs related to redispatch and premature unit retirements, or conside red the effect on system reliability, and there is no analysis of whether the existing transmission system can accommodate the dramatic changes that EPA's proposal may necessitate. Commenters requested the EPA to ensure that rules do not mistakenly accelerate the removal of electri c generation capacity when corresponding alternatives are not available endangering the avai lability of reliable, base-load energy, there by endangering our regional, state and national econom ies. Commenters noted that Arkansas's coal plants were designed and built to provide baseload power, while the non-merchant NGCC units were designed to provide electricity during periods of higher demand and stated that changing the purpose and design of these units so drasticall y will have a substantial adverse impact on utility rates and the reliability of service.

Commenters stated that for many existing NGCC units there is simply insufficient pipeline, gas availability, or transmission infrastructure to per mit operating year-round at a 70 percent capacity factor. Commenters stated that these infra structure limitations are exacerbated by the fact that the proposed state goals are calculated a ssuming that states will fully implement Building Block 2 by 2020, giving states and utiliti es only a few years or less in which to expand gas and transmission infrastructure as needed to re ach the target level, which commenters regard as impossible. Commenters stated that the infrastru cture to transport natural gas to increase the dispatch of NGCC units to 70% capacity factor is in adequate.

Commenters stated this building block dramatically oversimplifies the ability of one generation
source to substitute for another. Commenters stated that relying on natural gas for high-capacity factor, baseload operations creates significant dis patch, reliability, and transmission concerns for operators. Commenters stated that, while natural ga s has played a valuable role in producing high levels of power while load following to support var iable power supplies and peak demand, and contributing to system voltage and frequency needs, all of these roles will be complicated by acute fuel supply and price issues. Commenters stat ed that both the Federal Energy Regulatory7

Commission (FERC) and the North American Electric R eliability Corporation (NERC) have expressed concern about the reliability implication s of increased natural gas use.

Commenters stated that Building Block 2, which is p redicated upon unit capabilities, does not consider system capability and, in New York State, to increase the NGCC factor to 70% will result in significant reliability issues or force a n undesirous market redesign. Commenters agreed
with NERC concerns that continued assessment of the reliability implications of the proposed Clean Power Plan need to occur, because the over de pendence on one fuel type can expose customers to the potential of detrimental price vol atility.

Commenters listed some reliability concerns identif ied in a NERC report regarding increased reliance on natural-gas-fired generation. [See NERC , Potential Reliability Impacts of EPA's Proposed Clean Power Plan: Initial Reliability Revi ew at ii (Nov. 2014).]

First, NGCC units have traditionally been used for load following purposes, and while some are capable of operating at a high capacity factor, the y are generally less well-suited to serve as baseload resources than coal generation. Second, th e Proposed Guidelines would accelerate an ongoing utility industry shift from coal- to gas-fi red generation, threatening the fuel diversification that utilities traditionally rely o n to help to preserve reliability. Third, as the events of the winter 2014 "polar vortex" demonstrat ed, natural gas generation can face serious fuel availability issues during extended periods of cold weather. The Initial NERC Report expresses concern that over-reliance on natural gas generation will degrade utilities' ability to manage cold weather conditions and threaten reliabi lity. Fourth, Building Block 2's assumption that "the power industry in aggregate can support h igher gas consumption without the need for any major investments in pipeline infrastructure" i s unrealistic. There are "critical areas," including Arizona, Nevada and New England that alre ady face pipeline constraints, and those areas will need still more pipeline capacity to the extent that coal generation is replaced by natural gas generation.

Commenters stated that, with the Proposal's assumed significant shift from coal-fired to gas-fired generation, the power delivery system's fuel divers ification and associated resiliency will be seriously degraded, and its reliability negatively impacted. Commenters referenced the NERC Initial Reliability Review and highlighted the foll owing:

Higher dependence on natural gas can expose additio nal reliability risks, including pipeline transportation constraints that could result as mor e gas-fired generation is built. NGCC units could displace coal-fired generating units as basel oad units, forcing less-efficient coal units out of service, further increasing demand for natural g as. Adequate timing is required to add new pipeline and generation resource capacity where it is needed to offset coal plant retirements and supply natural gas to new generation. As gas-electr ic dependency significantly increases, unforeseen events like the 2014 polar vortex could disrupt natural gas supply and delivery for the power sector in high-congestion regions, increasing the risk for potential blackouts.

Commenters stated the EPA over-estimated the amount of NGCC capacity available for redispatch by failing to consider limitations like op erational constraints, reliability, infrastructure, and statutory and regulatory barriers that may impe de re-dispatch. Commenters stated the EPA's8

economic impact analysis failed to consider strande d asset costs and state-specific employment impacts of such extensive re-dispatch.

Gas supply and storage

Commenters stated that, unlike coal, gas plants typ ically have no storage capability which can lead to interruptions in service.

Commenters stated that coal fired plants have on av erage a thirty-day supply of energy on-site, whereas natural gas fired plants typically have no fuel storage capability. Commenters stated that supplying NGCCs with adequate gas year round will c ause some NGCCs to run on liquid fuels or shut down, reducing capacity factors. Commenters stated coal has always been the reliable fuel, as coal can be safely and conveniently stored on the plant side removing risks of failures in the delivery systems such have been experienced by natural gas. Commenters noted that unlike coal and fuel oil, natural gas typically cannot be stored on site at an EGU and as a result, natural gas is limited to real-time delivery through a netw ork of pipelines and bulk gas storage. Commenters noted that, unlike with coal, the abilit y to store natural gas onsite at the plant is very limited, making interruptions to delivery service a very serious issue concerning grid reliability.

Commenters stated that demand for natural gas will grow and the ability to supply the gas may cause interruptions in service. Commenters added th at demand for natural gas is expected to grow in other sectors (e.g., transportation, export s, and manufacturing), further affecting its availability for EGUs. Commenters also noted that a n additional problem is that existing natural gas pipeline infrastructure is old and not designed to transport the volume of gas required by NGCC plants operating at a 70 percent capacity fact or - transportation of larger quantities of natural gas at higher pressure through an aged infr astructure may cause public safety issues that EPA is not appropriately considering. Commenters st ated that a continuous supply is critical to support electric generators; however, natural gas i s widely used outside the power sector, and the demand from other sectors, particularly coincident end-user gas peak demand during cold weather, critically affects gas providers' ability to deliver interruptible transportation service in the power sector.

Commenters raised concerns about increased dependen ce on natural gas for generation, especially during extreme winter events.

Commenters noted that during the winter "polar vort ex" in January 2014, NGCC units were unable to come online due to the cold temperatures and natural gas curtailments. Commenters noted that according to PJM, "Among the challenges for PJM and its members in maintaining grid reliability during the month were unplanned ge nerator shutdowns from the cold and the stress of extended run times, natural gas curtailme nts and fuel-oil delivery problems." 16 Commenters noted that in Chapter 3 of its Polar Vor tex Review, September 2014, NERC states: "Increased reliance on natural gas during the polar vortex exposed the industry to various challenges with fuel supply and delivery. This incr eased reliance, compounded by generation outages during the extreme conditions, increased th e risks to the reliable operation of the BPS." Commenters noted last winter's polar vortex weather event in the PJM interchange when over 9,000 MW during a peak demand day of natural g as fired units went into a forced outage due to natural gas fuel curtailment. Commenters sta ted there was simply not enough natural gas9

transportation capacity available to satisfy the ho me heating and power generation needs of the area. Commenters stated that on January 7, 2014, wh en temperatures fell to below zero, near a quarter of the PJM operators faltered due to low te mperatures, with natural gas generators being
47% off line at one time. Commenters stated that al most 90% of the planned 7,100 MW of AEP coal unit retirements were called to operate during that time. Commenters stated that as observed during the 2014 polar vortex, the relationship betw een gas-fired generation availability and low temperatures challenges the industry's ability to m anage extreme weather conditions - particularly when conditions affect a wide area and less support is available from the
interconnection. Commenters stated that extreme wea ther conditions have the potential to strain BPS reliability and expose risks related to natural -gas-fired generation availability. Commenters asserted that with greater reliance on natural-gas- fired generation, the resiliency and fuel diversification that is currently built into the sy stem may be degraded, which NERC has highlighted in recent gas-electric interdependency assessments.

Commenters stated that establishing a dispatch-base d mitigation goal that impacts other existing generation types without thorough consideration of the impacts to resource adequacy may significantly degrade reliability. Commenters gave the example that during the extreme cold temperatures across most of the Southern and Easter n United States from January 6 to 8, 2014, natural gas fired generating plants did not perform as expected due to both plant outages and natural gas delivery system inadequacies. As an exa mple, commenters noted that in the PJM footprint 9,700 MW of gas generation capacity was u navailable due to forced plant outages and another 9,300 MW unavailable due to natural gas sup ply constraints, such that approximately 36% of the natural gas generation capacity was effe ctively forced out.

Commenters expressed concern regarding the reliabil ity of gas supplies to EGUs and households for home heating purposes. Commenters stated that i mplementation of the CPP could raise reliability issues associated with availability and distribution. Commenters stated that, in the absence of adding expansive new natural gas pipelin e capacity, the current infrastructure in Indiana is limited and may not be able to handle th e increased demand for natural gas to both
residential customers and EGUs. Commenters stated I ndiana is currently evaluating the
infrastructure to determine the effect this rule wi ll have on grid reliability. Commenters stated that a shortage of fuel capacity during cold Indian a winters could pose serious consequences for residential heating needs, as well as grid reliabil ity, and this would present a serious threat to public health and welfare for the citizens of India na.

Load following

Commenters expressed concern that NGCC units are be tter suited than coal to follow load and as NGCC units move to baseload operations reliability issues may arise.

Commenters indicated that today's coal fleet may no t be able to provide adequate flexible operations capabilities for the overall fleet as mo st existing coal plants were not originally designed for such duty. Commenters stated that NGCC units are better suited to follow load and that cycling coal-fired EGUs reduces heat rate effi ciencies, causing their CO2 emission rates (lbs/MWh) to deteriorate, and offsetting the Buildi ng Block 1 assumptions. Commenters stated that, because some NGCC units were specifically des igned and permitted to provide dedicated backup generation for intermittent sources of renew able energy, such as wind and solar - for10

these units, a significant portion of their capacit y would need to be preserved for reliability purposes, limiting the capacity available for re-di spatch to displace coal-fired generation and serve base load. Commenters stated that operational and reliability issues arise as lost dynamic response capabilities to match intermittent load ex ist when CCNG fast ramp optionality is eliminated. Commenters stated that by dispatching N GCCs as baseload resource, less capacity is available to quickly adapt to the changing load, ma king the power system less reliable, or at least requiring the addition of more intermediate or peak ing capacity. Commenters stated that, because fuel source diversification helps maintain affordab le energy prices and ensure reliability, a greater reliance on any one fuel source, such as na tural gas, makes the power system more susceptible to fluctuations in price and availabili ty of that one fuel source.

Commenters stated that coal-fired unit generation m ust remain an integral part of Indiana's baseload power generation to maintain current syste m reliability. Commenters stated that, under the Proposed Rule, coal-fired units historically us ed for baseload power generation would effectively need to transition into load-following units. Commenters noted that, at NIPSCO, current average coal-fired unit ramp rates are much slower than the NGCC ramp rate. Commenters stated that relying on coal-fired units to supply load-following generation could decrease electric system reliability because these units are not designed to respond to rapid changes in demand. Commenters stated that coal-fire d units' original design was for baseload service and, as cycle frequency increases, there is more wear and tear on these units resulting in more frequent forced outages. Commenters stated tha t more frequent forced outages pose increased reliability risk.

Commenters stated that the forced re-dispatching of natural gas generation and the addition of large amounts of renewable energy resources will im pact the stability and reliability of transmission grids in varying degrees. Commenters n oted that coal-fired generation often provides real and reactive power to load centers; f or example, TVA's Gallatin coal plant in middle Tennessee not only is a primary source of re al energy needed by the Nashville region, but it also is the source of reactive power that is ess ential for keeping the transmission grid stable in the area. Commenters indicated that to shift genera tion from that plant to a natural gas-fired plant
located elsewhere increases the risk of service dis ruptions. Commenters stated that the EPA recognized such risks in its enforcement memorandum addressing when it would provide utilities additional time to comply with the MATS rule.

Commenters noted that many of the units retiring by 2020 are smaller coal units which follow load well and also noted that increasing renewable capacity under Building Block 3 calls for more load following due to the inherent intermitten cy of renewable energy technologies. Commenters stated that increasing the capacity fact ors of NGCCs and operating them as more base-load resources reduces their ability to turn d own or ramp up as a load-following resource.

NGCC capacity

Commenters expressed several concerns regarding the ability to meet a 70% capacity factor while maintaining grid reliability.

Commenters indicated that the EPA's justification t hat the current NGCC fleet is designed for and is demonstrably capable of reliable operation a t 70 percent capacity is based on the NGCC11

fleet's average availability, but such an analysis says nothing of the reliability of units operating at a 70 percent or greater capacity factor for prol onged periods. Commenters stated that, while there is little evidence that the 70 percent capaci ty factor will represent a technological concern for the power sector, the most significant concern is that natural gas facilities do not have the experience of sustained operations at this level. C ommenters stated that a 70 percent capacity factor would change the purpose and design of the n ation's NGCC fleet at-large, and the EPA must consider whether fleets by state or NERC relia bility zones can operate reliably at such a capacity factor. Commenters referred to several rep orts concerning reliability. Commenters asserted that the EPA should defer to the expertise and jurisdiction of System Operators, NERC, and balancing authorities in ensuring resource adeq uacy and grid stability.

Commenters stated the EPA has not adequately consid ered reliability in the development of state goals under Building Block 2. As an example, commen ters indicated that if the target level of NGCC re-dispatch under Building Block 2 eliminates coal-fired generation in a particular state, but the post re-dispatch capacity factor of 70 perc ent from NGCC is not feasible, the reliability implications of this improper assumption will be ve ry significant and serious. Commenters contended that the EPA ignores several factors that would limit the ability of existing NGCC units to increase utilization to an average annual capacity factor of 70% and that would prevent that increased NGCC generation from replacing displ aced coal and O/G generation. Commenters stated that the EPA does not even acknowledge, let alone adequately address, the constraints preventing existing EGUs from operating at a 70 per cent or higher capacity factor. Commenters added that the EPA completely ignores potential tec hnical or permit limits on NGCC unit operation and dismisses infrastructure concerns. Co mmenters asserted that the Agency's primary response - that the allowance for "emission rate av eraging across multiple units and across time" within a state in the proposed emission guidelines will compensate for such constraints - does not demonstrate that a 70 percent overall capacity fact or is achievable. Commenters stated the EPA makes no attempt to determine whether each state wi ll have a sufficient number of existing NGCC units that are able to generate sufficient ele ctricity above a 70 percent capacity factor to make up for units that are not able to approach thi s level. As a result, commenters characterized the Agency's reliance on "averaging flexibility" as "mere speculation or conjecture".

Commenters stated the EPA's analysis of the existin g NGCC capacity "available" for re-dispatch fails to consider reserve margin requirements. Comm enters stated reserve margin is the amount of generation capacity an entity must maintain in e xcess of its peak load-serving obligation. Commenters stated that erosion of the reserve margi n increases the likelihood that MISO would need to manage peak demand through the use of emerg ency operation procedures.

Commenters stated that the assumption that the capa city factor at all NGCC units can be raised to 70% is an overreach into the resource planning a uthority of utility regulators. Commenters said economic dispatch is based on the principle of providing the least cost option from available fleet resources to deliver the required power to th e grid. Commenters added that the diverse energy portfolio that Georgia utilities have cultiv ated lessens rate impacts due to unexpected price shocks. Commenters said the proposed rule tak es that option away from the utility and mandates which electric generating units are used i rrespective of cost.

Regional Issues12

Commenters expressed concern that the EPA may not h ave adequately addressed regional issues that could affect grid reliability. Commenters stat ed that the need for, the accessibility to, and the impacts of the increased use of natural gas in elec tricity generation are not uniform in all parts of the country - there are regional differences in fue l diversity, the use of firm or interruptible natural gas pipeline capacity by electric generator s, natural gas pipeline capacity availability and flexibility, natural gas storage availability, inte gration of variable renewable resources, communication protocols as well as potential reliab ility impacts or system vulnerabilities that may occur as the generation fuel mix changes in the various regions. Commenters gave the example that while New England has concerns related to the lack of pipeline infrastructure and the ability of generators to contract firm natural gas delivery services, the desert Southwest has firm pipeline contracts but lacks natural gas stora ge and has concerns related to the flexibility needed on the gas side to address challenges associ ated with the increased deployment of
variable resources. Commenters stated that the elec tricity sector's growing reliance on natural gas raises concerns regarding the electricity infrastru cture's ability to maintain system reliability when facing a constrained natural gas capacity for delivering natural gas to electric power generators. Commenters stated these concerns are al ready being articulated in light of gaselectric dependency studies and analyses, and inclu de ISO/RTOs, electricity market participants, industrial consumers, national and regional regulat ory bodies, and other government officials.
Commenters added that the extent of these concerns varies from region to region; however, concerns are most acute in areas where power genera tors rely on interruptible pipeline transportation as the natural gas use for generatio n rapidly grows.

Commenters stated that the regional nature and comp lexity of natural gas availability issues have been discussed by FERC Commissioners: Chairman LaFl eur noted in 2013 Congressional testimony that "[i]n certain regions, there may be inadequate local pipeline capacity to support generation during the winter heating season, due to geography, fuel mix, and market structure. This is already an issue in New England, and may be an emerging issue in other regions as more gas is utilized for generation;" similarly, Commiss ioner Moeller has voiced his concern about "whether there will be sufficient pipeline capacity to support this increase in natural gas generation." Commenters noted that during a Septemb er 18, 2014 public meeting convened by Commissioner Moeller, electric generation owners vo iced a number of concerns about the ability of the natural gas system to meet the needs of the electric system as well as "concerns regarding unknown or unreasonable commercial terms in pipelin e service agreements, a lack of transparency surrounding available services and ill iquidity in the natural gas market." Commenters stated that FERC began examining this is sue in August of 2012, and, since that time, electric utilities, system operators and stat e commissions also have examined the reliability
issues associated with the increased use of natural gas for electric generation in their respective regions. Commenters noted that FERC has recently tu rned its attention to natural gas and electric scheduling in an effort to determine whether and ho w natural gas and electric industry schedules and practices could be harmonized to achieve the mo st efficient scheduling systems for both
industries. Commenters stated that in addition to F ERC, the RTO/ISOs also are discussing these issues through their stakeholder processes and are conducting regional studies to determine what must be done to maintain reliability going forward, and that NERC has similarly noted that "higher dependence on natural gas can expose additi onal reliability risks, including pipeline transportation constraints that could result as mor e gas-fired generation is built" (Initial Reliability Review at 10). Commenters asserted that if the organizations charged with maintaining reliability and ensuring the functionin g of electricity systems and markets are13

concerned about natural gas infrastructure and gas- electric coordination, EPA cannot ignore these issues in its BSER analysis. Commenters state d that chief among these issues are the sufficiency of the current natural gas pipeline inf rastructure, as well as the financing mechanisms for future pipeline construction and the competitio n for existing pipeline capacity.

System

Commenters expressed concern that the EPA needs to adequately consider the system requirements, especially related to the closure of coal plants.

Commenters expressed concern that, in projecting a non-economic dispatch of natural gas EGUs to become baseload generation, EPA's models have fa iled to recognize that coal plants idled are no longer likely to be economic and will be forced to retire, many prematurely, leaving the US with a huge national electric generation reserve de ficit. Commenters stated that coal plants will close not only because they are not dispatched but also because their economics were based on baseload, high capacity factor operation; transitio ning these plants to mezzanine or peak period units results in insufficient revenues to carry the staff and fixed costs that baseload coal plant
must maintain to remain viable. Commenters stated B uilding Block 2 is impractical because it ignores the need to keep coal resources online for reliability support. Commenters stated PowerSouth must keep a set amount of spinning reser ves available at all times under NERC requirements, and to do this it typically keeps at least one of the Lowman units online at all times. Commenters stated that, in order to prevent rolling blackouts or brownouts, PowerSouth must be able to dispatch the Lowman coal-fired powe r plant in order to maintain stability and reliability under extreme, but foreseeable, loading conditions. Commenters stated that this extra capacity supplied by the Lowman unit (and required by NERC) may prevent the NGCCs from operating at a 70 percent capacity factor. Commente rs noted the power demands during the severe winter season earlier this year and stated t hat system failure was avoided only through the sustained peak generation of several coal-fired pow er plants. Commenters suggested that, instead of substituting a method of power generation that i s unproven at capacities needed to fulfill grid demands, the EPA should recognize the already-prove n reliability of coal-fired EGUs as the preferred method of power generation.

Commenters stated that given the system requirement s that must be met in order to maintain reliability, even the seemingly simple decision to close a single fossil base load unit and replace it with a renewable generator requires consideratio n of, at least, the availability of sufficient generation to meet demand, the need for ramping and back-up power, the availability of natural gas supplies and the infrastructure to deliver it, the impact on the transmission system and the need to maintain inertia, frequency and voltage con trol, and that choosing to increase the generation at an existing unit that already is inte rconnected to the transmission system requires
consideration of similar issues. Commenters indicat ed that managing these considerations requires a significant amount of rigorous and time- intensive study and coordination - any addition or change to the transmission system has t o go through the interconnection study and analysis process, whether the change is to the capa city of an existing generator or a new generator is proposed. Commenters described the req uired studies as follows: "The purpose of these studies is to assess the impact of a new gene rating unit (or increase in generation from an existing unit) on the existing transmission system. The required studies consist of thermal analyses, stability studies and assessments of poss ible faults in the system that could result in14

cascading failure of the transmission system. No ge nerator can be attached to the transmission
network unless and until these studies show that th e system can withstand the injection of energy at that particular point. However, these studies on ly determine whether the system will be harmed by adding the generator or increasing capaci ty. An additional study, generally referred to as a "simultaneous feasibility study," must be done to determine whether the electricity actually can be moved from the point of production to other points on the transmission system. The results of this study determine whether transmissio n upgrades or expansions are needed to accommodate the increased generation." Commenters n oted that MISO's Generator Interconnection Procedures describe these required studies in more detail.

Commenters stated the EPA did not consider market c hallenges associated with additional integration of the natural gas and electric markets . Commenters stated that, as reliance on natural gas to generate electricity has increased, the NERC has undertaken a series of studies to examine potential impacts of this increased reliance. Comme nters stated that, in evaluating the impacts of increased reliance on the natural gas and electrici ty market, NERC highlights issues associated with the "planning gap," the period of time in whic h natural gas delivery needs to be scheduled before a power plant owner or operator knows the ex tent to which it will be dispatched. Commenters stated NERC noted that incre ased reliance on natural gas for electricity generation merits increased coordination to address some of the issues associated with this "planning gap." Commenters stated that when the EPA assumed that natural gas fired power plants could dispatch at 70 percent capacity factor s in order to set state based emissions targets, it is not apparent that the Agency considered this cha llenge which the NERC has identified.

Timing

Commenters suggested the EPA did not adequately con sider the time needed to implement the CPP, including new infrastructure.

Commenters stated the Proposed Rule does not allow sufficient time to replace generation capacity that is expected to be retired. Commenters anticipated that the Proposed Rule would require the retirement of approximately 11 gigawatt s of generation capacity in or around 2020. Commenters stated that, to avoid reliability and re source adequacy issues, this generation would need to be replaced in a timely manner. Commenters asserted that it is essential that the Agency assess whether the natural gas industry can support the level of increased NGCC utilization contemplated by the proposed guidelines both prior to and during the interim compliance period.
Commenters indicated that the increased demand for gas pipelines can be addressed with sufficient lead time (i.e., more than three years), which is needed to plan, collect contracts, permit, procure, and build new pipeline.

Commenters stated that the EPA failed to take into account other infrastructure issues in developing Building Block 2, noting that the SPP's analysis of the Proposed Guidelines indicated that unless the required generation and infrastruct ure is built, to respond to the Proposed Guidelines' tight time frame and changing generatio n mix the SPP region will face a significant loss in load and violations of reliability standard s. Commenters stated under the Proposed Guidelines SPP's anticipated reserve margin would b e 4.7 percent, representing a reserve-margin deficit of almost 4,600 MW in 2020 and an additiona l deficiency of 10,000 MW by 2024 Commenters indicated that given the 8 to 10 year ti me frame needed to design, permit and15

construct these additional generation and transmiss ion resources, SPP has concluded there is not a sufficient amount of time to achieve compliance w ith the Proposed Guidelines' Interim Goals and that widespread reliability impacts are likely. Commenters stated that a Bloomberg Government report illustrated the severe transmissi on bottlenecks facing New York. Commenters stated that in 2012 the average day-ahea d power prices in New York City (Zone J) were more than $10 per megawatt-hour higher than pr ices in western New York (Zone A); with fewer transmission bottlenecks, more economic (and lower-emitting) natural gas plants located in Zone A could have displaced less efficient power plants in Zone J. Commenters indicated that the EPA's Building Block 2 methodology assumes, not only in New York but in other parts of the country, that ramped-up utilization of NGCC fac ilities can easily transmit power to displace coal-fired capacity elsewhere in the state - but cu rrent experience in New York indicates that this is not necessarily true. Commenters asserted that t he EPA did not consider these possible
transmission constraints.

Commenters stated Southwest Power Pool (SPP) studie s have shown that the EPA's schedule of proposed unit retirements will have severe impacts on system reliability. Commenters stated that, in a November 2014 "Analysis of EPA's Proposal to R educe CO2 Emission from Existing Electric Generating Units" report, Midcontinent Ind ependent System Operator, Inc. (MISO)

states:

MISO's review also indicates that the interim targe ts in the proposed rule will require significant CO2 reductions in the 2020 timeframe. This study in dicates that this short timeline may not allow cost-effective, long-term planning. If coal p lant retirements are part of the compliance strategy for 2020, corresponding capacity additions (for reliability and resource adequacy) in a two-year window will be difficult if not impossible . MISO's experience is that new gas plant construction typically requires three to six years. If new transmission and gas pipeline additions are needed to accommodate the capacity expansion, t his timeline may be even longer. This finding suggest that in order to meet the 10-year a verage identified in the proposed rule, it is likely that entities will need to take immediate ac tion. Since it is possible that state plans will no t be finalized until the 2018-19 timeframe, there wil l be little time for decisions and implementation for infrastructure changes before 20 20.

Commenters stated the potential reliability issues of the CPP are being largely overlooked by EPA because the proposal does not consider the coor dination of transmission line and gas pipeline infrastructure needed to make the interim targets achievable. Commenters stated that expanding the gas pipelines and/or transmission pow er line infrastructure to accommodate new renewables and NGCC to replace coal requires extens ive amounts of time to study, permit and construct. Commenters stated it often takes provide rs in our region up to a decade to plan, permit and construct major extra high voltage (EHV) transm ission projects, obviously not aligning with the interim time period and barely complying with t he final goal. Commenters stated the CPP's interim goals do not allow the time required to per mit and construct the necessary infrastructure for this shift. Commenters stated that, in the majo rity of instances, siting NGCC at existing coal generation sites is not possible without the develo pment of new or the extension of existing natural gas pipelines. Commenters stated that, curr ently, it is potentially feasible to site the occasional new NGCC plant along existing pipelines at the intersections of, or in close proximity to, transmission power lines; however, as more NGCC comes online to comply with the CPP, these new NGCC facilities will quickly diminish exi sting pipeline and/or transmission capacity.16

Transmission Reliability

Commenters suggested the EPA did not adequately con sider the transmission resources needed to implement the CPP.

Commenters stated the changes in the utilization of the various generating plants driven by this proposal could have a significant impact on transmi ssion reliability due to potential large changes in power flows across the system and retire ment of generation that contributes to transmission system voltage and frequency performan ce. Commenters stated that the change in generation will almost certainly require developmen t of new transmission to ensure operational reliability, but scheduling outages of existing fac ilities will be difficult if simultaneous upgrades across many systems are needed such that time lines for commissioning of new transmission facilities may be delayed. Commenters asserted that to understand the full reliability, economic, and financial impacts of the proposed rule, detaile d transmission reliability evaluations should be conducted. Commenters stated that the proposed rule considers only the resource adequacy perspective with regard to potential electric syste m reliability impacts and does not address the potential thermal, voltage, and frequency impacts, nor does the proposed rule consider the associated potential transmission economic implicat ions of additional facilities required to ensure operational reliability or financial implications o f stranded transmission investments that become underutilized. Commenters encouraged the EPA to con duct detailed transmission reliability evaluations to understand the full reliability, eco nomic, and financial impacts of the proposed
rule.

Commenters expressed concern that the proposed re-d ispatch of coal generation to NGCC shifts power generation geographically across the state fr om eastern Arizona to primarily Maricopa County in west central Arizona. Commenters stated s uch a significant relocation of power resources leads to a concentration of generation re sources in one area raising reliability issues and creating large infrastructure needs in a nonatt ainment area to accommodate the shift in generation.

Commenters expressed concerned that the EPA's propo sal does not identify the consequences on Florida's electric service reliability, transmissio n load flow, or the scheduling of how its program of displacing existing coal-fired baseload faciliti es could reasonably be implemented. Commenters noted that Florida's coal- fired facilities and NGCC facilities are not typically co-located nor generally located within t he same utility system, and that in Florida, the existing transmission system has not been developed with the expectation that NGCC facilities would displace all or most of the baseload coal-fir ed facilities. Consequently, commenters believed that it would be necessary to conduct a Fl orida-specific transmission study to assess the full effects of such a program, which the EPA does not appear to have included in its reference material or factored into the proposed compliance s chedule. Commenters stated that the EPA's NODA appears to acknowledge these are significant a nd material issues, but no changes to the Proposed Rule were presented. Commenters indicated that while the EPA has assumed future wholesale level transactions between reliability re gions, it has not provided the commenters with any support documentation of electric reliability w ithin the Florida Reliability Coordinating Council region and the potential impacts to each of the Florida cooperative, municipal, and investor-owned systems. Absent this type of data, c ommenters stated they do not believe that electric reliability will be maintained if the Prop osed Rule is implemented.17

Comment 5: Commenters stated that, while existing oil/gas-fir ed steam EGUs located in New York City are necessary to comply with four mandato ry local reliability rules, the CPP would require reducing the output of New York's coal, oil , and oil/gas-fired steam EGUs to an extent that would undermine their economically viability a nd potentially lead them to retire.

Response 5: The EPA disagrees. In response to additional analys is and many comments, we have modified the proposal and RIA. The 111(d) fina l rule requires that states develop plans that
establish emission standards for affected EGUs. We are providing states with substantial flexibility as to how they structure those plans to achieve the 111(d) requirements. The flexibility includes, for example, the choice of approaches, tr ading, time to develop plans, additional time before the start of the interim performance period (postponed from 2020 until 2022), and the ability to shift emission rate achievement between performance periods. The Building Blocks are not prescriptive, and states may consider local cir cumstances as they develop their plans, including system reliability, fuel diversity, other regulatory requirements and infrastructure. See sections V.D, VIII.A, VIII.C and VIII.G of the fina l rule preamble of the CPP and Chapter 3 of the GHG Mitigation Measures TSD for the CPP Final R ule supporting the final CPP.

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

Commenters stated that New York City depends on its oil/gas steam facilities, which make up the majority of in-city generation, to comply with several reliability rules specific to New York City and that coal, oil, and oil/gas-fired steam ge neration also provides valuable fuel diversity to
the state as a whole. Commenters stated that existi ng oil/gas-fired steam EGUs located in New York City are necessary to comply with four mandato ry local reliability rules and provided the following additional information regarding these re liability rules and impacts:

These rules are designed to protect against the los s of electric load in the event that there is an interruption in the natural gas supply fueling gene rators in New York City or a forced outage on a transmission or generation facility serving this highly constrained area. Sufficient generation must be immediately available within New York City to ensure continued electric service to
customers located there. The first local reliabilit y rule - Minimum Oil Burn - supported by gas tariffs and interconnection requirements for New Yo rk City - protects the electric system from
sudden loss of electric load in the event that the local gas delivery system is unable to serve all of the generators that rely on it by requiring that ce rtain units maintain alternate fuel capability. To prevent such a loss of electric load, these dual-fu eled facilities are required either to run on oil o r to enable their auto-swap capability under certain conditions in order to maintain generation supply should the gas supply be interrupted. The ot her three local reliability rules - Thunderstorm Alert, Second Contingency Unit Commitm ent and Locational Operating Reserves - protect against loss of electric load in the even t that an electric transmission facility or generation facility serving New York City is sudden ly forced out of service. These rules require the dispatch of generation located inside New York City to ensure reliability. In 2012, there were 347 days when at least one of these reliability rul es was invoked in the New York City area, requiring the operation of oil/gas-fired steam EGUs . The 99% reduction in the operation of New York City's oil/gas steam facilities necessitated b y Building Block 2 would make it impossible to comply with the local reliability rules described a bove and would undermine reliability in New18

York City. Dual-fuel generation also provides valua ble diversity in New York's generating fleet, which is dominated by natural gas burning units. Hi gh consumer demand for natural gas during periods of extreme cold weather over a large portio n of the country can reduce the availability of natural gas for generation plants. Maintaining some diversity in the fuel supply of New York's generation fleet reduces exposure to this potential scarcity and helps avoid interruptions in electric generation when natural gas availability i s disrupted. This was vividly demonstrated during this past winter's polar vortex when severe and sustained cold weather threatened natural gas supplies to generators. Increased demand on New York's natural gas transmission infrastructure resulted in fuel interruptions to ga s-fired EGUs when gas was redirected to higher priority uses such as home heating. New York's oil/ gas-fired steam units generated over 2,000 GWh while burning oil fuel during the polar vortex, demonstrating the importance of these resources to reliability. Oil-fired generation was used to maintain reliable electric service to New York City during a total of 161 days last year. The EPA needs to ensure that its final goal for New York recognizes the significance of dual-fuel u nits to reliability and allows for them to run on oil when necessary because circumstances limit t he availability of natural gas as a generation
fuel.

Comment 6: Commenters expressed concerns with the EPA's approa ch in Building Block 2 regarding removal of coal plants, including fuel diversity, reliability, and stranded costs.

Response 6: The EPA disagrees. In response to additional analys is and many comments, we have modified the proposal and RIA – the establishm ent of CO2 emission reduction standards is regionally based. The 111(d) final rule requires th at states develop plans that establish emission standards for affected EGUs. We are providing state s with substantial flexibility as to how they structure those plans to achieve the 111(d) require ments. The flexibility includes, for example, the choice of approaches, trading, time to develop plans, additional time before the start of the interim performance period (postponed from 2020 unt il 2022), and the ability to shift emission rate achievement between performance periods. The B uilding Blocks are not prescriptive, and states may consider local circumstances as they dev elop their plans, including system reliability, fuel diversity, infrastructure, and the “useful lif e” of generating assets. See sections V.D, VIII.A, VIII.C and VIII.G of the final rule preamble of the CPP and Chapter 3 of the GHG Mitigation Measures TSD for the CPP Final Rule supporting the final CPP.

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

General

Commenters stated that re-dispatching the bulk of t he existing coal fleet to natural gas generation must be done judiciously given that gas-fired gener ation is still a significant GHG emitter, and given the uncertain future of natural gas availabil ity and price volatility. Commenters stated there is not enough existing NGCC in this country, and in Indiana particularly, to make up for the forced reductions in coal generation. Commenters ur ged the EPA to reconsider the proposed rules which removes an abundant, and widely utilize d nature resource from the nation's energy19

mix in such a dramatic and expeditious fashion, the reby hindering the reemergence of manufacturing in the nation's heartland and moving carbon emissions to global competitors with less pollution controls.

Fuel Diversity

Commenters stated that a balanced approach to fuel diversity is necessary to maintain reliability and affordability. Commenters stated that their cur rent generation mix provides the Orlando Utilities Commission (OUC) with the ability to swit ch between coal and natural gas as needed based on the market price conditions, fuel supply c hallenges and extreme weather. Commenters noted that, once the operation of gas transportatio n facilities in the Gulf Coast are suspended due to a named storm, it takes time to get them back to full operation and having a coal supply on site allows OUC to provide energy for their customers.

Commenters expressed concern that the proposed rule would remove coal EGU's from the electrical generation portfolio in Nevada and relie s totally on NGCC for base load power. Commenters stated this is contrary to PUC goals, wh ich seek portfolio diversity in order to maintain relative price stability in electrical mar kets and mitigate the potential for fuel supply disruptions. Commenters noted that coal units have the ability to stockpile fuel on site, whereas natural gas units receive their fuel through pipeli nes and are therefore vulnerable to pipeline disruptions. Commenters stated the FERC reported th at, during last winter's cold weather, numerous natural gas generators were forced to ceas e generation because of interruptions in pipeline deliveries, both because of the physical i nability of frozen pipelines to deliver natural gas and because suppliers cut off interruptible loa d to serve other load under much higher spot prices. Commenters stated the EPA failed to conside r these real and negative consequences in determining that every state's "best" utility syste m should entail the wholesale substitution of natural gas for coal.

Commenters stated that NERC has determined that the CPP will cause a generation shortage. Commenters stated that natural gas units are best s uited to follow load, rather than serve as base load units. Commenters stated that employing divers e fuel sources (coal-fired in addition to NGCC and renewables, when available) ensures a secu re and reliable energy supply.
Commenters stated that reduced reliance on coal-fir ed power, combined with increased reliance on NGCC, will decrease diversification of fuel sour ces which will constrain the power grid's ability to respond to unforeseen events such as reg ional transfers, labor strikes, unplanned outages and abnormal weather conditions. Commenters noted that, during the 2014 polar vorte x the following fuel delivery complications were enco untered: (1) natural gas interruptions (supply injection, compressor outages, and one pipeline exp losion); (2) oil delivery problems; (3) inability to procedure gas; and (4) fuel oil gellin g. Commenters stated that low temperatures during the polar vortex hindered power generation i n the following ways: (1) low temperature limits for wind turbines; (2) icing on hydro units; (3) failed auxiliary equipment; (4) stress of extended run times; and (5) frozen instrumentation.

Reliability

Commenters stated the EPA should not presume that c oal units can be retired or curtailed in favor of increased natural gas generation because c oal generation and natural gas generation20

serve different functions, with coal units required to ensure grid stability. Commenters stated that coal and natural gas generation are not interchange able such that each kWh of increased natural gas generation replaces on kWh of coal generation.

Commenters referred to the EPA's IPM run results an d stated the Proposed Rule would effectively eliminate coal-fired generation from Po werSouth's generation portfolio. Commenters stated this has long-term implications, including i mpacts to PowerSouth's ability to provide
reliable and affordable service to its members. Com menters stated the EPA cannot systematically phase out coal-fired EGUs. Commenters explained tha t, if external factors affect natural gas delivery, PowerSouth can rely on the coal resources in its fleet to meet demand. Commenters stated the ability to choose from a suite of fuel o ptions during resource planning retains fleet flexibility and reliability, and also ensures that economic and efficient electricity is provided to
our members. Commenters stated the additional basel oad generation capacity projected to retire
due to the Clean Power Plan would increase the risk s of brownouts, load curtailments, and other power disruptions in regions impacted by these reti rements. Commenters stated the EPA should be promoting, not destroying, projects that create an abundance of reliable and affordable electric generating capacity for our nation's seniors.

Commenters stated the shift to NGCC will eliminate stability in the energy market because gasfired technology is not as mature and reliable as c oal-fired generation. Commenters noted that, should a coal-fired unit experience a forced outage , generally speaking, it will be a 3 to 5 day outage repaired by a local veteran work force. Comm enters stated that, if a natural gas-fired combustion turbine unit experiences a forced outage , it is likely a 3 to 5 month outage with many unexpected expenses and without the availability of a local veteran workforce. Commenters stated that, if the utility industry is expected to rely upon gas-fired combustion turbine technology, the industry will have to install twice as many units as anticipated by EPA and spare units will be necessary to ensure that sufficient e nergy can be generated at all times, particularly during prolonged maintenance outages.

Commenters stated that, as SPP delineates, there ar e significant reliability impacts resulting from
the forced closures and other modifications to base load generation output required in order to comply with the proposed Rule. Commenters stated th at, in addition, MISO addresses the fact that reserve margins (the cushion electric generati ng entities must have to avoid outages when unexpected events occur) will fall well below what is needed to support the regional electric grid. Commenters stated the EPA should be mindful of the fact that the Arkansas Electric Cooperative Corporation must comply with RTOs' mand ates, which are derivative of their FERC-jurisdictional authority and when the reliabil ity coordinators raise red flags, those warnings should be carefully considered.

Commenters cited a NERC report and stated that extr eme weather events highlight the need for adequate reserve margin and fuel diversity. Comment ers stated that many regions relied on coalfired generation, with a ready fuel supply stored o n site, for grid reliability during these conditions, while the Proposed Rule anticipates tha t many of these same units will be retired in
or around 2020.

State-Specific Concerns21

Commenters expressed concern that the combination o f Building Blocks 1 and 2 in New York results in a scenario where certain reliability-mus t- run coal-fired units would be constrained to only several days of operating time each year and, as a result, these plants would be forced to close as the economic viability of the operation wo uld erode to unsustainable levels. Commenters stated that the complete eradication of coal-fired units from New York's fleet presents concerns related to fuel diversity and rel iability. Commenters stated that coal remains a viable option for grid operators to mitigate unexpe cted natural gas contingencies: it can be stored on-site and units can be operated to follow load va riations, unlike nuclear which is much less
flexible.

Commenters noted that in the EPA's goal setting met hodology for Building Block 2 under Option 1, it essentially retires all coal capacity in 11 states (Alaska, Arizona, California, Connecticut, Massachusetts, Mississippi, Nevada, Ne w Hampshire, New Jersey, Oregon and Washington) and replaces that generation with exist ing NGCC. Commenters stated two of these states (Oregon and Washington) have announced the r etirements of their entire coal-fired capacity as a result of various state agreements, b ut the remaining nine states have only announced the retirement of some of their existing coal capacity and have plans to keep their remaining coal fleet operating into the future. Com menters stated that the EPA's calculated requirements show a disconnect between the operatio nal reality of the U.S. electric system and the Agency's assumptions. Commenters stated that th e EPA's parsed IPM modeling files projecting compliance with the Option 1 state goals in 2025 under a state-based approach indicate that coal-fired capacity is required to me et demand in Arizona, Massachusetts, Mississippi, Nevada, and New Jersey.

Commenters expressed concern that there is a discon nect between EPA's assumptions related to NGCC re-dispatch in Building Block 2, and the EPA's modeling of state compliance with Option 1 goals. As an example, the commenters noted that t he EPA's Building Block 2 calculations displace (retire) all of Arizona's existing coal-fi red capacity; however, IPM's 2025 results for Option 1 under a state approach indicate that Sprin gerville Units 1 through 4 will be needed to generate 5,653 GWh of electricity, which is equival ent to 23.2 percent of the state's 2012 coalfired generation. Commenters asserted that, in assu ming a state can shift all of its coal-fired generation to its NGCC units without taking into ac count the reliability needs of specific electricity markets, the EPA shows a lack of unders tanding of how electric utilities plan and operate to meet electric demand and ensure reliabil ity of the grid. Commenters stated that even more coal capacity would be needed if EPA had prope rly applied summer capacity (as opposed to nameplate capacity) for NGCC.

Commenters expressed concern that, with the re-disp atch of NGCC to a 70% capacity factor combined with the unobtainable RE and EE targets in cluded in the calculation of Mississippi's CO2 goal, it is very likely that under the EPA's ru le as proposed, SMEPA's coal fired generating facility, Plant Morrow, will be forced into early r etirement. Commenters also expressed concern over the impact the Clean Power Plan will have on t he Plum Point Energy Station which is a coal fired generating plant located in Oscelola, Arkansa s. Commenters referred to Attachment A to their comments which express some of these concerns

.

Stranded Investments22

Commenters stated that, to preserve the investment Georgians have made and avoid stranded costs, EPA should remove from its calculations of t he state goal the assumption that all existing NGCC units statewide can be ramped up to a 70% capa city factor. Commenters stated that the draft rule summarily discards billions of dollars i n investment Georgians have made in state-ofthe-art emissions controls on coal-fired units. Whi le the Georgia Public Service Commission has already approved the retirement of approximately 30 00 megawatts of generation, EPA's proposal assumes that Georgia will retire another 3900 megaw atts of coal-fired generation in response to this rule, thereby stranding the investment in thos e generating units, including billions of dollars'
worth of environmental controls.

Commenters stated that implementation of the propos ed re-dispatching would require premature closure of Mississippi's remaining coal fleet, even though many of these units have taken recent steps to comply with the MATS rule by spending mill ions of dollars in control retrofits. Commenters stated that full implementation of Build ing Block 2 is not an option for these units because it would cause these upgrades to become str anded assets to the rate payers of Mississippi. Commenters stated that, under the prop osed application of Building Block 2, Mississippi would completely lose its fuel diversit y with a projected zero coal and oil/gas steam power generation by 2020, which is an unacceptable result. Commenters stated that removing fuel diversity jeopardizes power reliability and re moves the ability to control power costs for consumers. Commenters requested that the impact of Building Block 2 on Mississippi's proposed goal align with the stated intent of the proposed r ule, which is to reduce carbon emissions "while maintaining an affordable, reliable, and diverse en ergy mix". Commenters suggested the EPA consider evaluating the state's fuel usage profile for an acceptable level of natural gas usage prior to determining whether re-dispatching is even neces sary. Commenters noted that, in 2012, Mississippi's NGCC generation provided for 73% of t he total generation from its affected fossil fuel-fired EGU's and stated that this percentage ra te is more than sufficient to satisfy an acceptable NGCC generation requirement while still affording the state the opportunity to utilize a diverse energy mix. Commenters stated that re-dis patching to NGCC capacity for the Mississippi fleet does not consider the intended ut ilization of the units. Commenters stated that many of Mississippi's units were not designed or in cluded in the power system to provide extended power generation. Commenters stated that m any of these units were designed to chase peak demand and a detailed assessment of unit utili zation would need to occur before many of the units could be committed to a high-use re-dispa tch plan.

Commenters stated that, while implementing Building Block 2 threatens to prematurely close several of OG&E's coal-fired EGUs by requiring grea ter utilization of existing NGCCs, EPA's NODA proposes modifications to the CPP that would a lmost certainly lead to closures.
Commenters stated these measures contravene Section 111(d) by forcing displacement of coalfired EGUs with significant remaining useful lives. Commenters stated section 111(d) requires EPA to take into account the remaining useful lives of the sources it regulates. Commenters stated that, despite this provision, EPA did not as sess the remaining useful lives of OG&E's and others' coal-fired EGUs that are poised for closure under the Proposed Rule. Commenters stated shutting down OG&E's coal-fired EGUs will cause unt old damage to local communities, including job losses at OG&E facilities and elsewhe re in the supply chain, stranded investments,
and reductions in revenue. Commenters stated the ab ruptness of the transition risks destabilizing energy production and threatens reliability. Commen ters stated this scenario can and should be avoided, particularly since OG&E realizes the value of a diverse portfolio of electricity23

generation methods and has taken a leadership role across Oklahoma by pioneering utilization of NGCCs. Commenters expressed concerns regarding unin tended consequences sure to flow from the imposition of an arbitrarily high and hastily i mposed shift from coal-fired to natural gas-fired generation.

Commenters stated the EPA has not considered that r e-dispatching may leave some generating entities with stranded investments because, as EPA' s own modeling shows, many coal units will shut down due to re-dispatch. Commenters stated mos t coal units would be uneconomical to run as peaking units and nearby NGCC units would likely be unable to fully replace coal generation during high-demand periods; in most balancing areas , both coal and NGCC units must be dispatched during such periods, and retirements res ulting from re-dispatch could result in inadequate generation capacity during peak load per iods.

Commenters supported the modifications proposed by the Arizona Utilities Group (AUG). Commenters stated the AUG proposal requests EPA con sider the remaining useful life and asset value of Arizona's coal plants, together with lower ing CO2 emissions to achieve meaningful long-term reductions. Commenters stated the AUG pro posal would mitigate the sharp cliff projected under the EPA interim goal for the State, thus providing a smoother glide path for emission reductions. Finally, AUG's proposal would also lower the cost burden to be borne by

consumers.

Commenters stated that, because South Dakota has on ly a single natural gas generation plant - the Deer Creek Station, which is owned by Basin Ele ctric Power Cooperative, the Deer Creek Station would need to operate at greater than 70% c apacity, a level it was not designed for, to offset the loss of power from reductions at coal-fi red power plants. Commenters stated the redispatch of Deer Creek Station to a level of 70% ca pacity would in tum result in a dispatch of
South Dakota's lone coal-fired EGU to a level of 23 %, a wholly unreasonable and uneconomic
level for a baseload coal unit.

Commenters expressed concern that, in projecting a non-economic dispatch of natural gas EGUs to become baseload generation, the EPA's models hav e failed to recognize that coal plants idled are no longer likely to be economic and will be for ced to retire - many prematurely - leaving the US with a huge national electric generation reserve deficit. Commenters stated coal plants will close not only because they are not dispatched but also because their economics were based on baseload, high capacity factor operation and transi tioning these plants to mezzanine or peak period units results in insufficient revenues to ca rry the staff and fixed costs that baseload coal plant must maintain to remain viable.

Comment 7: Commenters stated that the EPA has not considered t he role of NGCCs in an integrated electric system. Commenters noted that u tilities provide ancillary services to balancing areas to ensure reliability and availability of ele ctricity to customers, which include scheduling, system control, and dispatch; reactive supply and v oltage control; regulation and frequency response; energy imbalance; operating reserves; and supplemental reserves.

Response 7: The EPA disagrees that we have not considered the p rovision of ancillary services. In response to additional analysis and ma ny comments, we have modified the proposal

and RIA – the establishment of CO2 emission reducti on standards is regionally based. The24

111(d) final rule requires that states develop plan s that establish emission standards for affected EGUs. We are providing states with substantial flex ibility as to how they structure those plans to achieve the 111(d) requirements. The flexibility in cludes, for example, the choice of approaches, trading, time to develop plans, additional time bef ore the start of the interim performance period (postponed from 2020 until 2022), and the ability t o shift emission rate achievement between performance periods. The Building Blocks are not pr escriptive, and states may consider local circumstances as they develop their plans, includin g system reliability, fuel diversity, the need for “ancillary services” and other regulatory requi rements. See sections V.D, VIII.A, VIII.C and VIII.G of the final rule preamble of the CPP and Ch apter 3 of the GHG Mitigation Measures TSD for the CPP Final Rule supporting the final CPP

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

Must-Run Requirements

Commenters stated that re-dispatch of NGCC resource s may also interfere with NERC compliance requirements regarding capacity reserves , spinning reserves and similar requirements. Commenters stated that the EPA cannot presume that certain coal units can be
retired or curtailed in favor of increased natural gas generation because coal generation and natural gas generation serve different functions. C ommenters stated that coal generators serve an important function in providing local reliability s upport, including black start capabilities (the ability to restart without any electrical input), v oltage stability, and other ancillary services. Commenters stated that, as a result, certain coal f acilities may be "reliability must run" units which cannot be retired without imperiling local gr id reliability. Commenters cited a Western Electricity Coordinating Council study (2022 Resour ce Options, July 25, 2013, p. 51): "The path rating for Path 8 [the Montana to Pacific Northwest corridor] is currently highly dependent on remedial action schemes that are directly linked wi th the coal-fired and hydro generation in
Montana. There are inertial concerns in the area. T he local balancing authorities have advised caution when running studies that dispatch renewabl e generation before coal-fired and hydro generation. In reality, the rating on Path 8 may ha ve to be decreased when these conventional resources are backed down, or turned off completely ."

Non-Generation Services

Commenters stated that units located in New York Ci ty are required to run in order to provide needed voltage support and frequency stability in t his heavily-populated urban center. Commenters stated that, while unit upgrades and re- powering with natural gas have dramatically improved the emissions profile of in-city-generatio n over the past decade, the system cannot maintain stability and reliability without these ke y resources.

Commenters stated the EPA ignores non-generation ro les that certain power plants serve, as black start capability and voltage support, often d ependent on coal power plants. Commenters stated it is arbitrary and unreasonable for EPA to ignore these factors when making assumptions about the displacement of coal generation. Commente rs stated the EPA's proposal assumes that electricity generation is completely fungible and t hat NGCC facilities can substitute completely for coal-fired electric generating units (EGUs). Co mmenters stated this approach ignores the non-generating services that coal-fired EGUs provid e to the electricity generation and25

transmission sectors. Commenters stated that coal-f ired EGUs may be located strategically to provide voltage support and other grid reliability benefits and that existing and under
construction NGCC facilities at other locations can not replace these functions. Commenters stated that certain coal-fired EGUs may be designat ed as black start facilities that are capable of restarting without any electricity input or for oth er reasons may be designated as must run facilities by FERC or regional transmission organiz ation (RTOs). Commenters stated these coalfired EGUs cannot be retired and replaced by existi ng or under construction NGCCs. Commenters stated that, because electricity generat ion is not truly fungible, there may be circumstances where coal generation is necessary, e ven if NGCC facilities are operated at 70 percent capacity. Commenters stated this is particu larly true in States where EPA's BSER analysis projects that coal-fired generation will c ease entirely.

Commenters stated that it is important to note that all generating resources do not provide the same services to the electric grid and that all ele ctrons may not be able to serve all customers due
to electric transmission or other constraints - dif ferent sources are needed to ensure that electrons actually reach end-users. Commenters indicated that while all generating units produce electricity, some types of units only supply energy , others supply critical grid services (balancing, back-up and ancillary services like vol tage and frequency control) that are needed to ensure the stability of the transmission system and other types provide capacity to ensure resource adequacy and reliability. Commenters added that renewable generation units can provide electrons, but are limited in their ability to provide grid or peak period capacity services.
Commenters asserted that retirement of base load co al-based units diminishes the pool of resources that are able to provide these other serv ices to the grid and places increased responsibility on natural gas based resources to se rve as base load units, back up renewable resources, provide ramping capability and provide a ncillary services to the grid.

Commenters stated that adequate transmission and ge neration infrastructure, as well as other essential services, are critical for the reliable o peration of the integrated grid, and that system operators do not have complete flexibility in the p rocurement of these services, many of which are often referred to as "ancillary services," as t hey often need to be provided by units in specific locations due to the physics of electricity. Commen ters noted that reactive power, for example, does not "travel" over distances and is, therefore, a "local" requirement that can be provided only by a few resources when needed. Commenters indicate d that FERC recognizes the following as ancillary services: scheduling, system control and dispatch; reactive supply and voltage control from generation service; regulation and frequency r esponse service; generation and energy imbalance service; operating reserve - synchronized reserve service; and operating reserve - supplemental reserve service (Order Nos. 888, 890). According to the commenters, under FPA sections 205 and 206 all public utilities that own, control or operate facilities used for transmitting electric energy in interstate commerce are required to take transmission service, including these ancillary services, for wholesale s ales and purchases of electric energy under open access tariffs. (Commenters added that black s tart service, an additional ancillary service, is a voluntary service that can be provided by some, b ut not all, generation resources. These generating units have the ability to go from a shut down condition to an operating condition and start delivering power without any outside assistan ce from the electric grid. Hydroelectric facilities and diesel generators have this capabili ty. These are the first facilities to be started up in the event of a system collapse or blackout to resto re power flows in the grid. See FERC Primer at 37.) Commenters stated that ancillary services, in addition to capacity and energy, are necessary26

to support the transmission of electric power from seller to purchaser, given the obligations of control areas and transmitting utilities within tho se control areas, to maintain reliable operations of the interconnected transmission system, and that ancillary services are so essential that FERC also requires that transmission service providers - absent third-party service - provide them to ensure the reliable delivery of electricity.

Commenters added that natural gas units are vulnera ble to pipeline disruptions while coal units have the ability to stockpile fuel on site. Comment ers stated that the EPA failed to consider these real and negative consequences in determining that every state's "best" utility system should entail the wholesale substitution of natural gas fo r coal. Commenters referred to an April 1, 2014 FERC report regarding last winter's cold weather du ring which numerous natural gas generators were forced to cease generation because of interrup tions in pipeline deliveries, both because of the physical inability of frozen pipelines to deliv er natural gas and because suppliers cut off interruptible load to serve other load under much h igher spot prices.

Commenters also expressed concern that the EPA's ca lculation of each state's best system fails to account for fuel-pricing stability. Commenters prov ided a chart (showing the price of coal and natural gas per million Btu from 2001 to 2013) and stated that, based on EIA data, coal prices have historically been low and stable, whereas natu ral gas prices have been volatile.

Ramping and Regulation

Commenters stated that NGCCs are often necessarily utilized for ramping (Scheduling, System Control, and Dispatch) and regulation (Regulation a nd Frequency Response) to maintain reliability and availability of electricity. Accord ing to the commenters, any constraint on NGCCs' operation flexibility, such as proposed by E PA in Building Block 2, hinders these units' ability to serve their historic purpose, thus impac ting reliability. Commenters explained that "ramping" is a load following requirement and requi res units to generate more or less as the system load or demand requirement progresses throug hout the day, while "regulation" relies upon faster generating resources that respond to sy stem demand changes from minute to minute (or even shorter durations). Commenters noted that utilities minimize cost to consumers while still meeting ramping and regulation requirements, and that what type of unit meets ancillary service demands depends on factors such as system d emand, a unit's cost, a unit's ability to respond to ramping and regulation needs, and the sy stem's capacity mix. Commenters added that depending on the time of the year, different unit m ixes may be committed to meet expected demand shapes while still providing capacity to mee t ramping and regulation needs, and that the system load shape often dictates the type of resour ces that will be committed to serve load. Commenters provided a figure with examples of seaso nal load shapes over a 24-hour period for the winter, spring/fall, and summer seasons.

Commenters described the differences between the ty pical load shapes in winter (a double peak and a mid-day valley) and summer (a more uniform lo ad shape, peaking in the afternoon) in the Southern Company footprint, and noted that a winter month's ramping and regulation requirements can be quite different than a summer m onth's requirements. Commenters described the different roles that NGCCs may play during wint er and summer days, and noted that outside of energy limited resources, such as hydroelectric power, NGCCs are the more flexible resources in that they can operate over a variety of operatin g states (e.g., 1x1, 2x1, Full Pressure, Power27

Augmentation) with minimum up and down times of app roximately 8 hours. Commenters stated that it is not uncommon for NGCCs to operate at low er output levels to ensure that a unit is available to meet the system's ramping or regulatio n needs and in addition, as system demand reaches a minimum level during a given time period, the ability of NGCCs to reduce output further (turndown) is valuable. Commenters added th at because NGCCs serve several different roles over the course of a year, they may maintain different capacity factors across the seasons. Commenters indicated that historically, NGCC's have run at higher capacity factors during the summer, but it is important that these units mainta in operational flexibility throughout the year to assist in meeting load. Commenters provided figures illustrating NGCC quick cold startup capability compared to typical coal-fired EGUs; the contribution to total load by various power generation sources over the course of a 24-hour day in summer; the contribution to total load by various power generation sources over the course of a 24-hour day in winter; and the capacity factor for NGCC units in summer, transitional seaso ns, and winter.

Commenters stated that requiring NGCCs to generate at a 70 percent capacity factor, despite system economics, will hinder system operations bec ause NGCCs would not be available to provide critical regulation, ramping, and turndown needs for system reliability. Commenters indicated that other units would need to perform th ese duties - impacting system reliability and generation costs. According to the commenters, the EPA modelers recognize the turndown constraints of other technologies (e.g., coal and o il/gas steam) in that the EPA's IPM Base Case v.5.13 maintains turndown limitations to "prevent c oal and oil/gas steam units from operating strictly as peaking units, which would be inconsist ent with their operating capabilities". Commenters also indicated that within IPM, the Agen cy states that the "[t]urndown constraints often override the dispatch order that would result based purely on the variable cost of generation", and that the EPA states, "[T]he turndo wn constraints in EPA Base Case v.5.13 require coal steam units to dispatch no less than 5 0% of the unit capacity in the five base- and mid-load segments of the load duration curve [LDC] in order to dispatch 100% of the unit in the peak load segment of the LDC. Oil/gas steam units a re required to dispatch no less than 25% of the unit capacity in the five base- and mid-load se gments of the LDC in order to dispatch 100% of the unit capacity in the peak load segment of th e LDC".

Commenters also stated that almost all of Southern Company's NGCC fleet (excluding IGCC and CHP units) is Automatic Generation Control (AGC ) capable. Commenters indicated that maintaining AGC capability allows a unit to dynamic ally follow system demand in 10 minute time increments, which is necessary to serve regula tion and frequency requirements. Commenters added that NERC also requires minimum am ounts of regulation and contingency reserves to respond to unexpected system conditions and maintain system frequency - commonly referred to as Control Performance Standards 1 (CPS 1) and Control Performance Standards 2 (CPS2). Commenters asserted that NGCCs are an impor tant part of fulfilling these NERC requirements

Commenters stated that as unit pricing has changed over time, so have the types of units fulfilling system regulation needs. Commenters prov ided a figure showing a comparison between 3 years of the types of units regulating the Southe rn Company system (i.e., the units on AGC), which illustrates the relative percentages of regul ation performed by resource types. The commenters presented three pie charts, which show t he changes in percent utilization of various sources for AGC over the period from 2008 to 2012. Commenters asserted that as 23 percent of28

Southern Company's 2012 AGC resources close or tran sition to gas, Building Block 2's dispatch requirement that further limits units available for regulation becomes more problematic. Commenters stated that as demonstrated in the figur e, the units performing regulation requirements can change as fuel prices change. Comm enters indicated that NGCCs are being called upon more often to perform regulation and as additional coal-fired EGUs switch fuel or retire, NGCCs will be asked to perform even more re gulation. Commenters concluded that maintaining NGCCs' future flexibility is important to ensure regulation needs are met, and that operational limitations, such as EPA Building Block 2, will impede NGCCs from performing regulation.

Commenters stated the EPA fails to consider the rol e of NGCCs in an integrated electric system in asserting that states can set a standard based o n achieving a fleet-wide capacity factor of 70 percent. Commenters stated the NGCCs are frequently called upon to provide ancillary services because of their unique operational capabilities (e .g., high annual availability and quick ramping capability). Commenters explained that ancillary Se rvices commonly refer to services provided by the utility to help ensure reliability and avail ability of electricity to customers. These services may include: Scheduling, System Control, and Dispat ch; Reactive Supply and Voltage Control; Regulation and Frequency Response; Energy Imbalance ; Operating Reserves; and Supplemental
Reserves. 8 Commenters stated utilities provide ancillary serv ices to balancing areas on a moment's notice and NGCC is a necessary technology to meet these generation needs due to its reliability (i.e., high annual availability) and qu ick ramping capability. Commenters added that, even though an NGCC may frequently operate to meet ancillary services, this does not mean the unit is operating at a high capacity factor (e.g., 70 percent).

Commenters stated that it is not uncommon for NGCCs to operate at lower output levels in order ensure that a unit is available to meet the system' s ramping or regulation needs. Commenters stated that, as system demand reaches a minimum lev el during a given time period, the ability of NGCCs to reduce output further (turndown) is valuab le. Commenters stated that some NGCCs may cycle across the day while other NGCCs stay onl ine through a single ramp up and ramp down cycle. Commenters stated that expecting NGCCs to generate at a 70 percent capacity factor despite system economics and the need for an cillary services will unnecessarily complicate system operations at the least and impin ge on reliability at the worst; in those circumstances, NGCCs would not be available to prov ide critical regulation, ramping, and turndown needs for system reliability. Commenters s tated other units would need to perform these duties, thereby impacting reliability and gen eration costs; thus, any constraint on NGCCs' operation flexibility, such as proposed by EPA in B uilding Block 2, hinders these units' ability to serve their historic purpose. Commenters stated thi s reliability concern is exacerbated because emission reductions through the other building bloc ks are infeasible; therefore, NGCCs would likely be required to operate at an even higher cap acity factor to compensate for the lack of reductions possible under the other building blocks

.
Commenters stated NGCCs often are utilized for ramp ing needs (scheduling, system control, and dispatch) and regulation (regulation and frequency response). Commenters stated that ramping requires units to move up or down as load varies th roughout the day while regulation provides faster resources that respond to system demand chan ges minute to minute (or shorter duration). Commenters stated that employing a mandate of 70 pe rcent capacity factor for NGCCs could erode the ability to optimize around economics and ultimately this will drive up costs, while at29

the same time making it harder to meet ancillary se rvice requirements. Commenters stated that the CPP will effectively reduce a system's turndown (cycling) capability and increase the need for nimble ramping/regulation units by (1) adding m ore renewables, (2) removing coal units, and (3) hindering more nimble units' (NGCCs) ability to respond to the resulting system needs. Commenters stated these factors increase cost, redu ce reliability, and complicate system planning needs.

Safety-Valve

Commenters suggested the EPA should include "safety valves" to allow utilities to ramp up a coal facility, rather than increase natural gas gen eration, to address short-term conditions when dictated by reliability and safety. Commenters note d that in very cold winters, the price of natural gas spikes and, in addition, increased natu ral gas generation is dependent upon adequate pipeline capacity. Commenters stated that the relia bility safety-valve would be similar to the oneyear compliance extension used to avoid retirement- related reliability impacts due to MATS.
Commenters stated that there is no consensus as to what would trigger the safety-valve.
Commenters stated the EPA should allow states to in clude a safety valve in their state plans to address situations where the increased dispatch of NGCC units could affect reliability.

Comment 8: Commenters expressed concern that, as the industry relies more on natural-gasfired capacity to meet electricity needs, it is imp ortant to examine potential risks associated with increased dependence on a single fuel type.

Response 8: The EPA disagrees that we have inadequately consid ered these issues. The 111(d) final rule requires that states develop plans that establish emission standards for affected EGUs. We are providing states with substantial flexibilit y as to how they structure those plans to achieve the 111(d) requirements. The flexibility in cludes, for example, the choice of approaches, trading, time to develop plans, additional time bef ore the start of the interim performance period (postponed from 2020 until 2022), and the ability t o shift emission rate achievement between performance periods. In response to additional anal ysis and many comments, we have modified the proposal and RIA – the establishment of CO2 emi ssion reduction standards is regionally based. The Building Blocks are not prescriptive, an d states may consider local circumstances as they develop their plans, including system reliabil ity, fuel diversity, extreme events, other regulatory requirements and infrastructure. See sec tions V.D, VIII.A, VIII.C and VIII.G of the final rule preamble of the CPP and Chapter 3 of the GHG Mitigation Measures TSD for the CPP Final Rule supporting the final CPP.

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

Area-Specific

Commenter s stated a large-scale shift toward natural gas, esp ecially beyond what Florida utilities are already planning, would greatly increase risks and reduce the state's fuel flexibility and diversity. Commenters stated these risks and the ne ed to have flexibility and diversity are very important because natural gas cannot be stored and because hurricanes and other natural disasters30

or catastrophic events can cause a disruption in su pply. Commenters stated the reliability of the entire state's electrical grid is in jeopardy if we become more dependent on natural gas as the primary fuel source. Commenters stated that price s pikes in natural gas, like those that occurred in 2008, would have bigger impacts on customers' el ectric bills with less fuel diversity and a greater reliance on natural gas. Commenters stated the only way for Florida to achieve EPA's proposed reduction goals would be to use new zero-c arbon generation, and the options there are
limited.

Commenters stated that in 2012, Florida utilities h ad a net summer generating capacity of 57,454 MW. Commenters stated that transmission capability to import energy into peninsular Florida from other states is approximately 3,600 MW, some o f which is already committed to the import of out-of-state generation to meet the state's curr ent and future power needs. Commenters stated that Florida's reliance on natural gas as a generat ion fuel has significantly increased over time and has resulted in a state policy to seek greater diversification in our fuel mix. Commenters stated that currently, approximately 60 percent of the electric power in Florida is generated from natural gas. Commenters stated that the concern wit h Florida's current dependency on natural gas generation pales in comparison to EPA's modeled pro jection that by 2025 Florida will be using natural gas generation to serve 85 percent of load.

Commenters stated that Florida law requires the FPS C to determine the need for new generating facilities and specifically to consider the need fo r electric system reliability and integrity, adequate electricity at a reasonable cost, and the need for fuel diversity and supply reliability. Commenters stated that it is important for Florida to maintain a diversified generation fuel source mix when seeking to comply with relevant CO2 standa rds because a diversified fuel supply can enhance system reliability and significantly mitiga te the effects of volatile fuel price fluctuations, extreme weather events and unplanned plant outages. Commenters stated that additional pipeline capacity would have to be built to accommodate a fu rther reliance on natural gas as a generating fuel. Commenters stated that one of Florida's prima ry pipelines crosses the Gulf of Mexico and is subject to some risk of hurricanes, which adds to t he concern of diminished fuel diversity.

Commenters stated that the EPA's proposal threatens fuel diversity. Commenters stated that the EPA's estimates for building block 2 in Louisiana, if utilized for SIP purposes, would entirely reconfigure the state's economic dispatch from one that currently relies on a modest level of baseload coal generation, to one almost exclusively reliant upon natural gas generation. According to the commenters, the EPA's analysis sug gests that Louisiana should shift its current 31 percent reliance on natural gas-fired generation to 63 percent of its power generation, a level that is more than double the national average for n atural gas-fired generation as forecast by the EIA in its most recent Annual Energy Outlook. Comme nters stated that this considerable change in Louisiana's power generation configuration may v ery well lead to a significant increase in ratepayer costs as well as potential service interr uptions. Commenters quoted NERC as saying: "the power industry relies upon diversification of fuel sources as a mechanism to offset unforeseen events (e.g., abnormal weather, regional transfers, labor strikes, unplanned outages); ensure reliability; and minimize cost impacts. Fuel diversification is also a component of an "allhazards" approach to system planning, which inheren tly provides resilience to the BPS." Commenters indicated that with the current plans fo r retirement of coal-fired capacity and the
additional retirements estimated to result from the EPA's proposal, the U.S. electric power industry will need to compensate for over 100 GW of retired coal-fired capacity. Commenters31

stated that the EPA's proposal threatens to exacerb ate this shift in the resource mix further threatening fuel diversity. Commenters included a t able (titled: “Building Block 2, Louisiana NGCC Units”), which shows listing the NGCC units in cluded in the EPA's CPP baseline calculations for Louisiana, which provides base yea r (2012) generation, the estimated generation level arising from EPA's Building Block 2 analysis, the percent increase this generation represents relative to base year 2012 level, and th e highest generation utilization levels for each NGCC unit over the past 10 years and 5 years. Comme nters made the following points based on
the table:

Louisiana Station No. 1 would need to ramp down to meet the 70 percent utilization level upon which EPA's second building block is based. Th us, based upon the EPA's analysis, Louisiana should adopt policies that promote (or in cent) one of its more efficient CHP units to operate at a lower, rather than higher ope rating efficiency. Substantially increased utilization would be required from the remaining un its under EPA's proposed rule. The Coughlin Power Station will be required to increase it generation utilization by 52 percent over 2012 levels, the Sterlington unit will be required to increase its power generation utilization by close to 70 percent, and the Ouachita unit would be required to increase its power generation utilization by close to 50 percent. These considerable increases in generation are unrealistic for the imp lementation time afforded by the EPA for CPP compliance. The two columns that present th e highest generation utilization levels for each NGCC unit over the past 10 years an d 5 years, respectively, show that at no point over the past decade has any CPP-eligible EGU reached a 70 percent utilization level. Only the Carville Energy LLC unit has reache d a level close (63 percent) to that assumed in the EPA's second building block, which i t reached only in the 2012 base year. Over the past 10 years, Carville has operated, on a verage, around 50 percent and has operated at an average utilization of 57 percent ov er the past five years. On average, most Louisiana EGUs (excluding Louisiana Station No. 1) report 10 year average generation utilization levels of 20 percent and five year aver age utilization levels of 32 percent, both of which are significantly lower than the EPA's tar get of 70 percent.

Commenters noted that ERCOT released a "Gas Curtail ment Risk Study" in March 2012 that
details risks related to curtailment and recommende d that the EPA consider these risks. Commenters stated that gas curtailment is a concern for electric generators who rely on natural gas, particularly in winter months when residential demand is high and supplies are jeopardized by freezing temperatures. Commenters stated that li mitations on natural gas pipeline capacity in Texas occurred during the very cold weather in Febr uary 2011 and 2014, when a large amount of gas was being consumed for home heating. Commenters stated that, with increased reliance on gas for electric generation, there will be an incre ased risk of having to curtail NGCC generation. Commenters stated that relying on one fuel source s o heavily will have unintended consequences on reliability and customer health, safety and cost s; having and maintaining a diverse fuel portfolio is a safer and lower risk approach.

Commenters stated that regional deliverability for the Midwest is in question and noted that, during the peak of the extreme cold temperatures an d storms in January of this year, CWLP's natural gas supplier advised that it had no natural gas to supply us at any price, delivering its supply instead to its residential and commercial cu stomers.32

Extreme Events

Commenters expressed concern that reduced reliance on coal-fired power combined with

increased reliance on NGCC will decrease diversific ation of fuel sources which will constrain the power grid's ability to respond to unforeseen e vents such as regional transfers, labor strikes, unplanned outages and abnormal weather conditions ( as shown during the winter of 2014-14). Commenters stated there is not enough existing NGCC generation in this country to make up for the forced reductions in coal generation and the ga s supply and infrastructure in this country are not available or reliable enough to serve all the g as generation that will be needed. Commenters stated this leaves a significant gap between the am ount of energy that can be generated in compliance with the CO2 goals and the amount of ene rgy that must be generated to supply reliable electricity to the population. Commenters stated that natural gas units are best suited to follow load, rather than serve as baseload units an d employing diverse fuel sources (coal-fired in addition to NGCC and renewables when available) ens ures a secure and reliable energy supply.

Commenters stated that with this shift toward more natural gas consumption in the power sector, the power industry will become increasingly vulnera ble to natural gas supply and transportation risks. Commenters indicated that overdependence on a single fuel type increases the risk of common-mode or area-wide conditions and disruptions , especially during extreme weather events. Commenters referenced a September 2014 NERC report and stated that adverse winter weather, such as that experienced during January 20 14, provided signs of natural gas supply and natural gas supply and deliverability risks. Commen ters stated that this can be a local issue in areas where there is already a heavy concentration of natural gas generation. Commenters added that while there are several plants with dual-fuel capability, the capability to switch to a secondary fuel can be limited during certain operat ing conditions. Commenters stated that an analysis of the CPP prepared by Energy Ventures Ana lysis (EVA) found that natural gas generation would increase by an additional 400-450 TWh/year beyond the EPA's projections, and the gas generation energy market share would re ach 35 percent in 2020, 39 percent in 2030, and 49 percent in 2040. Commenters asserted that as reliance increases more on natural gas for both baseload and on-peak capacity, it is important to also examine potential risks associated with reduced diversity and increased dependence on a single fuel type.

Commenters stated that generally, the power industr y relies upon diversification of fuel sources as a mechanism to offset unforeseen events (e.g., a bnormal weather, regional transfers, labor strikes, unplanned outages); ensure reliability; an d minimize cost impacts. Commenters added that fuel diversification is also a component of an "all-hazards" approach to system planning, which inherently provides resilience to the BPS. Co mmenters indicated that the EPA estimates that an additional 49 GW of nameplate coal capacity will retire by 2020 due to the impacts of the proposed CPP, and that when including the 54 GW of nameplate coal capacity already announced to retire by 2020 (Energy Ventures Analys is maintains a complete list of announced power plant retirements in the contiguous United St ates, retirements as of 10/02/2014) (mostly due to MATS), the power industry will need to repla ce a total of 103 GW of retired coal resources by 2020, largely anticipated to be natura l-gas-fired NGCC and CTs. Commenters stated that considering the current and ongoing shi ft in the resource mix, the EPA proposes to further accelerate the shift, lessening the industr y's diversification of fuel sources.33

Commenters stated natural gas units are best suited to follow load, rather than serve as baseload units. Commenters stated that employing diverse fue l sources (coal-fired in addition to NGCC and renewables, when available) ensures a secure an d reliable energy supply. Commenters stated abnormally cold temperatures impact fuel delivery a nd the ability of the power grid to run reliably. Commenters stated reduced diversity in po wer supply restricts the power sector's ability to respond to these events. Commenters stated that, during the 2014 polar vortex the following fuel delivery complications were encountered: (1) n atural gas interruptions (supply injection, compressor outages, and one pipeline explosion); (2 ) oil delivery problems; (3) inability to procure gas; and (4) fuel oil gelling. Commenters s tated that low temperatures during the polar vortex hindered power generation in the following w ays: (1) low temperature limits for wind turbines; (2) icing on hydro units; (3) failed auxi liary equipment; (4) stress of extended run times; and (5) frozen instrumentation. Commenters s tated Hoosier Energy experienced some of these adverse impacts during the polar vortex: phys ical limitations combined with differences in operational structure of the natural gas and electr icity markets made it extremely difficult to obtain fuel and run the Holland Energy facility; as a result the plant ran only four days from 1/1/2014 through 3/31/2014 and the facility had a c apacity factor of only one percent based on MWh versus potential.

General

Commenters stated that natural gas supply to all us ers is a "just in time" supply system, meaning any disruption in the supply chain causes immediate hardships to the consumers of natural gas. Commenters stated that, without reliable natural ga s, utilities have generally turned to coal which
can be stored on site and carries much less risk on the supply side. Commenters stated a diversified electric strategy at any utility is nee ded to assure the availability of fuel to supply th e electricity to meet customers' needs. Commenters st ated that electric reliability is a major concern for CWLP, whose mission, as a municipal uti lity, is to provide our citizens with reliable, affordable energy (not profits). Commenters stated that, while the electric industry is spending major capital to increase reliability and reduce ri sk for grid reliability on cyber security and physical security, our nation's overall energy poli cy under the GHG Rule introduces more risk into reliability than any outside threat may provid e. Commenters stated that during the peak of the extreme cold temperatures and storms in January of this year, CWLP's natural gas supplier advised that it had no natural gas to supply us at any price, delivering its supply instead to its
residential and commercial customers. Commenters st ated that, while CWLP was able to operate on fuel oil during the period in question, fuel oil operation is suboptimal, expensive and should not be considered a resource to stand up the electr ic grid except during extreme periods. Commenters stated that, if you combine the "just in time" supply system of natural gas along with the "as available" supply system of renewable energy as the predominant supply of the US electric grid, one is left with an electric system that carries great risk (less reliability).

Commenters stated that both the timing and stringen cy of EPA's proposed reductions will challenge the nation's electric utilities, and will lead America to greater dependence on natural gas as a main source of electric generation. Commen ters stated that, from a reliability perspective, it is essential that base load generat ion (coal and nuclear) remain a feasible and costeffective source of generation to meet existing and future energy needs. Commenters stated that over-reliance on any one dispatchable generation ma kes the electric system vulnerable to price34

spikes, distribution disruptions, and even intentio nal human acts such as vandalism or terrorism. Commenters stated it is unknown how operating at su ch a level will impact the long-term reliability and efficiency of such facilities. Comm enters stated that the extent of these concerns varies from Region to Region; however, they are mos t acute in areas where power generators rely on interruptible natural gas pipeline transpor tation.

Commenters expressed concern that a "prolonged dash to gas" will lead to over-reliance on one fuel type and have adverse consequences for the bal ance and diversity of the power sector and the economy. Commenters stated that the increased u se of natural gas to generate electricity will put stress on the natural gas system, which is pres ently designed to meet peak winter heating needs, by requiring increasingly larger supply and flow rate to power plants. According to the commenters, this increased reliance on natural gas has already contributed to rapid price spikes in the cost of gas, which translates into much high er wholesale electricity prices. Commenters stated that it is concerning that EPA has failed to look at the impediments to greater use of natural gas for electric generation or consider the implications of over-reliance on natural gas for generation.

Comment 9: Commenters stated that an assessment of reliability is critical before extensive redispatching decisions are made.

Response 9: The EPA disagrees with the interpretation of the ru le’s requirements, or that the analysis of 111(d) inadequately addressed reliabili ty.. In response to additional analysis and many comments, we have modified the proposal and RI A – the establishment of CO2 emission reduction standards is regionally based. The 111(d) final rule requires that states develop plans

that establish emission standards for affected EGUs . We are providing states with substantial flexibility as to how they structure those plans to achieve the 111(d) requirements. The flexibility includes, for example, the choice of approaches, tr ading, time to develop plans, additional time before the start of the interim performance period (postponed from 2020 until 2022), and the ability to shift emission rate achievement between performance periods. The Building Blocks are not prescriptive, and states may consider local cir cumstances as they develop their plans, including system reliability, fuel diversity, the n eed for ancillary services other regulatory requirements and infrastructure. See sections V.D, VIII.A, VIII.C and VIII.G of the final rule preamble of the CPP and Chapter 3 of the GHG Mitiga tion Measures TSD for the CPP Final Rule supporting the final CPP.

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

Commenters stated that, as NERC has pointed out in its November 2014 Preliminary Reliability Assessment, the EPA's proposal will result in chang es in the resource mix and new dispatch protocols that require comprehensive reliability as sessments to identify changes in power flows and electric reliability services including: (1) lo ad and resource balance; (2) voltage support; and (3) frequency support. Commenters stated the EPA ha s not undertaken these assessments; for example, as the system experienced this past Januar y during the polar vortex, the existing gas infrastructure can be extremely challenged to meet home heating demands, as well as peak gas-35

fired generation requirements. Commenters stated th is problem will become ever more challenging as demand from gas-fired generation inc reases in the future.

Commenters stated the Clean Power Plan's interim ta rget does not allow sufficient time for states throughout the Western Interconnection to identify how they can comply with the proposed legislation, determine compliance plans, select res ources and complete the necessary evaluations to ensure a reliable electric system. Commenters in dicated that the use of the Building Blocks in the proposed rule to meet emission targets will sig nificantly affect balancing areas throughout the Western Interconnection in that implementation will result in resource retirements, changes in operating practices, changes in training procedu res used by operators to control the electric system, changes in the capabilities of the transmis sion system, changes in how the transmission system is operated, a requirement for new transmiss ion resources and transmission upgrades, changes in levels of natural gas-fired generation u sed across the west, changes in the level of gas transportation capacity needed to support a greater use of gas-fired resources, and development of new renewable resources. Commenters gave some ex amples of the changes that would be required, including closure of the North Valmy coal -fired plant which could result in concerns about voltage support in northern Nevada. Commenter s added that each state's selection of Building Blocks will affect every other state, and therefore coordination among all states to ensure reliability of the Western Interconnection i s critical. Commenters stated that at present, states have only begun to plan for the impacts of i mplementing the proposed regulation, and asserted that it is imperative that each state have sufficient time to implement its own compliance plan.

Commenters asserted that it is not tenable for Neva da to meet the interim goal with Building Block 2 for the following reasons (which are addres sed in greater detail elsewhere in this document):

• System reliability has not been sufficiently evalua ted to be able to retire the affected coal-fired EGUs in northern Nevada by 2020

.

• A 2020 retirement date fails to take into account t he remaining useful life of the
coal-fired EGUs.

• Closure of the coal-fired EGUs without new generati on would have detrimental effects on reliability in northern Nevada. Both of the coal-fired EGUs serve base load. Existing NGCC EGUs would not be able to serve that additional base load during the entire year. Therefore, new NGCC EGUs wo uld have to be
constructed.

• In Nevada, over 80% of the land within its borders is federally owned. The process of obtaining the necessary approvals to sit e additional transmission is a lengthy one and unlikely to be accomplished within a three-year period, assuming that the EPA were to approve the state plan by 2017

.

• Replacing coal-fired EGUs with NGCC EGUs is not sim ple. The facilities would not likely be able to use the same footprint becaus e new NGCC units must be36 constructed before closure of the coal-fired units to ensure continuity of reliable
service.

• New pipelines will have to be constructed, and siti ng those pipelines is likely to be met with NEPA and ESA complexities.

• Finally, there is a disparity in different states' closure schedules that need to be resolved before the facility can be shuttered.

Commenters supported the Nevada State Agencies' pos ition that more analysis should probably be done on natural gas infrastructure in the region to determine if the re-dispatch goals outlined by EPA are realistic. Commenters stated the coal pl ant retirements under SB 123 and North Valmy's scheduled retirement in 2025 will, like EPA 's re-dispatch assumptions, shift Nevada's energy production from coal generation to natural g as and renewable energy generation.
Commenters stated that an assessment of Nevada's ab ility to reach the proposed interim and final goals should consider the planned retirement of alm ost all of Nevada's coal EGU capacity by the end of 2025, as coal retirements can be used in pla ce of a re-dispatch strategy to achieve
emission reductions.

Some commenters responded to points made by other c ommenters:

• Commenters agreed that reliability is a critical co ncern that must be addressed.
Commenters noted that the WECC and other entities a re working hard to analyze effects on balancing areas from Clean Power Plan mo difications, and that Nevada has shown leadership by planning to join the Energy Imbalance Market being piloted by PacifiCorp and the California Independen t System Operator (CAISO), which will help bring more renewable resources into play for participants to
utilize. Commenters added that the National Renewab le Energy Labs (NREL) is conducting a long-range analysis, the Renewable Ene rgy Futures Study of how to integrate high levels of renewable energy onto the grid, which is extensive and
detailed. Commenters stated that Commenters 22732 s hould submit specific concerns to the NREL for analysis in this plan so t hat any potential issues can be addressed upfront, which would include addressing t he voltage support concerns related to North Valmy.

• Commenters indicated that with coal plants retiring westwide, major transmission lines will be freed up to serve other needs includi ng wheeling renewable energy, and that renewable energy resources in the vicinity of the North Valmy plant include both geothermal, which is viewed as a "base load" source, as well as solar

energy.

Commenters disagreed with the assertion that new NG CC EGUs will need to be built to redispatch from coal to natural gas, stating that the Western Interconnect is awash in excess natural gas capacity at present and it is growing. Commente rs also refuted the contention that replacing a coal plant necessarily requires new gas to replace their "baseload" power, indicating that coal plants in Nevada in recent years, such as the Reid Gardner plant, have often been run as peaking units, starting up in the morning and shutting down at night. Commenters stated that this is37

inefficient and expensive use of coal power, and it does not necessitate replacement with 100% "baseload" power but could be replaced with a mix o f resources to address the shape of the load including efficiency, renewables and demand respons e.

Comment 10: Commenters said that because of their locations an d other constraints, the
emission reductions that the EPA assumes can be obt ained from Building Blocks 2 and 3 are unrealistic for many rural electric cooperatives.

Response 10: The EPA disagrees with the interpretation of the ru les’ requirements. The 111(d) final rule requires that states develop plans that establish emission standards for affected EGUs. We are providing states with substantial flexibilit y as to how they structure those plans to achieve the 111(d) requirements. The flexibility in cludes, for example, the choice of approaches, trading, time to develop plans, additional time bef ore the start of the interim performance period (postponed from 2020 until 2022), and the ability t o shift emission rate achievement between performance periods. The Building Blocks are not pr escriptive, and states may consider local circumstances as they develop their plans, includin g system reliability, fuel diversity, other regulatory requirements, infrastructure, and the “u seful life” of generation assets. See sections V.D, VIII.A, VIII.C and VIII.G of the final rule pr eamble of the CPP and Chapter 3 of the GHG Mitigation Measures TSD for the CPP Final Rule supp orting the final CPP.

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

Commenters said that because of their location far from other sources of generation, and because of the unique cost constraints they face, many coop eratives lack affordable or practical access to enough gas-fired and renewable energy sources to re place the coal that would be displaced by the new rule, which makes the emission reductions t hat the EPA assumes can be obtained from Building Blocks 2 and 3 unrealistic for many rural electric cooperatives.

Commenters said that cooperative generators have li mited equity available to them i.e., they are highly leveraged, and cooperative consumers must se rvice the debt on units affected by the rule. In many case, commenters said, units running even l ess that 10 percent below their operational norm on a continuing basis would be unable to gener ate enough revenue to service the outstanding debt on the unit. Commenters said runni ng them less (which is what the EPA effectively requires when it suggests that cooperat ives can build new, lower-emitting units or purchase electricity from lower-emitting sources in lieu of generating it from existing units) will lead to significant financial issues and a very hig h likelihood of creating stranded assets.

Commenters noted that EPA's model presumes that Ari zona's Tri-State Generation and Transmission Association, Inc., (Tri-State) coal-fi red facility, Springerville Unit 3, will dispatch at such a low level due to environmental dispatch t hat in reality its continuing operation will no longer be economically viable. According to comment ers, the EPA modeling projects almost 100% re-dispatch of coal resources in Arizona by 20 30. Commenters explained that Tri-State built this 417 MW coal-fired unit in 2006, invested nearly $1 billion dollars in it and the expected useful remaining life of the plant extends until 2066. According to commenters, the Springerville plant is a state-of-the-art coal plan t with air pollution controls including bag houses for particulate matter, scrubbers for sulfur dioxid e, and selective catalytic reduction for nitrogen38

oxides. Commenters added that Tri-State will be ins talling additional controls in 2015 to reduce mercury emissions.

Commenters described how the EPA modeling shows tha t Seminole Electric Cooperative coalfired generating facilities have been arbitrarily s cheduled for retirement well before the end of
their useful life. Commenters described the investm ent this plant has made (more than $530 million) in environmental control technology and re cycling practices and how $260 million of which was placed in service less than 5 years ago. To reduce emissions, and as part of Seminole's commitment to their communities, commenters said th at approximately 70% of the byproducts produced at the coal facility are recycled for use in products that consumers use every day, including wallboard and concrete. These continued i nvestments have made Seminole's facility one of the cleanest coal-based power plants in the country, commenters said. Should the EPA's proposed CO2 rule be finalized, commenters stated, these costly investments will become stranded assets and Seminole's coal-fired power pla nt will be forced to close, leaving 300 hardworking, skilled employees without jobs. Additional ly, commenters said, Seminole would have to build or purchase new power generation to replac e the electricity produced from its coal-fired facility. Such a drastic and sudden shift in Semino le's power portfolio will not only drive up the cost of electricity for its member cooperatives and member consumers, commenters said, but could have sweeping unintended consequences for the fragile but recovering workforce and economy in Florida. Commenters said that numerous c ooperatives will have units that face premature phase-out, creating stranded assets and c onsequently state regional economic disruptions.

Commenters stated that nationwide concerns over nat ural gas availability prompted the U.S. Congress to enact the 1978 Power Plant and Industri al Fuel Use Act. Although repealed in 1987, commenters said that during implementation it requi red all new electric generating facilities to be "coal capable." Commenters said that due to the capital cost differentials between facilities constructed to be "coal capable" and those designed solely for natural gas use, as well as the historically higher fuel cost of natural gas, the F uel Use Act economically prohibited new EGUs that were coal-capable from using natural gas as th e primary fuel. During the time the relevant portions of the Fuel Use Act were in effect, commen ters said, electric cooperative generation needs grew substantially and, as a consequence, abo ut 60 percent of cooperative total baseload electric generation was constructed under Fuel Use Act and is coal based.

Comment 11: Commenters expressed concerns that existing capacit y agreements, transmission rights, complicated ownerships, and unique loads wo uld interfere with implementation of the

CPP.

Response 11: The EPA disagrees. In response to additional analys is and many comments, we have modified the proposal and RIA – the establishm ent of CO2 emission reduction standards is regionally based. The 111(d) final rule requires th at states develop plans that establish emission standards for affected EGUs. We are providing state s with substantial flexibility as to how they structure those plans to achieve the 111(d) require ments. The flexibility includes, for example, the choice of approaches, trading, time to develop plans, additional time before the start of the interim performance period (postponed from 2020 unt il 2022), and the ability to shift emission39

rate achievement between performance periods. The B uilding Blocks are not prescriptive, and states may consider local circumstances as they dev elop their plans, including system reliability, fuel diversity, other regulatory requirements, the “useful life” of generation assets, and infrastructure. See sections V.A, V.D, VIII.A, VIII .C and VIII.G of the final rule preamble of the CPP and Chapter 3 of the GHG Mitigation Measures TS D for the CPP Final Rule supporting the

final CPP.

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

Commenters stated that the coal-fired Big Stone Pla nt and the one combined-cycle unit have no contractual relationship, are owned by different co mpanies, and serve unique loads. Commenters stated that Big Stone is South Dakota's only coal-fired EGU, and there is only one NGCC plant, Deer Creek Station. Commenters stated t hat Deer Creek Station was installed by Basin Electric Cooperative to meet that company's u nique load and customer demand; it was never meant to meet a load reduction from Big Stone . Commenters stated that the combinedcycle unit owner does has no obligation to provide energy to the owners and the customers of Big Stone Plant. Commenters also stated that Big St one Plant operates within the MISO
centralized market. Commenters stated that the comb ined-cycle unit will be placed in the Southwest Power Pool centralized market beginning i n 2015; therefore, the two units will operate with entirely different commitment and disp atch processes. Commenters stated that each Big Stone owner has a firm transmission right from Big Stone to serve their respective loads; likewise, the NGCC plant has a firm transmission ri ght to serve its loads.

Commenters stated that Building Block 2 fails to ac count for the fact that facilities may have already committed their capacity under long term po wer purchase agreements, which the states lack the authority to abrogate. Commenters stated t hat neither EPA nor the states have the authority to regulate the transmission or sale of e nergy to the extent that the Proposal would require: the Federal Power Act ("FPA") imposes lim itations on state authority with respect to energy; states whose transmission facilities are un der the operational control of a System Operator will not be able to unilaterally implement the proposed emissions standards under Building Block Two without impermissibly intruding upon the exclusive jurisdiction of FERC
under the FPA.

Commenters stated that Building Block 2 assumes tha t states can "substitute" the electricity produced by coal-fired and oil/gas-fired steam unit s with electricity produced by NGCC units through, essentially, preferential dispatch of NGCC units. Commenters asserted that Building Block 2 fails to consider what percentage of electr icity produced by NGCC units is currently committed through long-term sales contracts and, th erefore, not available for dispatch.

Commenters stated that independent power producers (IPPs), which are contracted for specific amounts of generation, may not have the immediate f lexibility to re-dispatch under the power purchase agreements (PPAs) between the buyer and th e seller. Even in deregulated market-based systems such as ERCOT, commenters said, the operati on of individual units and companies is still subject to the overall operational needs and constraints of the electrical grid.

Commenters stated that PowerSouth's ability to meet a 70 percent capacity factor is constrained by its agreement to accept "must run" energy from S EPA hydro (for which it would not get40

credit in EPA's goal calculation). As a result of t his, commenters stated PowerSouth reduces its NGCC's operation to fully utilize its "must take" h ydro energy. Commenters stated this flexibility reduces system carbon emissions, but Po werSouth would be penalized for it if Building Block 2 were implemented in Alabama.

Commenters noted that, depending on the market stru cture of the region, natural gas-fired generators may rely more heavily on firm contracts or interruptible contracts. Commenters stated that electric generation owners who have the abilit y to recover costs associated with firm
contracts often choose to enter into firm contracts while, in regions where it is more difficult to recover such costs, such as the Northeast or Mid-At lantic markets, interruptible contracts are frequently used. Commenters stated that, depending on the region, the utilization of the pipeline capacity, and the specific pipeline tariff, firm pi peline costs vary. Commenters provided a Figure 5 (Firm Natural Gas Transmission Rates, Individual Pipeline Tariffs) which shows the average, minimum and maximum costs for firm natural gas fuel delivery in the respective regions based on existing pipeline tariff rates, assuming a 100 p ercent utilization factor of the pipeline. Commenters noted that, while firm contracts on olde r pipelines are most often cheaper than contracts with newer pipelines because older pipeli nes' capital investments are fully depreciated, however, it may be more difficult to contract with older pipelines since they are often fully
subscribed.

Commenters stated the EPA overstates the amount of existing NGCC capacity available for redispatch because the EPA needs to account for NGCC units that may be unavailable for redispatch because they are contractually committed t o out-of-state service or availability. Commenters stated that plants with 10- to 15-year o ut-of-state power purchase agreements (PPA) would not be available for in-state re-dispatch. Co mmenters stated that, even where merchant units have not presently committed to out-of-state service or availability, such units have no obligation to serve in-state load. Commenters state d that, for these reasons, it is inappropriate to assume that capacity from merchant NGCC units will be available for re-dispatch. Commenters stated that forcing PPAs to be dishonored would run afoul of the Contracts Clause and, where compliance would require PPA abandonment, credit ma rkets would tighten causing economic impacts that EPA has not analyzed.

Commenters stated that NGCC ownership diversity may reduce the potential for re-dispatch. Commenters stated that virtually all of the Intermo untain Power Agency (IPP) generation has been delivered to the California Purchasers who, al ong with the other Purchasers, have entitlement rights to all of IPP's generation. Comm enters stated the availability of potential NGCC generation for re-dispatch, including transmis sion, is individual and specific to each
Purchaser. Commenters stated the California Purchas ers may determine that procuring underutilized NGCC in Utah may not serve their econ omic interest or may simply be unavailable. Commenters stated that any NGCC re-dis patch by a California Purchaser from
sources outside of Utah would not factor into the r ate calculation for Utah unless Utah were to join in a regional plan inclusive of such NGCC re-d ispatch. Commenters stated the realization of NGCC re-dispatch as contemplated by building block 2 would be left to the EGUs in Utah exclusive of IPP. Commenters stated that, since IPP is a major source of generation in Utah, it may be difficult for the remaining EGUs to meet the re-dispatch goal. Commenters stated the EPA should allow adjustments for the effects of NGC C re-dispatch from sources outside of the41

state as well as impact of such re-dispatch on the remaining EGUs in the state to be factored into
the rate calculation.

Commenters stated that Idaho must be allowed to re- dispatch out of state coal generation to the under-utilized Idaho NGCC plants and the EPA must r eformulate Idaho's goal with a 70% capacity factor at the two affected units. Commente rs stated that Idaho has two plants with the EPA-designated affected units, both of which are NG CC plants: (1) Idaho Power's Langley Gulch and (2) the Rathdrum LLC plant, which sells g eneration to Avista and has a Power Purchase Agreement with Rathdrum, LLC through 2025.

Comment 12: Some commenters stated that proposed building block 2 does not take into account the current system for dispatching generati ng units.

Response 12: The EPA disagrees that we have mischaracterized or failed to consider the complexities to the current system for dispatching units. The 111(d) final rule requires that states develop plans that establish emission standards for affected EGUs, and, in response to additional analysis and many comments, we have modified the pr oposal. We are providing states with substantial flexibility as to how they structure th ose plans to achieve the 111(d) requirements. The flexibility includes, for example, the choice o f approaches, trading, time to develop plans, additional time before the start of the interim per formance period (postponed from 2020 until 2022), and the ability to shift emission rate achie vement between performance periods. In response to additional analysis and many comments, we have modified the proposal and RIA –

the establishment of CO2 emission reduction standar ds is regionally based. The Building Blocks are not prescriptive, and states may consider local circumstances as they develop their plans, including system reliability, the need for ancillar y services other regulatory requirements and infrastructure. See sections V.A, V.D, VIII.A, VIII .C and VIII.G of the final rule preamble of the CPP and Chapter 3 of the GHG Mitigation Measures TS D for the CPP Final Rule supporting the

final CPP.

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

Dispatch Decisions -- Lowest Cost

Commenters stated Block 2 ignores the manner in whi ch the utility industry, Regional Transmission Organizations (RTOs) and Independent S ystem Operators (ISOs) make dispatch decisions. Commenters noted that, in many parts of the country, dispatch decisions are not under the authority of state agencies or utilities but ar e made by RTOs or ISOs. Commenters stated that, in the utility industry, the dispatch decisio ns are made based on two factors: reliability and cost. Commenters indicated that coal units required for reliability should not be assumed to be able to back down when NGCCs increase their capacit y factor. Commenters noted that many coal units provide voltage support to enable the tr ansmission system to deliver electricity; other coal units must operate to enable the system to mee t load in the event of sudden system changes, such as an unexpected outage of another fossil unit or the loss of a renewable resource (e.g., when the wind stops blowing).42

Commenters stated that building block 2 would creat e significant problems for Regional Transmission Organizations (RTOs), whose purpose is to help their members access the lowest cost generation on a continual basis, regardless of the location of the generation or the location of the member, while maintaining grid reliability. Com menters noted that as a result, RTOs implement what is known as economic dispatch, but u nder the proposal RTOs will be forced to implement environmental dispatch of generating unit s (i.e., RTOs will be required to consider the environmental effects of operating generating u nits before the economic benefits of operating those same units). Commenters asserted that this is contrary to the purpose for which RTOs were formed and also violates those regional entities' o bligations under the Federal Power Act to dispatch generation economically.

Commenters stated that, given RTOs and ISOs current ly make their dispatch decisions on the current cost of generating kilowatts at that partic ular moment, it drives the grid towards producing the most cost-effective electricity. Comm enters stated Building Block 2 would drive dispatch decisions towards utilizing 70% of the NGC C capacity, seemingly at the expense of lower cost generation. Commenters stated that shift ing our generation preferences from low cost method to the 4th most preferred method in terms of cost will do nothing other than significantly raise electricity rates.

Commenters stated the concept of operating all NGCC units at a 70% capacity factor is unrealistic for Texas due to the design of the ERCO T market. Commenters stated that any dispatch method that preferentially selects resourc es based on emissions rates, without regard for underlying fuel cost structure, will lead to market uncertainty and severe price increases. Commenters stated that, when the grid is strained, ERCOT may need to require coal units to run outside of emissions constraints for reliability. C ommenters stated this Building Block calls for an approximate 52% reduction in coal unit operation in Texas while CPS Energy's average NGCC capacity factor is around 35% for 2009-2013, t hanks to CPS Energy's zero-emissions
base load nuclear resource.

Dispatch Decisions -- Managed by Independent Agenci es

Commenters stated that the Ameren Corporation does not own an existing NGCC generating unit. Commenters stated that certain generating uni ts of this type may have permit limitations, warranty, and/or other contractual arrangements tha t preclude their operation as assumed in the proposed rule. Commenters also noted that in RTO ma rkets, the FERC and not the states regulate the RTOs; therefore, the proposed rule imposes a re quirement on states that they do not have the authority to implement.

Commenters stated that Building Block 2 is incompat ible with the current system for electricity dispatch, which is managed by independent agencies, not state governments and which is based on cost, not a regulatory preference for natural ga s. Commenters stated that dispatch decisions are made by regional transmission operators (RTOs) and independent system operators (ISOs) like MISO, ERCOT, and PJM, which operate within the structure and governance of FERC. Commenters stated that many of these organizations serve multiple states, and their jurisdictions do not always follow state borders. Commenters stat ed that, since state governments have limited authority to dictate these organizations dispatch d ecisions, it will be impossible for a state to43

fully implement Building Block 2 simply because an individual state does not have the authority to fully control the dispatch decisions.

Commenters stated the EPA lacks the legal authority to order NGCC plants to operate at a particular capacity. Commenters stated that only a Regional Transmission Operator or Independent System Operator under the jurisdiction of the Federal Energy Regulatory Commission (FERC) jurisdiction has such authority.

Commenters stated that, while the EPA has suggested that the Northern Tier Transmission Group (NTTG) could manage the regional re-dispatch of pow er envisioned under Building Block two, the NTTG has written to the EPA to explain that the NTTG has no authority or capability to implement building block two requirements.

Commenters asked EPA to not include redispatch from coal- to gas-fired generation as part of the emission rate goal setting methodology because the redispatch of generating assets is outside the scope of EPA's authority under the CAA and intr udes upon the authority of both the states
and the FERC.

Commenters stated that altering market design to ac hieve a set capacity factor in New York, which has deregulated the electricity market, will be almost impossible. Commenters stated the EPA should recognize the limitation and significant benefits of deregulated markets and encourage deregulated markets that have delivered s ignificant reduction in GHG and not place those markets in peril.

Commenters stated that, while the EPA suggests that a state could effectuate re-dispatch of the generation within a state by requiring units to fac tor the costs of compliance into their electricity market bids, the EPA's suggestion will not work abs ent the coordination of all generating units within the SPP region. Commenters stated that, beca use compliance obligations and costs differ greatly among states, it would be impossible for a unit in one state to determine the bid price necessary to ensure that it would or would not be d ispatched before generating units in other states within the SPP region. Commenters stated thi s is further complicated in states that fall within multiple regions, such as New Mexico and Tex as. Commenters stated that, in Oklahoma, the electricity market is managed by SPP, an indepe ndent system operator that dispatches all generation within its region and SPP, like all syst em operators, dispatches electricity on a priority basis of (1) reliability and (2) least-cost.

Commenters stated that the EPA's Building Block 2 i s based on what commenters considers to be a faulty premise that generation from any NGCC u nit located within a state may be redirected by a utility or state within the state's borders to offset reduced generation from coal-fired units elsewhere in the state. According to the commenters , in most states electric generation is dispatched by an RTO or ISO, which calls up generat ion from EGUs within its system such that the lowest cost generating sources are dispatched f irst. Commenters also noted that the areas covered by RTO and ISO systems typically do not coi ncide with state borders - in most cases, an ISO's footprint includes generating units in severa l states, and some states are divided between multiple ISOs. Commenters maintained that as a resu lt it is common for EGUs within a state to be dispatched based on direction from different man aging authorities, and for EGUs to serve load outside of the states in which they are locate d. Commenters added that there may be limited44

interconnection between the different dispatch syst ems in a state, and EGUs in one part of a state may lack the cross-state transmission rights needed to serve load in a different part of the state.

Commenters stated that the EPA has assumed that a u tility will be able to alter the dispatch patterns of its NGCC capacity without taking into a ccount the dispatch mechanisms within Regional Transmission Organizations (RTOs) and Inde pendent System Operators (ISOs).
Commenters indicated that an RTO's control over the dispatch of generation will affect a state's ability to adopt measures that achieve EPA's propos ed section 111(d) requirements and a utility's ability to control emissions from its overall fleet and comply with state plan requirements. Commenters noted that under Building Block 2 the st ate, and ultimately the utility, will need to achieve EPA's post re-dispatch capacity factor on N GCC units, but dispatch of the units is not controlled by either the state or, generally, the u tility, and thus direct control is not possible; rather, a utility would need to attempt to bid its units in a manner which results in the RTO dispatching the utility's NGCC units within a certa in state at EPA's post re-dispatch capacity
factor for that state. Commenters stated that RTOs currently make dispatch decisions based upon economics - i.e., the lowest cost generating source s are dispatched first. Commenters gave the following example of this "economic dispatch" mecha nism, which is based on a presentation by the Electric Reliability Council of Texas (ERCOT) a t a Texas Public Service Commission workshop on the Proposed Guidelines:

Every five minutes, ERCOT sends a signal to each on line generator that is participating in the ERCOT market (through the generator's Qualified Sch eduling Entity) telling each generator how much power to produce; In general, this set of gene rator output levels is the lowest cost way to meet the system load for that five minute interval; The optimization uses the offer curves submitted for each generator; If the lowest-cost se t of generator output levels would result in an
overload of one or more transmission constraints on the system, the economic dispatch optimization will select a different, higher-cost s et of output levels that is the lowest cost set tha t does not overload any transmission constraints; and , This process is called a security-constrained economic dispatch (SCED).

Commenters stated the EPA presumes that utilities w ill be able to rely on the interconnected nature of the electricity sector to accomplish Buil ding Block 2 (79 FR 34837). Commenters stated that PowerSouth is not part of an RTO or ISO , but instead owns and operates its own Energy Control System and must comply with the FERC and NERC requirements on its own. Commenters stated that FERC and NERC require certai n reliability measures such as maintaining spinning reserves at all times and, bec ause PowerSouth is not part of an RTO or ISO, it cannot rely on other resources to satisfy s uch requirements like many other utilities. Commenters stated the EPA's proposal essentially pr ohibits PowerSouth from maintaining its business model by making it so uneconomical that Po werSouth must coordinate with other utilities to satisfy reliability requirements. Comm enters stated it is well beyond EPA's authority to regulate certain business models out of existenc e and require those utilities to join an RTO or
ISO.

Commenters stated the EPA proposal ignored the inte rstate nature of ownership, contracting, and supply for municipal and electrical loads. Commente rs stated the EPA's purported redistribution of electric power for environmental reasons leaves Wyoming regulating the output of power not used in Wyoming, and interferes with the generation and distribution of power for small45

municipalities who have no ability to redirect thei r power supply along environmental lines. Commenters stated that the EPA incorrectly assumes that "generation at one EGU can be substituted for generation at another" because the EPA considers the nationwide grid to be fully interconnected, such that electrons can be dispatch ed from any generating source for delivery anywhere they are needed, allowing the re-dispatch of power from low carbon emitting sources to replace generation from high carbon emitting sou rces. Commenters stated there are actually three different electrical grids in the continental United States that operate with different electrical characteristics (Eastern Interconnection , Western Interconnection, and the Electric Reliability Council of Texas).

Commenters urged the EPA to work with states and re gional transmission organizations to adopt a more realistic view of the potential for re-dispa tch that considers stranded costs and the reliability of the grid and to adopt a more reasona ble phase-in time table for re-dispatch that does not threaten the reliability of the regional grid n or impose undue stranded costs on states' electric ratepayers. Commenters stated the Western Electrici ty Coordinating Council (WECC) began a phased study process to provide an analysis of pote ntial impacts of the Proposed Rule to the Western electric generation and transmission indust ry. Commenters stated preliminary WECC results indicate that a state's decisions made rega rding compliance with the Proposed Rule can "drastically impact grid operations, system resilie ncy, and potentially, compliance opportunities for a neighboring state."

Commenters suggested that the EPA may need to revis it their understanding of dispatching, as well as a review of availability using local, exist ing system constraints to define an appropriate target for NGCC dispatching, which may not be diffe rent than what was already demonstrated in 2012 when NGCC were the least cost option. Commente rs stated that the EPA knows that available electric generating units are dispatched by cost, and when the cost of natural gas fell below the cost of coal in 2012 (in lb/MMBtu of heat input), the resulting generation change was obvious. The commenters disagreed with EPA that the se data suggest that, since the industry already shifted 20% capacity, they can also shift a n additional 20% due to a rule because this conclusion ignores EPA's initial statements on how available units are dispatched by cost. Commenters noted the EPA describes that Regional Sy stem Operators (RSOs) and Independent System Operators (ISOs) dispatch according to econo mics first and the EPA then observes the huge increase in capacity factor in 2011 and 2012 o f NGCC, and relates this to the historic low natural gas prices. Commenters stated that, if EPA requires re-dispatch ing approximately 90% of coal and oil/gas steam generation to existing NGCC, the existing NGCC must not be limited by other system constraints.

Bilateral contracts

Commenters stated that EGU owners can replace fossi l fuel-fired generation with renewable generation through bilateral contract. Commenters s tated that, whether an EGU owner is located in a state that is operating under traditional util ity regulation or in a restructured market, that owner may enter bilateral contracts for the sale of power. [FERC Primer at 60-61.] Commenters stated that such contracts require the EGU to suppl y a certain amount of power to a customer such as a distribution utility. Commenters stated a large volume of renewable energy used by vertically integrated utilities--including IOUs, mu nicipal utilities, and co-ops--is procured through PPAs with independent renewable developers. Commenters stated those utilities that46

own fossil fuel-fired EGUs are free to reduce the u tilization of their EGUs and replace it with the procurement of renewable energy from renewable proj ects owned and operated by third party developers. Commenters stated that, even in organiz ed markets, IPPs often enter into long-term bilateral contracts rather than sell all generation into the day-ahead or spot-market operated by the RTO. Commenters stated a good example of this i s Invenergy:

• Invenergy, an IPP that owns generation capacity fro m various resources including 56 wind projects (5,473 MW), 5 solar projects (49 M W), 8 natural gas combustion turbines (4,529 MW), and 4 storage proje cts (65 MW). Invenergy enters into bilateral contracts with utilities, ele ctric cooperatives, and commercial power users in many states throughout all regions o f the country. As the owner of natural gas and renewable EGUs, Invenergy can manag e, through traditional business decision making, the resource mix of its g eneration assets in order to
reduce the CO2 emissions of its fossil fuel-fired E GUs while meeting contract obligations to its customers. Moreover, IPPs such a s Invenergy can help utilities that own EGUs or other EGU owners by signing bilate ral contracts for their own low- or zero-carbon emission generation so that tho se purchasers can meet their obligations to distribute electricity, yet reduce u tilization of their higher emitting
EGUs.

Commenters stated that IPPs that own only fossil ge neration can also sign bilateral contracts with IPPs that own renewable energy. Commenters stated t hat bilateral contracts between merchant
fossil fuel-fired EGU owners and their customers of ten do not specify the particular generation resource that must be used. According to commenters , merchant fossil-fuel fired EGU owners that do not own sufficient renewable generation or do not own it in the right location can instead act as a power marketer by signing a separate bilat eral contract with a third party renewable generator, so that the original bilateral contract obligation between the merchant fossil fuel-fired EGU owner and a customer or distribution utility wo uld be satisfied with a mix of renewable power from the third party and fossil-fired power f rom the merchant fossil fuel-fired EGU

owner.

Commenters stated the bilateral market for renewabl e energy is well developed. Commenters stated there are no legal or technical obstacles to a fossil fuel-fired EGU owner acting as the counterparty of a bilateral contract for purchase o f energy from a renewable generation facility. Commenters stated the ability of non-utility entiti es to sign contracts for the delivery of renewable generation is sufficient proof that such contracts are adequately demonstrated.
Commenters stated that even end-users that are not in the power sector have entered into such PPAs, including:

• OwnEnergy has a contract to deliver the output of i ts 50 MW Alexander Wind
Farm in Kansas to Yahoo.

• Microsoft has signed a bilateral contract to purcha se the output of the 175 MW Pilot Hill Wind Project in Illinois owned by Orion Energy and Vision Energy.

Area-Specific Concerns47

New Mexico

Commenters stated that the final rule should evalua te and adjust Building Block 2 where necessary to account for dispatch decision-making c apabilities. Commenters stated that redispatch considerations in goal setting should cons ider whether out-of-state utilities and balancing authorities make dispatch decisions that affect states' ability to accomplish full redispatch. Commenters explained that many of New Mex ico's dispatch decisions are not controlled by in-state authorities. Commenters stat ed that New Mexico is connected to two different grids and exports between 30 and 40% of i ts power annually, making it dependent on other states' dispatch authorities to make appropri ate dispatch decisions. Commenters also noted that many of the state's rural electric cooperative s purchase power from the Southwest Power Pool, for which dispatch decisions are made in thei r Corporate Center in Little Rock, Arkansas.

Commenters stated that the final rule should evalua te and adjust Building Block 2 where necessary to account for dispatch decision-making c apabilities. Commenters stated that many of New Mexico's dispatch decisions are not controlled by in-state authorities as New Mexico is connected to two different grids and exports betwee n 30 and 40% of its power annually, making it dependent on other states' dispatch authorities to make appropriate dispatch decisions. Commenters added that many of the state's rural ele ctric cooperatives purchase power from the Southwest Power Pool, for which dispatch decisions are made in their Corporate Center in Little Rock, Arkansas. Commenters stated, nevertheless, pa rtial re-dispatch is possible in New Mexico; it may, therefore, become an important option to in clude in the New Mexico State Plan.

South Dakota

Commenters stated that, because the economics of un it dispatch vary dramatically from utility system to utility system, Block 2 would impose arbi trarily different cost of compliance on the different states. Commenters stated that analysis o f the different state targets shows the arbitrary impact of Block 2 and provided the following exampl e.

Consider two similar, adjacent states: North and So uth Dakota. Despite the fact that they are in the same region of the country, North Dakota and So uth Dakota have very different targets. North Dakota is required to achieve an 11% reductio n to 1,783 lb/MWh, while South Dakota
must labor to achieve a 35% reduction to 741 lb/MWh . The primary reason for this difference is EPA's decision to use the arbitrary re-dispatch met hodology to address NGCCs; North Dakota has none, while South Dakota has a single NGCC that was under construction in 2012 and thus had a very low capacity factor. With a difference i n targets of more than 1,000 lb/MWh, the two states will face completely different compliance ec onomics.

Commenters stated that another issue the EPA fails to consider is the potential implications on how states/RTOs could dispatch units where there ar e multiple RTOs operating in a single state. Commenters gave the example that in South Dakota th ere is one NGCC unit - Deer Creek station (owned by Basin Electric Power Cooperative (Basin)) , which commenced commercial operation in August 2012 and had a 1 percent annual capacity factor for that year. Commenters noted that in the EPA's goal setting methodology for Building Block 2, Deer Creek is ramped up to a 70 percent capacity factor, requiring South Dakota's l one coal-fired unit - Big Stone (co-owned by Otter Tail Power, Montana-Dakota Utilities and Nort hWestern Corporation) - to reduce48

operations to an annual capacity factor of 23 perce nt. Commenters asserted that the EPA fails to consider that the Deer Creek and Big Stone plants h ave different owners and are located in
different RTOs and serve different loads.

Commenters stated that an issue EPA fails to consid er in its simplified approach on NGCC redispatch is its potential implications on how state s/RTOs could dispatch units where there are multiple RTOs operating in a single state. Commente rs noted there are eleven states that have
two RTOs within their state boundaries. Commenters stated that in South Dakota there is one NGCC unit, Deer Creek station, and one coal-fired u nit, Big Stone, but the EPA failed to consider that the Deer Creek and Big Stone plants h ave different owners and are located in
different RTOs and serve different loads. Commenter s stated the flawed assumption of Building Block 2 is that Deer Creek Station will be dispatch ed to meet the needs of the Big Stone Plant co-owners' loads presently served by Big Stone Plan t.

Commenters stated that, because Deer Creek Station' s load is delivered into a different RTO than the coal-based load at South Dakota's only coal-bas ed plant, Big Stone, therefore its power cannot be used to replace Big Stone's load, as EPA' s rule assumes. Commenters stated that, while
the EPA assumed that the Deer Creek Station will in crease in electrical output and the Big Stone Station will correspondingly decrease in electrical output, thereby decreasing the CO2 emissions in the state of South Dakota, this assumption is no t consistent with the facts in South Dakota.
Commenters stated the EPA should reevaluate the rol e its Deer Creek Station plays in South Dakota, as EPA's treatment of this facility is erro neous and this impacts South Dakota's state emission limit significantly.

Commenters stated that re-dispatch of energy from o ne plant to another is feasible where the coal-fired unit and the NGCC unit are owned by the same company and where the incremental costs will be borne by the customers of the company serving the load. Commenters stated that
where the coal-fired unit and the NGCC unit are own ed by completely different entities serving separate loads, as is the case in South Dakota, any transfer of energy between those entities would require a willing buyer and a willing seller. Commenters stated Big Stone Plant and Deer
Creek Station are not merchant units with unsubscri bed capacity and energy available for sale. Commenters stated that, since Basin Electric built Deer Creek Station to serve its own load obligation, energy from Deer Creek Station has not been available for sale to the co-owners of Big Stone Plant, and Basin Electric lacks incentive or means to sell energy committed to serving its own load. Big Stone Plant's co-owners have no r ight to the energy output of Deer Creek Station, making re-dispatch infeasible.

Commenters stated that detailed engineering studies and modeling are needed to ensure that energy can be transferred effectively from each gen erator to the load it is intended to serve. Commenters stated that, while adequate transmission capability and infrastructure supports delivery of Big Stone Plant generation to its retai l customers and Deer Creek Station generation to its customers, this transmission infrastructure was not designed to support the transmission of energy from Deer Creek Station to customers of the Big Stone Plant co-owners. Commenters concluded that the EPA should not require implement ation of Building Block 2 in South Dakota because it would be contrary to the contractual, pl anning, operational, and reliability realities facing the separate owners of Big Stone Plant and D eer Creek Station. Commenters stated Building Block 2 is technically infeasible in South Dakota and, in its final rulemaking, the EPA49

should remove Building Block 2 from the target-sett ing calculation for South Dakota. Commenters stated they supported the comments filed by Commenters regarding Building Block 2 and the Big Stone Plant.

Other States/Areas

Commenters stated that Michigan's IOUs are market p articipants in one of two RTOs (MISO or PJM); and as such the electric generation resources are managed through a market-based system where power is bid into the market and bought back to provide supply to their customers. Commenters indicated that based on this existing ma rket-based approach, jurisdictional issues would arise between the state regulators overseeing implementation of Section 111(d) and the RTOs managing the economic-based dispatch of all ge neration, including NGCC units. Commenters asserted that a fundamental change in th is system would be necessary in order to account for re-dispatch of NGCC units, such as the implementation of a carbon price.

Commenters stated that EPA's re-dispatch approach c onsequently conflicts with the responsibilities assigned to RTOs by FERC, and the nature of electricity markets today. Commenters added the Southwest Power Pool (SPP) res ponded to a question from the Missouri
Public Service Commission on whether an RTO's contr ol over the dispatch of generation will affect a utility's ability to control emissions and comply with the Proposed Guidelines by saying that SPP's market dispatch is designed to reliably dispatch the most economic resources and could affect compliance with EPA's requirements unl ess well-designed market system changes
are made. Commenters stated that close coordination between SPP, members, regulators and the applicable state agencies will be needed to ensure that SPP's SCED system appropriately accounts for emission goals, which will not be a si mple matter and will take considerable time to develop the appropriate protocols and potential mar ket system changes.

Commenters stated that, while fossil fuel-fired gen eration sources located within Nevada are subject to Nevada's air quality control measures an d permit limits, a number of them are not subject to Nevada jurisdiction from a public utilit y planning perspective. Commenters stated those resources are owned and controlled by utiliti es in other states. Commenters stated Building
Block 2 creates conflict between states that share a common generating station. Commenters stated that Nevada cannot utilize non-jurisdictiona l NGCC and coal-fired EGUs to assist in meeting its emission reductions targets until the j urisdictional issue has been addressed. Commenters stated that, while the USEPA suggests th at states should be left to negotiate such situations among themselves, there is very little t ime to do so before a state plan is required to be submitted under the proposed deadlines. Commenters stated the Nevada Agencies request that the USEPA provide a more streamlined approach.

Commenters added that SWEPCO's comments to the Texa s Public Utility Commission identified concerns over Building Block 2 in Texas - SWEPCO no ted that the Proposed Guidelines' redispatch approach is inconsistent with the current dispatch algorithms used by balancing authorities, and that noneconomic dispatch will lea d to increased costs for customers.

Commenters stated that power simply cannot flow acr oss the east/west systems without constraint, as EPA assumes. Commenters explained th at Basin Electric has several DC Ties that bridge the national electric system, but only has a limited amount of available capacity across50

those ties. Commenters stated that Basin Electric t herefore developed its generating assets on either side of the grid without regard to environme ntal dispatch: coal primarily on the west, where coal resources can be cheaply and dependably obtained, and natural gas and wind largely on the east, where good wind resources exist. Comme nters stated that, because environmental dispatch has never before been proposed or mandated , Basin Electric has not developed its generating capacity to transfer across the east and west grids. Commenters stated that Basin Electric only has ownership or capacity rights to t ransfer 240 MW in the west-to-east direction and 423 MW in the east-to-west direction, far less that its total generating capacity of 5,152 MW. Commenters stated that, as a result, Basin Electric cannot meet its member load requirements by simply re-dispatching NGCC on one side of the grid to replace power lost from a coal-based EGU on the other, or likewise replace lost generati on from a west-side EGU with east side
renewables.

Commenters stated that the EPA's misunderstanding o f how electric markets operate, shown in this instance by its confusion on what the Northern Tier Transmission Group (NTTG) does, highlights the pragmatic problems of actually imple menting the rule as proposed because the Proposal relies on these fundamental errors. Commen ters noted that the Proposal states that Northern Tier Transmission Group (NTTG) as a region al transmission organization will be able to facilitate/implement the Proposal by ensuring: t he re-dispatch of coal with NGCC units as described under Block 2, grid reliability, and tran smission upgrades. Commenters stated that this assumption is completely false and illustrates how EPA has stepped outside of its expertise in this rulemaking. Commenters stated that, while Utah Associated Municipal Power Systems (UAMPS) is an active member of NTTG, NTTG is not a regional transmission operator and does not have control over grid reliability, capacity ma rkets, scheduling/dispatch decisions or transmission upgrades. Commenters stated that NTTG is a planning organization that is designed to provide a forum for State, industry and public s takeholders to study transmission scenarios that may be ultimately implemented by NTTG members.

Commenters stated that even where electricity dispa tch is governed by individual utilities and not by an ISO or RTO, similar limitations on in-sta te re-dispatch arise where a state is served by multiple utilities or where a utility spans multipl e states. As an example, Commenters noted that TVA generates power from fossil fuels in 4 states a nd distributes power to Tennessee and portions of 6 other states, and it also buys and se lls some power from neighboring systems and optimizes the dispatch of generating assets and ope ration of transmission infrastructure as a system (not necessarily within individual states) t o maintain reliability and minimize cost.
Commenters indicated that three of TVA's five NGCC units are located in Mississippi, but all of
its coal-fired units are located outside of Mississ ippi (TVA does purchase power through a power purchase agreement from the Red Hills coal-fired un it in Mississippi). Commenters concluded that increasing the capacity factor of TVA's Missis sippi NGCC plants would have minimal effect on coal-fired generation in Mississippi: virtually all of the generation displaced would be from
TVA's coal-fired units in other TVA states.

Commenters stated that the U.S. Energy Information Administration ("EIA") describes the grid and the systems that provide efficient and reliable electricity to consumers in its "primer," a document accessible to all, including EPA. Commente rs said that it is most important to recognize that the grid uses market mechanisms to d ispatch the proper mix of resources at any51

one time, but the grid does not and cannot be tuned to environmental concerns only. Commenters cited the EIA primer:

"An electric power system is an integrated system c onsisting of generating plants, high voltage transmission lines, local distribution facilities, communication, and other facilities that must operate as a contemporaneous network in real-time o r in a synchronous manner to provide stable and reliable electricity to consumers. The flow of electricity within the system is maintained and controlled by dispatch centers. It is the responsib ility of the dispatch center to match the supply of electricity with the demand for it. In order to carry out its responsibilities, the dispatch center is authorized to buy and sell electricity based on system requirements. Authority for those transactions has been preapproved under interconnec tion agreements signed by all the electric utilities physically interconnected or with coordin ation agreements among utilities that are not
connected.

[R]egional transmission organizations and independe nt system operators in some geographic regions exist to operate transmission systems in a non-discriminatory manner. They also manage organized competitive markets for the purchase and sale of wholesale electricity....

Overall reliability planning and coordination of th e interconnected power systems are the responsibility of the North American Electric Relia bility Corporation (NERC).... NERC's eight regional entities cover the 48 contiguous States an d portions of Canada and Mexico. The regional entities are responsible for overall coord ination of bulk power policies that affect the reliability and adequacy of electricity service in their areas. They also regularly exchange operating and planning information among their memb er utilities.

The electric power industry and the Federal Energy Regulatory Commission (FERC) continue to implement the requirements of the Energy Policy Act of 2005. This Act amended the Federal Power Act by adding Section 215, which set the resp onsibility for overseeing operations, developing procedures, and enforcing mandatory reli ability standards in the electric power industry to a new electricity reliability organizat ion (ERO). Section 215 requires FERC to certify the ERO and approve reliability standards proposed by the ERO. In July 2006, FERC certified NERC to be the ERO, and by doing so NERC became the North American Electric Reliability Corporation. FERC also provided guidance on a pro f orma Delegation Agreement between NERC and Regional Entities under which Regional Ent ities would have the authority to recommend reliability standards to the ERO and enfo rce them. In Order Nos. 693 and 693-A, the FERC approved 83 of 107 proposed Reliability Standa rds for which the ERO assumed enforcement responsibilities in June 2007. Under th is new authority FERC may undertake enforcement actions independent of the ERO, includi ng the imposition of penalties. The FERC, under its new general oversight responsibilities, c ontinues to examine, provide input, and approve new mandatory standards as proposed by the ERO."

Comment 13: Commenters expressed concerns regarding the lack au thority by states or other entities to implement the generation shifting in th e CPP.52

Response 13: The EPA disagrees with commenters. CAA section 111( d)(1) requires the EPA to promulgate regulations under which states submit st ate plans regulating “any existing source” of certain pollutants “to which a standard of performa nce would apply if such existing source were a new source” and “provides for the implementation and enforcement of such standards of performance.” Affected EGUs, including municipaliti es and electric cooperatives, are subject to air quality requirements, including meeting such st andards of performance that a state may establish to meet emissions performance levels that the EPA determines are achievable under CAA 111(d). We give states and affected EGUs flexib ility determining how they meet these requirements. No state or affected EGU must impleme nt the precise measures included in the building blocks in order to do so. For a more compr ehensive discussion of these issues, please see section V.D of the final rule preamble of the C PP for EPA’s response to this comment.

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

Commenters stated the Proposal seems to work under the assumption that a state (or the loadserving entities within a state) have full legal au thority and operational capability to dispatch any generating and transmission resources within the st ate to serve existing and future load obligations. Commenters continued, stating that BB2 calls on load serving entities in Arizona to significantly increase their reliance on existing n atural gas-fired generation without any consideration of the ownership of those units, exis ting legal commitments of various units, financial consequences related to the shift from cu rrently owned generation, and without adequate consideration of natural gas pipeline capa city and electric transmission constraints.

Commenters stated that using new data, there is an incorrect EPA assumption that commenters have authority to provide services for generation d ispatch, transmission upgrades and system reliability. Commenters' explanation follows. I. BA CKGROUND In the proposed rule the EPA specifically references the commenter's organizatio n and suggests that for areas of the country that are not covered by an ISO/RTO, there are regio nal groups, such as commenters and Columbia Grid, that can control dispatch and seek s olutions such as capacity markets and transmission upgrades to preserve resource adequacy and ensure the continued reliable operation of the grid 1. Commenters stated in order to correc t this apparent misunderstanding of the nature of the organization, commenters submitted these com ments to brief the EPA on commenters' roles and functions in relation to transmission pla nning and system operations, and in particular to draw a clear distinction between the responsibil ities of a planning region such as commenter's and those of a Regional Transmission Organization ( RTO). Commenters said commenters' organizations' activities are governed and directed by the commenter's organization's Steering Committee, with membership comprised of (1) one sta tproposal for increasing the dispatch e regulatory utility commissioner appointed by each s tate's respective regulatory utility commission 3 in the NTTG Footprint, (2) one represe ntative from each of the Funding Members 4, and (3) one representative appointed from each s tate customer advocacy agency 5 within the commenter's organization Footprint (the comment er's organization Members). commenter's organization Members, together with other stakehold ers, carry out an open, transparent, coordinated transmission planning process for servi ce and facilities involving the combined systems within commenter's organization and ultimat ely, interregional coordination through participation by the commenter's organization in th e Western Electricity Coordinating Council processes. Commenters stated the commenter's organi zation Members are committed to53

initiatives that will increase the efficiency and u se of the transmission grid for the benefit of customers, the furtherance of markets, regional tra nsmission tariffs, and other transmission products, services or structures that are economica lly justified. Commenters stated the proposed rule suggests that commenter's organization exercis es a dispatch function, may authorize transmission upgrades, and could implement a capaci ty market. Commenters said these functions are not performed by commenters' organization and o utside of its authority to implement. Commenters stated though commenter's organizations carry out an important role for regional and interregional transmission and system planning for the commenters' organizations' footprints, it is not a market operator, nor has any role in th e scheduling, commitment and/or dispatch of any generating units. Commenters said further, tran smission plans that result from commenters' organizations' processes are implemented by other e ntities, not by and through commenters' organizations. 6 Commenters stated it is important to emphasize that unlike a RTO, commenter's organization does not have operational or short ter m reliability authority for the transmission within its footprint. Commenters said this responsi bility, along with tariff administration and design, congestion management, parallel path flow, ancillary services, OASIS total transmission capability and available transmission capability, a nd market monitoring functions remain with other entities (e.g., individual Transmission Owner s). III. CONCLUSION Commenters stated commenters' organizations do not have the authority , nor the responsibility, to provide services for generation dispatch, transmission upgrades and system reliability that EPA has assumed as a basis for implementation of its proposed rule.

Commenters pointed out that state utility regulator y commissions lack the authority to implement several building blocks with respect to public powe r utilities. Commenters state that in some instances, state utility commission approval is req uired for new generation units or for generation dispatch. Commenters noted that state utility commi ssions do not otherwise regulate public power utilities in their states.

Grid Operators

Commenters stated that, in designing its state-by-s tate best systems, EPA wrongly assumes that states can control the dispatch of in-state resourc es so that, for instance, an in-state NGCC unit can be ramped up and an in-state coal unit can be r amped down to meet EPA's goal. Commenters
stated that states themselves do not control the di spatch of units, as units are instead dispatched by regional grid operators based on regional power needs. Commenters concluded that the grid operator might be forced to call on the state's coa l and gas plant to meet regional supply needs, depending on the state of the regional market at an y one time and, thus, EPA's state-by-state best systems could not exist in the real world.

Commenters stated the proposed rule fails to recogn ize scheduling and dispatch are controlled by regional transmission organizations (RTOs) and inde pendent system operators (ISOs). Commenters stated Montana cannot unilaterally imple ment Building Block 2 without intruding upon the jurisdiction of these organizations and th e Federal Energy Regulatory Commission (FERC). Commenters stated FERC has exclusive jurisd iction over the transmission of electricity in interstate commerce and the sale of such energy at wholesale in interstate commerce and states retain jurisdiction only over retail sales of elect ricity, generating facilities, facilities used for54

local distribution, and facilities used for transmi ssion of energy wholly consumed by the
transmitter.

Commenters stated that, although EPA considers each state's best system to be one in which all NGCC generators operate at a 70 percent capacity fa ctor, the EPA fails to provide any information as to how a state would go about obtain ing that result. Commenters stated that neither the EPA, the states, nor FERC has the autho rity to order natural gas generators to operate at that or any other capacity factor. Commenters st ated that, while a state PUC, through an IRP, could require a utility to acquire additional NGCC assets, whether those assets will run at a particular capacity factor will depend on market co nditions, including natural gas prices. Commenters stated that the EPA's best system theref ore depends on a factual impossibility: the notion that NGCC units should operate at a 70 perce nt capacity factor when that level of operation is beyond the power of the state to comma nd.

Commenters indicated that the EPA has recognized th at EGU owners and grid operators are subject to various reliability and operational cons traints, and dispatch decisions are based on electricity demand at a given point, the variable c osts, and system constraints; commenters quoted the proposal as saying that it is this "secu rity-constrained economic dispatch [that] assures reliable and affordable electricity" (79 FR 34862). Commenters asserted that state agencies responsible for environmental protection a re not charged with, nor should they be, dispatch of electricity within their own state much less outside of state borders. Commenters added that the CAA does not give states the authori ty to regulate the dispatch of power plants on the interstate grid, which commenters characterized as a fatal flaw in this building block. Commenters stated that the EPA cannot cite any law or rule that permits states to override the FERC to meet air pollution goals, noting that any m arket changes require FERC approval and must be permissible under the Federal Power Act (FP A) - rates must be "just and reasonable" and "not unduly discriminatory or preferential."

Commenters noted that the EPA cites the ability for states to control dispatch by example of the Title IV program (79 FR 34862), but commenters foun d this comparison unpersuasive. Commenters stated that most importantly, Title IV w as approved by Congress under the CAA and this proposal has not been. Commenters added th at under programs such as Title IV, it is the individual source that is regulated, not the entire power system - individual EGU owners decide how best to comply with their allocations, whether it is through reduced operation or the
installation of a control device. Commenters indica ted that under Title IV, an individual EGU
that installs an environmental control device can a ctually operate more frequently than one that does not; the decision is made based on what is nec essary to reduce emissions inside-the-fence
based on allocations received. Commenters asserted that the EPA is not comparing apples to apples in comparing Title IV and the intricacies of this system-wide proposal.

Commenters stated that EPA's assumption that a stat e has the ability to re-dispatch large blocks of capacity and generation from existing coal-fired EGUs to existing NGCC EGUs, in most cases, is incorrect. Commenters stated that State e nvironmental agencies do not have authority to require such re-dispatch, and, in fact, some states do not have such legal authority at all. Commenters stated that setting emission rate goals based on such an assumption exceeds EPA's authority under Section 111(d). Commenters suggeste d the states are in the best position to determine whether existing NGCC capacity can, in fa ct, supplant existing coal fired EGUs taking55

into account transmission constraints, gas supply l imitations, remaining useful life, contractual obligations of NGCC owners, load pockets, location and actual capacity of NGCCs (including climatic and altitude considerations) environmental constraints (some NGCCs are limited by air permits due to proximity to non-attainment areas) a nd market limitations.

Commenters stated, because the current generation m arket is controlled and regulated by many agencies (FERC, NERC, the Commodities Futures Tradi ng Commission (CFTC), RTOs/ISOs), the EPA and state environmental agencies cannot ord er the market. Commenters stated FERC's role under the Federal Power Act (FPA) is to ensure that the power market is fair and that just
and reasonable rates are maintained. Commenters sta ted that, while the EPA's IPM calculates the cost of carbon to be between $40 and $50/ton of CO2 and determines that this range of cost can
be modeled to result in the market shift that Build ing Block 2 is trying to force, the EPA, however, cannot incorporate this carbon proxy cost into the market price of electricity.

Commenters stated that neither EPA, FERC, nor the s tates' as they have currently configured their institutions have the authority to decree a 7 0% capacity factor for gas plants. Commenters stated the "unadministrability" of building block 2 provides further evidence that the Proposed Plan will not survive judicial review under the pri nciples stated in UARG.

Commenters stated the EPA and state environmental a gencies cannot order the market to become
uneconomical or unreliable. Commenters stated this market is controlled and regulated by many agencies (FERC, NERC, the Commodities Futures Tradi ng Commission (CFTC), RTOs/ISOs).
Commenters stated FERC's role under the Federal Pow er Act (FPA) is to ensure that the power market is fair and that just and reasonable rates a re maintained. Commenters stated that, in its IPM model, EPA calculates the cost of carbon to be between $40 and $50/ton of CO2 and determines that this range of cost can be modeled t o result in the market shift that Building Block 2 is trying to force. Commenters stated the EPA can not incorporate this carbon proxy cost into the market price of electricity. Commenters stated that, due to this, all of the volatility and instability that entities managing the market work to avoid will occur. Commenters stated capacity factor is a function of unit availability and cost. Commenters stated that, in MISO, plant efficiency, demand, cost of fuel, and transmission constraints all play a role in determining which plants run and when. Commenters stated supers eding current market design with a requirement to run certain units regardless of trad itional dispatch factors counters the long term resource planning used by RTOs.

Commenters asserted that states operating in compet itive energy markets cannot increase utilization without supporting market mechanisms an d signals. Commenters stated that, if the EPA left the standard-setting approach up to each s tate, and allowed time for market mechanisms to be developed and implemented, it is possible tha t Building Block 2 principles could be captured in state plans.

Commenters stated the EPA does not have primacy on regulation of the nation's electric grid and natural gas transmission and distribution infrastru cture. Commenters stated the EPA's authority under Section 111(d) of the CAA is to best protect the public from excessive emissions from affected facilities, not to limit operations of tho se affected facilities. Commenters stated that dispatching lower carbon sources to displace existi ng coal-fired generation is not a system of emission reduction, and dispatch priority is outsid e the purview of the CAA. Commenters stated56

they cannot see how a congressionally authorized 11 1(d) rulemaking process can dictate that states (e.g., legislators, Michigan Public Service Commission), independent system operators (e.g., MISO), and reliability organizations (e.g., ReliabilityFirst), somehow craft a system that dispatches the electric generation fleet on a compl etely new basis.

Long-Term Contracts

Commenters asserted that states have no authority t o require that NGCC units abrogate existing bilateral contracts (such as Power Purchase Agreeme nts) between NGCC units and those who purchase electricity from them. Commenters stated t he FPA permits utilities to set rates with individual electricity purchasers through bilateral contracts, though contract rates must be filed with FERC before going into effect. Commenters indi cated that under the filed-rate doctrine, "interstate power rates filed with FERC or fixed by FERC must be given binding effect by state utility commissions determining intrastate rates." Commenters went on to note that when the filed-rate doctrine applies to state regulators, it does so as a matter of federal pre-emption through the Supremacy Clause, and that the filed-ra te doctrine "is not limited to 'rates' per se,"
but rather extends to non-rate terms and conditions , including "contractual provisions, methodologies for allocating costs, restrictions on availability of the [service] as well as quantity and price terms." Commenters concluded that as a re sult, states have no authority to require that NGCC units abrogate existing bilateral contracts (s uch as Power Purchase Agreements) between NGCC units and those who purchase electricity from them. Commenters stated that in calculating possible reductions from Building Block 2, EPA fails to document or account for the number of facilities whose electricity is partially or entirely committed through such contracts.
Commenters noted that the American Public Power Ass ociation estimated that in 2013, twothirds of new capacity in the U.S. was built with P ower Purchase Agreements for the sale of power. Commenters added that while 64 percent of th ese agreements were with a utility, the EPA fails to acknowledge or at all account for the fact that a significant percent of NGCC units will be unavailable for re-dispatch due to long-ter m contractual commitments. According to commenters, these contractual commitments commonly span 10 to 25 years in the Southeast and the West, and project finance contracts in organize d markets have similar timetables. Commenters indicated that plants with 10- to 15-yea r out-of-state PPAs would not be available for in-state re-dispatch as EPA presumes, giving th e example of several hundred MW of generation from a NGCC facility in New Mexico that is committed to out-of-state off-takers for the next 32 years. Commenters added that this gener ation cannot be presumed available for redispatch in New Mexico. Commenters stated that the EPA also assumes, under Building Block 2, that any increases in capacity at NGCCs will be eli gible for re-dispatch, again ignoring the potential impacts of long-term agreements. Accordin g to the commenters, if a facility has committed the entirety of its electrical output to a counterparty under a long-term Power Purchase Agreement, then even if it could increase its output, it may not be able to sell the incremental additional output into the wholesale ma rkets. Commenters also stated that a Power Purchase Agreement may also contain a provision req uiring the buyer's consent before modifications may be made to the subject facility. Commenters concluded that as a result of these omissions, the EPA overestimates the amount o f electricity eligible for re-dispatch under Building Block 2.

Regional Markets57

Commenters also stated that EPA ignores the fact th at a number of states are located in more than one regional market. Commenters stated that po rtions of Arkansas and South Dakota are in the SPP and other portions are in MISO; SPP, PJM, a nd MISO cover some of all states and only parts of others; and the Electric Reliability Counc il of Texas (ERCOT) covers only part of Texas. Commenters noted that, in South Dakota where EPA's best system would significantly reduce generation at the Big Stone coal plant and replace it with generation from the Deer Creek NGCC plant, the dispatch of these units is controlled by two different operators and therefore they are not seamlessly integrated. Commenters stated that D eer Creek is dispatched through the region's Integrated System (IS), operated by Basin Electric and the Big Stone unit, on the other hand, is dispatched into MISO. Commenters stated IS/SPP and MISO do not share a dispatch signal that would allow one plant's increased operations to res ult in the lower dispatch of a plant operating in a different market, nor would there be any econo mic or logical reason to dispatch the units in a coordinated fashion given that they serve different markets. Commenters also noted that these two plants were built to their particular size and in their particular locations to serve the needs of their utilities' customer bases, not those of other utilities and each of the owners of these plants possesses firm transmission rights to ensure that t he generation reaches load.

Commenters stated the proposal does not take into a ccount how the organized markets of an
RTO like PJM function. Commenters asserted that sta tes that have restructured their electric markets have effectively relinquished both jurisdic tion over EGUs in their states and operational control over EGU dispatch and the transmission syst ems that deliver the energy from the EGUs to the RTOs. Commenters stated that, in the restruc tured states, the EGUs rely on RTO market signals sent by FERC jurisdictional wholesale marke ts to set the price at which they will offer their energy, capacity and other products into the market. Commenters stated those federal, wholesale market signals also serve as indicators f or whether the EGUs should continue to invest in ongoing operation and maintenance expenses. Comm enters asserted that States no longer have the ability to intervene to direct which resources are operated, constructed, or maintained. Commenters stated that, while states that have reta ined or returned to traditional regulation have some control over EGUs and how they are dispatched, restructured states have little to none.

Commenters stated the EPA's analysis of Building Bl ock 2 fails to consider that many states have deregulated their electricity markets, meaning that dispatch calls are made entirely by FERC-regulated regional transmission operators. Com menters stated that Pennsylvania, for example, has turned over these operations to PJM an d, as a result, Pennsylvania cannot directly regulate which facilities under its jurisdiction ar e called up to deliver electricity at any given time. Commenters stated that, unless and until EPA addresses this issue, any final rule relying on re-dispatch would be unsupported by the record.

Commenters stated that the EPA cannot assume states have jurisdictional control over the dispatch of electricity. Commenters stated the EPA should not assume that all of the NGCC plants are owned and operated by the same entity th at owns and operates coal-fired generation,
nor should it assume that the run/not run decisions are within the state's decision-making authority, or even within the decision-making abili ty of a single market regulator or system operator. Commenters stated that utilities that are members of the Midcontinent Independent System Operator (MISO) regional transmission organi zation rely on MISO's dispatch process and have no authority to override, force, or modify this process. Commenters stated that the state also has no authority over this dispatch process an d no mechanism to force or modify dispatch of58

these plants. Commenters stated the EPA has failed to explain how the state could control the dispatch of these NGCC plants given current Federal Energy Regulatory Commission (FERC) regulations. Commenters stated the EPA assumed a 70 percent utilization rate of all NGCC in the state without regard to how these units are dispatc hed by the utilities and Regional Transmission Organizations (RTO) and the USEPA has not identifie d any tools to do this and has not addressed federal regulatory barriers. Commenters s tated that, in Michigan, the majority of the NGCC capacity is dispatched by the RTO and the stat e has no authority over this dispatch process and no mechanism to force or modify dispatc h of these plants. Commenters stated that, in Michigan, one NGCC plant that is owned and opera ted by an Independent Power Producer will soon be dispatched via a proposed direct trans mission line that leads out of the state; in this case, even a Michigan CO2 price-forcing dispatch wi thin MISO for electricity sold in Michigan would have no effect on this plant's generation sin ce it is being bid, sold, and supplied into
another RTO.

Commenters stated there are limits on states' autho rity to mandate re-dispatch. Commenters stated that MISO, like all system operators, dispat ches electricity on a priority basis of (1) reliability and (2) least costs. Commenters stated that, because compliance obligations and costs differ greatly among states, it would be impossible for a unit in one state to determine the bid price necessary to ensure that it would or would no t be dispatched before generating units in other states within the MISO region. Commenters sta ted this is further complicated in states that fall within multiple regions, such as South Dakota. Commenters stated the EPA assumed that generation from Deer Creek could be increased and, as a result, generation from Big Stone decreased; however, because Big Stone and Deer Cree k participate in different markets, the presumed increase in generation from Deer Creek cou ld not displace load requirements for Big
Stone.

State-Specific Concerns

Commenters stated the EPA has simply ignored the fa ct that states like Indiana do not have authority over the market dispatch of electric gene rating units located in its state; that authority i s held by regional transmission organizations, in thi s case MISO, and to a lesser extent PJM. Commenters stated that the Indiana Department of En vironmental Management (IDEM) does not have dispatch authority as referenced in building b lock 2 that MISO and PJM have. Commenters asserted Indiana does not have regulatory authority to control the dispatch of electricity within its own borders, let alone on a regional basis, and thu s lacks the authority to implement Building Block 2. Commenters stated that, even if the state were to establish the authority to mandate dispatch of electricity from NGCCs at a certain lev el of capacity, implementation would have to be conducted by an RTO, not the state. In that case , commenters stated Indiana would not be in a position to properly oversee and enforce implementa tion, or ensure adequate recordkeeping.

Commenters stated the EPA's simplistic appraisal an d approach to the process of dispatch does not reflect the underlying wholesale market dynamic s of a state's power sector. Commenters stated the EPA must revise how it applies building block 2 in goal setting because it must reflect
realistic and reasonable outcomes. Commenters state d the EPA's algorithm governing building block 2 results in emission reductions through the displacement of all coal and oil-fired generation with existing NGCC generation in New Jer sey, which, according to Commenters is
not a realistic or reasonable outcome. Commenters s tated that in deregulated markets, such as in59

New Jersey, the dispatch of units is determined by economic merit. Commenters offered that states can influence dispatch, as New Jersey has do ne, through environmental regulations and energy policy; however, there is no direct and auto matic correlation between a decrease in operation of in-state affected coal and oil-fired u nits and the increase in operation of an in-state affected NGCC. Commenters stated the EPA's approach is merely an academic exercise that assumes the affected in-state NGCC will only displa ce affected in-state coal and oil-fired generation. Commenters stated that, as EPA defines "affected EGU", New Jersey's in-state affected generation comprises approximately 40% of New Jersey's annual in-state power generation (from only 30% of New Jersey's electric generating capacity) and dispatch may be provided by a multitude of various source types thr oughout the PJM region.

Commenters indicated that the Pennsylvania DEP and the Pennsylvania Public Utility Commission (PA PUC) lack the authority to dispatch EGUs, and there is no practical way for Pennsylvania to implement Building Block 2. In Penn sylvania, commenters said, the dispatch of generating units is under the direct control of PJM Interconnection, LLC (PJM), which does not have the authority to act as an environmental regul ator and must dispatch units based on its tariff. Commenters said that Building Block 2 should not be included in the determination of BSER because re-dispatching from one stationary source c ategory to another category is not consistent with BSER as prescribed in the CAA.

Commenters also stated that in Ohio it is the EGU o wners who decide in what manner to bid into the electricity market and for how much time, and i t is PJM, under the authority of FERC, who determines dispatch order based on utilizing the le ast expensive resource first to meet energy
demand. Commenters asserted that it is not within O hio EPA's authority to require NGCC sources increase dispatch to a certain percentage u nder a Section 111(d) plan, and that states do not have the ability to force an operator to run a NGCC unit at over 70% utilization. Commenters indicated that this creates unanswered questions: W hat happens if natural gas prices significantly increase and the natural gas unit will not be able to operate profitably? What if a unit suffers a major equipment breakdown? Will the units be in vio lation if 70% utilization is not achieved? Commenters contended that the proposal could lead t o the situation where a NGCC unit must operate to achieve the 70% utilization value even i f the electricity is not needed. Commenters stated that this element of the proposal must be dr opped from further consideration.

Title V Permit

Commenters noted that the EPA suggested that states could implement increased re-dispatch of NGCC by limiting the operation of coal-fired EGUs t hrough permits (79 FR 34862). Commenters stated that to restrict operation in a T itle V permit, such limitations would need to be included in a federally approvable plan but stil l could not override other federal laws outside of the CAA. Commenters asserted that placing a spec ific limit on the number of hours a baseload coal-fired EGU could operate reflects the EPA' s lack of knowledge on the federal mandates of large utility plants to operate for reliability purposes.

Comment 14: Commenters said that not all EGU owners have the ab ility to dispatch NGCCs and CHP facilities to higher capacity factors.60

Response 14: The EPA disagrees. The 111(d) final rule requires that states develop plans that

establish emission standards for affected EGUs. We are providing states with substantial flexibility as to how they structure those plans to achieve the 111(d) requirements. The flexibility includes, for example, the choice of approaches, tr ading, time to develop plans, additional time before the start of the interim performance period (postponed from 2020 until 2022), and the ability to shift emission rate achievement between performance periods. In response to additional analysis and many comments, we have modified the pr oposal and RIA – the establishment of CO2 emission reduction standards is regionally base d. The Building Blocks are not prescriptive, and states may consider local circumstances as they develop their plans, including system reliability, fuel diversity, the “useful life” of g eneration assets, other regulatory requirements and infrastructure. See sections V.A, V.D, VIII.A, VIII .C and VIII.G of the final rule preamble of the CPP and Chapter 3 of the GHG Mitigation Measures TS D for the CPP Final Rule supporting the

final CPP.

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

Commenters said that the EPA's assumption that "aff ected sources may themselves implement the measures included in building blocks 2, 3, and 4, so that those measures are within their control" (79 FR 34889) is faulty and unsupported as sumption. Commenters said that a utility company whose fleet of affected EGUs is entirely co mprised of NGCC units cannot simply decide to re-dispatch their units at a 70% capacity . Commenters stated that facilities may be ordered to either increase or decrease generation b y the regional authority to ensure the integrity of the electrical grid. Commenters added that there are aspects of Block 2 that are clearly outside the authority of the affected sources, e.g., utilit y companies with fossil fuel-fired EGUs do not necessarily have authority over the transmission sy stem which may be operated and controlled by an entirely separate entity. Commenters said tha t an entity which has no affected sources is not only beyond the control of the affected utility companies, but is also completely beyond the EPA's legal authority.

Commenters stated that new legislation would be req uired if, as the EPA' s IPM model indicates, the State of Louisiana will likely find its best co mpliance option to be to direct the retirement of RPS-2. Commenters stated that Lafayette Utilities S ystem (LUS) would be required to replace more than 50% of its generating capacity and more t han 63% of its energy requirements with other generation alternatives. Commenters stated th is would take new legislation, as neither LUS nor the municipalities that comprise the Louisiana Energy and Power Authority, are subject to Louisiana Public Service Commission regulation.

Commenters stated that the responsibility to achiev e the emission performance level may be assigned solely to EGUs, but it leads to some qu estionable scenarios. Commenters stated that one scenario is when a regulated unit is subject to a System Support Resource Agreement (SSR) that requires a unit to operate to maintain system reliability. According to commenters, Michigan has three power plants in the Upper Peninsula that are subject to an SSR Agreement: the Presque Isle Power Plant, the City of Escanaba Plant, and W hite Pine No. 1. Commenters asked, if a unit cannot run because of a CO2 limit, how would this i nteract with a SSR ordered by FERC?
Commenters said that the state has no control over dispatch or SSRs, and the EPA should explain how the interrelationship between CO2 dispatch and a SSR order could work under this rule.61

Comment 15: Commenters asserted the EPA failed to describe the mechanisms states can use to develop and implement an approvable plan.

Response 15: The EPA disagrees. In response to additional analys is and many comments, we have modified the proposal and RIA. The 111(d) fin al rule requires that states develop plans that

establish emission standards for affected EGUs. We are providing states with substantial flexibility as to how they structure those plans to achieve the 111(d) requirements. The flexibility includes, for example, the choice of approaches, tr ading, time to develop plans, additional time before the start of the interim performance period (postponed from 2020 until 2022), and the ability to shift emission rate achievement between performance periods. EPA believes that the preamble of the final rule describes mechanisms tha t a state may use to develop and implement and approvable plan. See sections V.D, VIII.A, VIII .C and VIII.G of the final rule preamble of

the CPP.

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

Commenters stated that the EPA has failed to descri be the mechanisms states can use to develop and implement a plan that will reliably demonstrate compliance. Commenters explained that Building block 2 cannot require states to interfere with the economic dispatch or reliable operation of the grid because states cannot interfe re with the existing regulatory authority and enforcement responsibility of the federally authori zed agencies that control unit dispatch decisions and plan for the reliable operation of th e electricity grid. Commenters stated that it is unclear how EPA would envision a regulatory require ment be structured and enforced to achieve the types of redispatch assumptions that were used to derive the state goals. Commenters indicated that a review of recent permits for NGCC units and other fossil units and found no examples of facilities that have an enforceable min imum capacity factor limit. Commenters stated it is unclear how EPA's assumed capacity fac tor could be effectively implemented and
enforced because of various uncertainties related t o whether the design, support infrastructure, and current permits and regulatory requirements for the existing NGCC fleet are sufficient for all units to sustainably achieve a 70% capacity factor. Commenters stated the EPA's own modeled outputs indicate that the targeted 70 percent capac ity factor used to create the state goals would not in fact be achieved by the proposed CPP. Commen ters asserted that the EPA must explain how states could develop a plan that produces resul ts its own model refutes, or recognize that the proposal does not accurately reflect the operation of the electricity grid.

Commenters stated it is unclear based on the text o f the proposed rule whether the power plant operator or MISO would be responsible for establish ing compliance with Building Block 2 for the purposes of enforcement. Commenters stated it i s also unclear what the legal implications would be if, for example, Indiana included a carbon price in its 111(d) Plan, EPA approved that Plan, and then Indiana's NGCC plants operated at an average capacity factor of less than 70 percent in any given year. Commenters stated that t he notion that a pricing or permitting scheme can be reliably correlated with a specific operatin g threshold at EGUs lacks empirical support and accomplishing such a task would require accurat e long-term forecasts about the future trajectory of electricity use decades into the futu re, something even the federal government admits is beyond its capabilities.62

Commenters stated that the EPA's Building Block 2 i s based on the faulty premise that generation from any NGCC unit located within a stat e may be redirected by a utility or state within the state's borders to offset reduced genera tion from coal-fired units elsewhere in the state. Commenters stated that, in most states, electric ge neration is dispatched by an RTO or ISO, which calls up generation from EGUs within its syst em such that the lowest cost generating sources are dispatched first; thus, as an initial m atter, neither a utility nor any state agency controls the relative dispatch of coal-fired EGUs a nd NGCC units in most states. Commenters stated that the areas covered by RTO and ISO system s typically do not coincide with state borders; rather, an ISO's footprint includes genera ting units in several states, and some states are divided between multiple ISOs. Commenters stated th at, as a result, it is common for EGUs within a state to be dispatched based on direction from different managing authorities, and for
EGUs to serve load outside of the states in which t hey are located. Commenters added that there may be limited interconnection between the differen t dispatch systems in a state, and EGUs in one part of a state may lack the cross-state transm ission rights needed to serve load in a different part of the state.

Commenters stated that it must be recognized that n atural gas pipelines are not subject to the proposed rule, and thus are under no regulatory obl igation to undertake the necessary expansion. Commenters stated that, even if they were to initia te expansion efforts immediately, it is reasonable to expect that such expansion would take at least a decade to complete at a cost of many billions of dollars.

Commenters noted the EPA requested comment on wheth er it should use MWh from the increased utilization of NGCC units in Building Blo ck 2 to decrease generation from a state's coal-fired EGUs before decreasing generation from t he state's oil/gas-fired steam units (79 FR 64545). Commenters stated the EPA neglects to provi de technical analysis for this alternative approach and, therefore, the EPA has no sound basis for adopting it; i.e., simply wanting to maximize emission reductions is not a justification for the change. Commenters stated that the EPA has no authority to dictate which units are dis patched first, last, or otherwise and the EPA should not attempt to force state environmental age ncies to usurp the authority for dispatch decisions which are made by utilities and independe nt system operators with oversight by state utility commissions and the Federal Energy Regulato ry Commission. Commenters stated the decision making authority to increase the capacity factor of NGCC units as well as whether to dictate whether reductions come first from coal gen eration or oil/gas generation is based on a number of factors and clearly does not belong to EP A and therefore should not be considered.

Commenters referred to comments made by Nevada DEP et al. ("Agencies"), who question whether EPA has jurisdiction to authorize re-dispat ch of various EGUs to achieve emissions reductions, and stated that they do not see this as a major shift from other Clean Air Act strategies to reduce criteria pollutants including ozone or PM.

Comment 16: Commenters stated that Alaska should be exempted fr om the Proposed Rule because the state cannot reasonably implement BSER, in part because re-dispatch as described by the EPA under building block 2 is not feasible i n the state. In the alternative, commenters stated that the goal calculation for Alaska should not include any provision for re-dispatch.63

Response 16: Alaska is not included in the final rule at this t ime.

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

Commenters stated that under building block 2 for A laska, the EPA reassigned the 2012 baseline generation at Healy Unit 1 to NGCC units to arrive at a final goal of 47% capacity factor for Alaska's NGCC units. (Commenters noted that the cal culation does not account for Healy Unit 2.) Commenters asserted that the EPA's assumption t hat all generation at the Healy Power Plant could be displaced by NGCC generation is false, bot h because of the transmission system
limitations discussed elsewhere in the comments and because of the planned retirement of the Beluga and Sullivan NGCC EGU's. Commenters explaine d that the Healy Power Plant will provide a total of 80 MW of generation capacity for the Fairbanks load center, and provided the following information about the plant:

The plant is located adjacent to the Usibelli Coal Mine and has two coal-fired steam generating units. Healy Unit 1 commenced generation in 1967 an d has a gross capacity of 27 MW. Healy Unit 2, or the Healy Clean Coal Project, has a name plate capacity of 52.5 MW and, like Healy Unit 1, uses the locally produced coal. GVEA is inv esting significant resources to reconstruct Healy Unit 2. This includes $190 million in investm ents and a recent consent decree with EPA requiring additional pollution control measures at both Healy units. The Healy Power Plant is connected to Fairbanks, 97 miles to the north, by t wo transmission lines owned and operated by
GVEA.

Commenters stated that the NGCC EGUs that EPA's goa l computation assumes can replace Healy's 80MW of coal generation are located more th an 200 miles south of Healy, beyond the other end of the Alaska Intertie. According to the commenters, this 80 MW transmission line is already generally operated at capacity to deliver h ydroelectric and natural gas generation to GVEA's customers in the Fairbanks load area, and th ere are no NGCC EGUs connected to the
Fairbanks load center other than those connected th rough the south end of the Alaska Intertie. Commenters added that the Healy units provide volta ge support to the Intertie, so that if the Healy units were not operating, the loss of the Hea ly SVC would result in a reduction of transfer capacity of approximately 1l MW. Given the current generating and transmission resources,
commenters asserted that Alaska cannot execute the second building block. Commenters stated that, hypothetically, GVEA could have two options t o replace Healy power: (1) upgrading the Alaska Intertie to allow more power north or (2) ge nerating power locally from other fossil-fuel
fired units. Commenters asserted that both scenario s would substantially increase the cost of power in Fairbanks (already among the most expensiv e regions in the country for power), raise serious resource availability and reliability conce rns, and compromise the state's ability to address the PM2.5 non-attainment finding for Fairba nks. Commenters believed that these options
are not realistic.

Commenters went on to state that if the rule is app lied to Alaska, the goal calculation should not include any provision for re-dispatch from coal uni ts to NGCC units because, as discussed above, the coal and NGCC units in Alaska are separa ted by over 200 miles, the state's transmission capacity is already used to its limit, and reliance on the single contingency line would have significant implications for reliability and resource adequacy in the Fairbanks area. Commenters concluded that Alaska cannot re-dispatch coal generation at a reasonable cost.64

Comment 17: Commenters stated building block 2 does not provide compliance options in

certain cases.

Response 17: The EPA disagrees. We are providing states with sub stantial flexibility as to how they structure their plans to achieve the 111(d) re quirements. The flexibility includes, for example, the choice of approaches, trading, time to develop plans, additional time before the start of the interim performance period (postponed from 2 020 until 2022), and the ability to shift emission rate achievement between performance perio ds. The Building Blocks are not prescriptive, and states may consider local circums tances as they develop their plans, including system reliability, fuel diversity, other regulator y requirements and infrastructure. See sections V.D, VIII.A, VIII.C and VIII.G of the final rule pr eamble of the CPP and Chapter 3 of the GHG Mitigation Measures TSD for the CPP Final Rule supp orting the final CPP.

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

Commenters stated building block 2 does not provide Owensboro Municipal Utilities (OMU) with options for compliance because Kentucky has no operating NGCC plants and only one NGCC facility under construction. Commenters st ated that, at the time of the issuance of the proposed rules and as of December 1, 2014 there wer e no operating natural gas combined cycle units in Kentucky and, while Cane Run 716, the firs t CCGT in Kentucky is under construction and there are other units planned by TVA at the Par adise Steam Plant17, OMU and other LGE/KU transmission system participants have no acc ess to such units. Commenters stated that OMU, like all but 13 original TVA interconnected ut ilities, is prohibited from buying from TVA and thus, these future CCGTs provide no compliance option to OMU. Commenters stated that bringing CCGT energy into OMU from TVA is possible but would entail incremental transmission cost and a capacity purchase agreement with an IPP in TVA. Commenters stated such a mandated power purchase agreement as a condi tion of OMU's compliance plan is most likely a violation of the Federal Power Act.

Commenters stated that bringing CCGT power into the LGE/KU control area to serve OMU load
from MISO or PJM entails increased transmission cos t and would be subject to recall during Maximum Generation Events. Commenters stated that, in Kentucky there is a lack of natural gas infrastructure: there are no existing NGCC plants i n Kentucky and the natural gas supply and delivery infrastructure does not exist to sustain a forced conversion to a significant percentage natural gas based generation in a state where 93% o f electric generation is from coal. Commenters stated that, even if this were the most cost effective option for Kentucky's EGUs in a final rule, sufficient time to site, permit, engi neer, procure and construct the required pipeline and natural gas storage capacity is impossible by t he interim compliance date. Commenters stated that, for a FERC regulated pipeline company to build new natural gas pipeline, they would first require a firm commitment from shippers on th e proposed pipe before FERC would authorize the project. Commenters stated the propos ed rule and the RIA did not adequately
account for the time of the construction of the nec essary natural gas pipelines or the cost to complete.65

Comment 18: Commenters asserted Florida’s import transmission c apability is limited.

Response 18: The EPA disagrees. EPA is fully aware of transmis sion constraints for imports and exports to FRCC. We assume this is what the co mmenters mean, since FRCC is only the peninsular part of Florida, and transmission into c oastal Florida is served by other transmission lines and not subject to this constraint. EPA uses 3600MW for this limit, not 3800MW; please see the IPM model documentation at http://epa.gov/p owersectormodeling. In response to additional analysis and many comments, we have modi fied the proposal and RIA – the
establishment of CO 2 emission reduction standards is regionally based. The 111(d) final rule requires that states develop plans that establish e mission standards for affected EGUs. We are providing states with substantial flexibility as to how they structure those plans to achieve the 111(d) requirements. The flexibility includes, for example, the choice of approaches, trading, time to develop plans, additional time before the s tart of the interim performance period (postponed from 2020 until 2022), and the ability t o shift emission rate achievement between performance periods. The Building Blocks are not pr escriptive, and states may consider local circumstances as they develop their plans, includin g system reliability, fuel diversity, other regulatory requirements and infrastructure. The rul e provides Florida with the flexibility to meet the requirements in many different ways. See sectio ns V.D, VIII.A, VIII.C and VIII.G of the final rule preamble of the CPP and Chapter 3 of the GHG Mitigation Measures TSD for the CPP Final Rule supporting the final CPP.

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

Commenters stated that, while the Proposed GHG Rule limits re-dispatching to within a region's existing fleet (79 FR 34865), Florida's import tran smission capability is limited to approximately 3,800 MW, or 6.6% of total capacity. Commenters sta ted that Florida's geographical location and corresponding energy import limitations should mini mize reliance on regional dispatch hypotheticals and confine Florida's re-dispatch inc reases (for Final Goal computation) to those within the State going from 61 to 70 percent.

Comment 19: Commenters expressed concern that the implementatio n of Building Block 1 and Building Block 2 will work against each other.

Response 19: The response to this comment is addressed in sectio n 3.1.1 of the RTC.

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

Impacts on Heat Rate

Commenters stated the EPA's goal of shifting coal g eneration to natural gas would result in increased heat rate for coal plants. Commenters pro vided the following additional information:66 • Commenters stated that implementation of Building B lock 2, including the redispatch from coal to NGCC, would undermine Buildin g Block 1 because, if Plant Lowman is forced to provide load following and anci llary services due to the increased dispatch of NGCC, Plant Lowman's heat rat e is likely to increase because operational stability is the single largest factor in heat rate.

• Commenters stated Building Blocks 1 and 2 are econo mically inconsistent, since on the one hand, Building Block 1 assumes emission reductions from heat rate improvement projects at existing coal-fired boilers , while on the other hand, Building Block 2 assumes increased utilization of N GCC units at the expense of
coal-fired units. Commenters stated the EPA fails t o acknowledge this inconsistency.

• Commenters stated Building Block #2 will negate som e if not all of the heat rate improvements from Building Block #1. Commenters sta ted heat rate is increased when plants operate at lower loads, and the benefit of a heat rate improvement strategy is reduced at lower loads. Commenters stat ed that, if an existing EGU is currently base-loaded, as San Miguel operates, and shifts to a load-cycling operating profile in the future, that unit's annual average heat rate will increase, and the heat rate reduction strategy (or strategies ) implemented will not lower the annual average heat rate as much when compared to b ase-load operation. Commenters stated that, in some cases, any HRI impr ovements achieved by undertaking the relevant options described in Build ing Block #1 could be negated by load-cycling. Commenters referred to section 5 o f the S&L report performed for the NRECA and stated the following:

S&L evaluates the impacts on cycling load on HRI me thods. See table 7, page 15 of Attachment B - impacts on heat rate to each of the HRI methods . As part of the evaluation S&L examined six plants to understand how varying dispatch loads aff ect the heat rates of the units. San Miguel was one of the units examined; see pages 22 through 24 of Attachment B. During the time frame evaluated - years 2012, 2013 and through July 2014 - San Miguel was mainly base loaded with increased cycling in the spring of 2014. This can b e seen by the average operating capacity factors (AOCF) - 96%, 95% and 87% respectively and graphically represent in Figure 6 by the Dispatch net load by date. S&L also evaluated heat rate over the operating range - figure 7 and
table 10 of Attachment B - net unit heat rate incre ase over 1,500 Btu/kWh from high load to low load. This is a greater than 13% increase in heat r ate. S&L stated, "as the AOCF decreases in 2014, the annual average net unit heat rate increas ed by nearly 6% from the previous year". This indicates that if HRI did improve by 6% those gains would be lost by the effects of Building
Block #2.

• Commenters stated that, while the goal of the build ing block 2 is to reduce the

operation of the coal-fired EGUs and reduce CO2 emi ssions, analysis shows that the efficiency of the Wisconsin coal-fired EGU flee t could fall as much as 5% due to heat rate increases brought on as a result of ap plying building block 2 as proposed by EPA. Commenters stated that, given thei r preliminary estimates show that the achievable HRI for vintage Wisconsin coal-fired EGUs is estimated to range between 0.5% and 2.3%, any CO2 reductions achieved by building block67 1 are more than offset by the inefficiencies caused by building block 2; specifically, the result is a net loss of over 3% e fficiency for Wisconsin's coalfired fleet. Commenters stated this result is contr ary to the intent of BSER and further supports the conclusion that Wisconsin's ma ximum NGCC capacity factor
should not exceed 37%.

• Commenters stated that, under the Proposed Rule, co al-fired EGUs would shift from providing baseload generation to cycling and/o r increased load-following operation and, as a result, coal-fired EGUs would b e operating at lower capacities with intermittent increases to meet peak demand. Co mmenters stated that coalfired EGUs are not designed for load-following and cycling, which reduces their efficiency, thereby increasing heat rates. Commente rs stated a coal-fired EGU's heat rate is highest (i.e., least efficient) at the minimum load point at which the unit can safely operate. Commenters stated that ext ra energy is required to shift a unit from low to higher loads to overcome inertia i n the system. Commenters stated the more frequently a unit must move up and down the load curve, the more excess energy will be required to produce the desir ed load and, thus, the unit will be less efficient on average.

• Commenters stated that, under the Proposal, coal un its would be operated more as peak demand units even though coal units operate mo re efficiently as base load units. Commenters stated that, if coal units are re quired to constantly change energy output then the units will be operating at l ess than peak efficiency and will not be able to obtain measurable heat rate improvem ents.

• Commenters stated that cycling solid fuel units inc reases maintenance costs and
shortens the unit's useful life as well as increasi ng emissions during the prolonged start-up and shutdown periods.

• Commenters stated that decreased utilization of coa l plants under Building Block 2 would result in greater costs and lower efficienc y associated with running these plants at reduced capacity. According to the commen ters, when fossil-fueled generators cycle on and off or ramp down to minimum generation, the thermal cycling of the components can lead to fatigue, cree p, and fatigue-creep interaction, resulting in increased maintenance and repair. Commenters added that load-following operation also creates more opportun ities for component failure because of the thermal, mechanical, and electrical cycling of equipment and systems and results in less efficient operation and higher CO2 emissions per MWh, with the heat rate of an existing 425 MW coal- fired EGU increasing exponentially when it is operated at lower capacity factors.

• Commenters stated that, while AEPCO can attempt to reduce utilization of its highest carbon intensity sources, it must also meet its members' load requirements and, thus, reduced utilization thus must be underta ken in conjunction with another alternative, purchase or construction of another ge neration asset, or market power purchases. Commenters noted that reduced utilizatio n also adversely affects the heat rate of the EGU compared to full utilization.68 • Commenters stated that, as NGCCs become baseload re sources under the proposed rule's dispatch assumptions, coal units op erating at reduced loads and simple cycle peaking units operating at increased c apacity factors will likely replace NGCCs as intermediate, load-following units in many parts of the country. Commenters stated this type of operation r educes coal unit efficiency and
would tend to worsen their emissions rates and coul d result in higher emissions than was assumed by EPA as a result of the re-dispa tch step. Commenters stated that, in analyzing the proposed rule, EPA failed to consider the effect of increased coal unit ramping and simple cycle peaking unit uti lization when determining the level of emission reduction achievable by NGCC re-d ispatch. EPA should also analyze the need for increased load-following gener ation that will likely occur as renewable generation increases.

• Commenters stated that cycling coal-fired units on and off could lead to increased pollution from unit startup and shutdown.

• Commenters stated the re-dispatch of coal-fired gen eration to NGCC generation will necessarily reduce base-load coal-fired EGUs t o load-following EGUs, resulting in significant degradation of heat rate a t the coal-fired units which will offset all or part of the lower CO2 emission rate o f the NGCC unit. Commenters stated the degradation of heat rate caused by requi ring a coal-fired EGU that is designed to operate as a base-load unit to continua lly scale generation up and down as re-dispatch to NGCC units occurs will neces sarily decrease thermal efficiency and increase the CO2 emission rate of th e formerly base-loaded EGU. Commenters stated such degradation in heat rate at coal-fired EGUs could also offset any potential heat rate improvements due to equipment upgrades or changes in operation and maintenance practices set forth in Building Block 1, and would impact the economic viability of such upgrades and changes.

Commenters stated that implementation of Block 2 af fects other building blocks and suggested Building Block 2 be calculated first, then Block 1 evaluated after determining which coal units continue to operate based on modeling runs and how the coal and gas units will be dispatched. Commenters stated that increasing the capacity fact or of NGCCs and subsequently reducing the capacity factor of coal units under Block 2 will ad versely affect the heat rate performance of the coal units from Block 1 because coal units will gen erally cycle on and off more frequently and swing load more often when they are used less, decr easing the efficiency of these units. Commenters stated these building blocks are not add itive for this reason.

Commenters stated that EPA must establish a floor f or operation of existing coal-fired EGUs that prevents degradation of their heat rates. Commenter s noted that the real heat rate begins to degrade significantly when the capacity factor for Wisconsin EGUs falls below 50%. Commenters stated that, as a result, the EPA should not allow the capacity factor of Wisconsin coal-fired EGUs to fall below 50% when determining building block 2. Commenters stated that, in applying this criterion, the EPA must also maint ain operation of all of the coal-fired EGUs. Commenters noted that significant investments have recently been made in these EGUs to continue their efficient operation into the foresee able future.69

Discourage Investment

Commenters stated that implementation of Building B lock 2, including the re-dispatch from coal to NGCC, would undermine Building Block 1 because r e-dispatching from Plant Lowman to an NGCC would discourage continued investment at Lowma n, which would make heat rate improvements unlikely. Commenters stated the EPA fa ils to address why EGUs would make heat rate improvements if their utilization is unde rcut by increased NGCC utilization.

Comment 20: Commenters expressed concern that the re-dispatchin g of baseload units from coal-fired EGUs to natural gas units could have uni ntended consequences that could increase the net output rate of CO2 emissions.

Response 20: The EPA disagrees. We do not expect the rule to res ult in over construction of new generation capacity or substantial increases in natural gas demand. We expect substantial reductions in greenhouse gas emissions from the uti lity power sector. In response to additional analysis and many comments, we have modified the pr oposal and RIA – the establishment of CO2 emission reduction standards is regionally base d. The 111(d) final rule requires that states develop plans that establish emission standards for affected EGUs. We are providing states with substantial flexibility as to how they structure th ose plans to achieve the 111(d) requirements. The flexibility includes, for example, the choice o f approaches, trading, time to develop plans, additional time before the start of the interim per formance period (postponed from 2020 until 2022), and the ability to shift emission rate achie vement between performance periods. The Building Blocks are not prescriptive, and states ma y consider local circumstances as they develop their plans, including system reliability, fuel diversity, other regulatory requirements and infrastructure. See sections V.A, V.D, VIII.A, VIII .C and VIII.G of the final rule preamble of the CPP, Chapter 3 of the GHG Mitigation Measures TSD f or the CPP Final Rule supporting the final CPP, and the Regulatory Impact Analysis of th e CPP final rule.

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

Fossil Fuels

Commenters stated that if the EPA's goal is to curb the effects of climate change, then the EPA must revise the proposed rule to ensure that the st andards do not phase out one fossil fuel, coal, just to replace it with another fossil fuel, natura l gas, for power generation. Commenters stated that the market is already pushing the switch from coal to gas, but the rule may assist in accelerating the trend if it isn't carefully design ed. Commenters suggested that goal achievements would be canceled out if states increased CO2 equiv alent during the duration of the plan as a result of increased natural gas-fired power plants.

Commenters expressed concern that the CPP will lead to an over-build of new gas plants, with commercial lives of 30 or more years. Commenters st ated that, while some new gas resources are a necessary part of a clean energy transition, the best scientific consensus is that the entire globe,70

including the US, has to achieve near complete inde pendence from carbon emissions to avoid the worst risk of climate change by 2050; it is critica l to avoid inducing too much new gas technology in 2020. Commenters stated that an overs upply effectively removes the incentive to deploy additional technology; thus locking in a lar ge amount of new gas resources will have the side effect of locking out renewables and other new clean technologies, in both competitive market and regulated utility regimes, for an extend ed period. Commenters stated this lock-out will occur even if renewables become cheaper than t raditional power technologies since it doesn't matter how cheap something is if no one nee ds it at all.

Commenters expressed concern that the CPP could acc elerate the lock-in of large amounts of new natural gas generation, particularly in some re gions, while generally delaying the deployment of tomorrow's cleaner and cheaper renewa ble energy and emerging competitive distributed energy resources. Commenters stated the NRG warns that this could result in the overbuilding of new natural gas plants, which would reduce the incentive to add new renewable generation capacity to the grid, locking out energy resources that are truly clean.

Commenters stated the Proposed Rule's drive to incr ease natural gas consumption would have a negative effect on the expansion of renewable energ y. Commenters noted the EPA finds that, in light of low natural gas prices, market forces alon e may already lead investors to choose to build new NGCC units, rather than new renewable resources and stated the Proposed Rule's Block 2 exacerbates this market effect by rewarding, as BSE R, the increased utilization of natural forces to favor natural gas power generation. Commenters s tated it will be that much more difficult for RE and EE to retain their current respective share of energy production and avoidance of energy use, much less increase it. Commenters stated the E PA must revise the Proposed Rule so that it incentivizes RE and EE, not natural gas.

Hydro, Nuclear, Solar and Wind

Commenters stated that achieving a set capacity fac tor for a specific fleet of units in states who have instituted deregulated electricity markets wil l be challenging. Commenters stated that, while RGGI-like programs do affect generator bid pr ices and therefore the order of economic dispatch, creating a market signal that grants out- of-merit-order dispatch schedules to a particular technology type would introduce significant market distortions and could result in unintended outcomes, such as higher energy prices and the unde rutilization of wind, water, or other zero emissions resources in favor of a higher-emissions resource the exact opposite of EPA's goal in this rulemaking.

Commenters stated that requiring a 70% NGCC capacit y factor will alter market design, result in less utilization of zero emission resources, and ma ke the attainment of Building Block 3 more costly.

Commenters stated that forcing states to re-dispatc h NGCCs as close as possible to the 70 percent capacity factor would undermine the current and continued integration of renewable energy and, perversely, increase CO2 emissions. Com menters stated that, because CO2 emissions are lower when NGCCs dispatch in concert with renewable energy resources rather than alone, the Proposed Rule would increase, rathe r than decrease, emissions in areas with a high integration of variable energy resources.71

Commenters stated that, while the Smith units and B uck were dispatched significantly above 70% in what are considered peak months, in the rema ining months of October, November, April, and May, nuclear generation supplies the majority o f the utilities' baseload needs. Commenters stated that, in order to achieve the NGCC dispatch target, North Carolina would be required to cycle down nuclear units and dispatch NGCC units in their stead. Commenters stated that, due to their operational characteristics, nuclear units ar e not capable of cycling to allow for NGCC generation during these off-peak months. Even if te chnically feasible, commenters stated that cycling of nuclear generation would be counterintui tive because nuclear generation produces
zero CO2 emissions while NGCC does not. Commenters stated that it is inconceivable that EPA intended such an illogical result when propounding this building block. Commenters stated that any building block based on increased natural gas d ispatch should be directly based on the ability of a state to increase its NGCC units' dispatch con sistent with sound environmental and economic principles. Commenters stated that, based on the data discussed above, the emission
reductions attributed to North Carolina's increased use of NGCC units is overstated and the EPA
should recalculate the emission reductions attribut ed to this building block in light of the additional NGCC dispatch that is technically feasib le in North Carolina.

Commenters expressed concern that Arkansas receives almost zero credit for nuclear and hydroelectric power plants that produce no greenhou se gas emissions.

New York

Commenters stated that the EPA's re-dispatch approa ch fails to account for two important
considerations relevant to New York. Commenters sta ted that (1) the assumed re-dispatch would reduce the output of the impacted steam facilities by over 99%, likely forcing the retirement of units that are critical to reliability and (2) give n the location of NGCC units within New York, the extent of the re-dispatch assumed would require not using available generation from nonemitting resources to "make room" for the NGCC outp ut, undermining the intended impact on
overall CO2 emissions. Commenters stated that the f laws with the Clean Power Plan that would compromise reliability in New York stem from key as sumptions within the Building Blocks that are not technically sound and result in CO2 emissio ns reduction targets for New York that are unreasonable and unworkable within the timeframes p rovided. Commenters stated that no amount of flexibility afforded in the manner in whi ch New York State may seek to comply with the Clean Power Plan can make up for requirements t hat are inherently unreasonable because they are based on flawed assumptions in the Buildin g Blocks.

Commenters stated the EPA's assumed increase in the capacity factor for New York's NGCC EGUs would require a dramatic, highly-uneconomic re -dispatch that would compromise reliability and would actually require backing down lower emitting generation resources.
Commenters stated that most of New York's NGCC EGUs are located in the western part of the state along with the bulk of the state's hydropower and nuclear generation and that operating the NGCC EGUs at the levels assumed by the EPA would pr oduce more electricity than the combined total of the demand in that portion of the state and the transmission transfer capacity to the areas of greater demand to the southeast. Comme nters stated it is not possible to run NGCC resources at the levels assumed by the EPA without reducing the use of generation from nonemitting wind, hydropower, and nuclear units that a re also located in the western portion of the state. Commenters stated it would be illogical and counterproductive to pursue such a re-72

dispatch, as it has the perverse effect of substitu ting NGCC generation for non-emitting renewable generation in the name of reducing CO2 em issions.

Comment 21: Commenters stated that, despite concerns regarding methane leakage, expanded dispatch of NGCC can provide immediate, substantial emission reductions, as the EPA and other observers have recognized.

Response 21: The EPA agrees. See section V.D. of the final rule preamble of the CPP, and the Regulatory Impact Analysis of 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 the much lower GHG footprint of g as-fired generation (as compared to coalbased power) has been confirmed by almost all indep endent observers despite concerns regarding methane leakage (sometimes termed fugitiv e emissions) associated with shale gas production.

Comment 22: Several commenters expressed concern regarding emis sions associated with the natural gas system, such as methane.

Response 22: The EPA disagrees with the apparent presumption tha t methane emissions from natural gas systems rises between the baseline scen ario and a modeled Clean Power Plan scenario. See section V.D. of the final rule pream ble of the CPP and the Regulatory Impact Analysis of the final CPP or the EPA’s response to this comment. Discussion of “fugitive methane,” however is outside the scope of the final rule.

Natural Gas -- Climate Change

Commenters objected to the Clean Power Plan as writ ten because it drives much of the electrical utility generation market to natural gas power over clean energy solutions.

Commenters stated that, although natural gas is cur rently a cheap form of electric generation, it is not a long-term solution. Commenters stated that emerging technologies like wind and solar are rapidly decreasing in price and already employi ng thousands of Missourians. Commenters stated that, with strategic investments to reach ne w economies of scale, wind and solar will soon become the cheapest form of electric generation ava ilable. Commenters stated that, as a nation we should not waste this regulatory opportunity on technologies that will always be based on finite resources that emit large amounts of carbon into our atmosphere.

Commenters stated natural gas is not clean energy. Commenters suggested minimizing the reliance on industries such as coal and natural gas and oil, which will create more demand for renewable clean energy and alternative energy that truly is sustainable.73

Commenters stated that the proposed rule should be improved so that it ensures that states are pursuing renewable energy and energy efficiency as the first priority. Commenters stated that the EPA should not approve compliance measures that wou ld incentivize the construction or utilization of new fossil fuel generation. Commente rs also stated that the EPA should not undersell what states can do with RE and EE, which commenters stated will help states reach their targets more effectively. Commenters stated t hat the proposed rule will increase gas generation with a potential increase of 180 percent by 2020. Commenters stated that no CPP should incentivize the expansion of fracked gas in the electricity sector.

Commenters referred to a Stanford University study titled, "Changing the Game: Emissions and Market Implications of New Natural Gas Supplies" an d stated that the study shows that the shale gas boom produced only modest benefits long-term fo r greenhouse reduction, in part because the increase in natural gas use might discourage effort s to conserve energy and boost efficiency. Commenters noted the Stanford study did not address some of the debate about methane leaks from hydraulic fracturing drillings and other produ ction supply chains steps.

Commenters objected to the Clean Power Plan as writ ten because it drives much of the electrical utility generation market to natural gas power over clean energy solutions. Commenters stated that the NGCC units are energy assets with 30 or mo re years of life that take investment away from clean energy solutions and creates a new green house gas carbon lock-in cycle with natural gas generation plants for the U.S. energy market pl ace. Commenters stated that a 2014 University of California-Irving study makes the cas e that with higher natural gas supplies in various scenarios the renewable energy generation d emand decreases and the potential for greenhouse gas reduction diminishes. Commenters sta ted that the authors of the report argue that only greenhouse gas reduction policy, such as a car bon tax or carbon emission caps will result in significant reductions. Commenters stated the Clean Power Plan will drive too much of the electrical utility generation market to natural gas power plants resulting in a short-term failure to meet greenhouse gas reduction goals and undermining more effective immediate steps with energy efficiency, demand management, energy storag e, and development of existing as well as future renewable energy generation alternatives. Co mmenters stated that the growing transportation markets for electric vehicles depend on a clean energy grid to be truly effective in reducing greenhouse gases, but that clean energy ge neration grid does not exist today in the U.S.

Commenters asserted the Clean Power Plan should pro mote a rapid transition away from fossil fuels towards renewable sources of power, such as w ind and solar. Commenters stated that academic studies question whether natural gas has a ny significant climate benefit over coal because of the leakage of methane, which is 86 time s more potent than carbon dioxide over a 20 year span. Commenters stated that, even without tak ing into account methane leakage, however, natural gas is a fossil fuel that emits greenhouse gas pollution when burned and thus cannot be part of a common-sense solution to climate disrupti on. Commenters stated the Clean Power Plan's promotion of natural gas as an alternative t o coal would continue our reliance on fossil fuels for many decades and incentivizes more invest ment in dirty energy infrastructure.

Commenters stated that instead of promoting the inc reased use of gas, we must transition rapidly to truly sustainable energy sources. Commenters sta ted that increased reliance on fracked gas at best significantly delays and at worst may altogeth er displace the development of solutions such as wind, solar, and energy efficiency.74

Commenters stated the promotion of greater dispatch of gas-fired power plants as a substitute for coal should be removed from the description of buil ding block #2. Commenters stated the rule should not accept the greater dispatch of gas-fired power plants or replacement of coal-fired power plants with gas as measures of compliance pur suant to building blocks #2 or #3. Commenters stated the EPA should set much more aggr essive goals for zero-emission renewables. Commenters stated avoiding climate cata strophe will require that the U.S. swiftly and dramatically reduce its consumption of both coa l and gas. Commenters stated that, because natural gas does not present a clear climate benefi t over coal when full life-cycle impacts are considered, it is unsound climate policy to craft a rule that favors one fossil fuel over the other.

Commenters objected to the proposed regulations bec ause natural gas electricity generation would be 18-19 percent higher by 2030 under the EPA 's plan than it would be without the plan. Commenters stated this is a problem because, if we are to meet our larger G-8 commitment, we
need to remove fossil fuels from our mix. Commenter s stated that natural gas plants, once built, stay in use; in analyzing lifetime emissions for a natural gas plant, the National Energy Technology Laboratory assumed a lifetime of 30 year s. Commenters stated the way to transition off of fossil fuels, and the greenhouse gas dangers that they present, is not to build more fossil fuel plants that will stay in operation well into t he middle of this century.

Commenters stated the trajectory of increasing use of natural gas is incompatible with the far deeper reductions in CO2 emissions that will be req uired in the decades following 2030. Commenters stated the CPP has given no consideratio n to this issue. Commenters stated there is also the potential issue of the cost of stranded na tural gas assets in the context of the decreases of natural gas use that are going to be necessary. Com menters stated this should factor into the EPA's analysis of the potential problems associated with increasing natural gas production for use in the electricity sector. Commenters stated th at, because of the venting and leakage rates from the natural gas industry, it is important that the best system of emission reduction not significantly increase natural gas use in electrici ty production, until a more definitive assessment
in its favor is demonstrated. Commenters stated tha t, since plenty of options with a more certain and a cleaner path to CO 2 emission reductions are available, the EPA should indicate that these would be preferable and less open to question than an increase of natural gas use in electricity generation.

Commenters suggested the trajectory of short- and m edium-term policies should be compatible with a global phase-out of all CO 2 emissions by the end of this century, a topic that has been broached in the IPCC5 report. Commenters stated thi s report estimates that a trajectory limiting global average temperature rise to 2 o C would have to reduce global greenhouse gas emissi ons between 78 and 118%. Commenters stated the former v alue implies an essentially total
elimination of fossil fuels in the U.S. if the diff erential responsibilities of developed countries under the UNFCCC are taken into account, and the la tter figure means net CO 2 removal from the atmosphere. Commenters stated the EPA's natural gas use trajectory is even more intensive than that in the 2014 AEO of the EIA, which projects tha t 30.6% of electricity generation in 2030 would use natural gas. Commenters stated the EPA's modelling of the electricity sector for the year 2030 suggests that about 34% of the generation in 2030 would use natural gas as fuel.
Commenters stated the EIA reference case for natura l gas in EIA AEO 2014 projects total natural gas supply for U.S. use of 29.56 trillion c ubic feet in 2030. Commenters stated that, using a 2.5% venting rate, 20-year warming potential of 8 6, and assuming that 80% of natural gas is75

burned as fuel, the total emissions from the natura l gas fuel system would be about 2.3 billion
metric tons of CO 2 eq in the year 2030. This amounts to about 38% of 2 010 net U.S. GHG
emissions.

Several commenters were concerned that the CPP may be ineffective in reducing climate change
due to related emissions of methane.

• Commenters stated that natural gas development lead s to global warming. Commenters stated that natural gas may emit half as much CO2 as coal when burned, but it contributes methane, a greenhouse ga s with 300 times more global warming potential than CO2. Commenters also stated that natural gas development leads to global warming through massive deforestation for the purpose of constructing injection wells and infrast ructure. Commenters used Pennsylvania, which has lost hundreds of thousands of acres of old-growth forest to natural gas development, as an example. Commente rs stated that this deprives the plants of the natural process of transpiration.

• Commenters stated that regulatory agencies should c ease granting fracking permits and should cease saying that natural gas is the answer to atmospheric pollution and climate change. Commenters stated tha t natural gas development will only deepen the nation's reliance on fossil fu els and accelerate climate change
when there should be a focus on renewable sustainab le energy.

• Commenters stated that natural gas may be necessary over the short term, but it is not as clean as previously thought and so does not belong in the clean energy plan. Commenters stated that natural gas contribute s to greenhouse gases; it does emit only about half as much carbon as coal when bu rned for power, but it emits methane over its life cycle. Commenters stated that starting at extraction through processing and transportation, natural gas emits me thane from leakage, the
amount of which is about one half to three times as much methane as estimated. Commenters pointed out that methane is a much more potent gas than CO2. Commenters cited extraction as a problem with natur al gas; all of the easy natural gas has been depleted, and fracking is the only eco nomical option left.
Commenters attributed a lot of the methane to frack ing and expressed support for the EPA's support to control leakage.

• Commenters stated that the proposed rule is deficie nt in its reliance on a building block of replacing coal generation with natural gas plants, which the rule assumes
will be less carbon intensive. Commenters stated th at the proposed rule fails to increase efficiency standards for natural gas plant s. Commenters stated that there is scientific evidence that the proposed rule under states the climate harms of natural gas generation by failing to use reasonable means to account for methane leakage and the intense and short-term greenhouse g as effects of atmospheric methane. Commenters stated that encouraging natural gas development would impose substantial externalities on the communities directly affected by drilling infrastructure and fracking.76 • Commenters expressed concern that a switch to natur al gas is not the solution we need if we are serious about protecting the environ ment from all effects of power generation, not simply carbon emissions. Commenters stated various components of natural gas process leak methane, which is a gre enhouse gas 86 times as potent as carbon dioxide over a 20 year scale according to the intergovernmental panel on climate change, and leakage above three percent is enough to negate the climate benefits of natural gas over coal.

• Commenters stated that replacing coal with carbon c annot get us to the 80% reductions needed by 2050.

• Commenters stated that the promotion of greater dis patch of gas-fired power plants as a substitute for coal should be removed f rom the description of building block #2. Commenters explained that, because natura l gas does not present a clear climate benefit over coal when full lifecycle impac ts are considered, it is unsound climate policy to craft a rule that favors one foss il fuel over the other. Commenters stated the rule should not accept the gr eater dispatch of gas-fired power plants or replacement of coal-fired power pla nts with gas as measures of compliance pursuant to building blocks #2 or #3. Co mmenters stated that avoiding climate catastrophe will require that the U.S. swiftly and dramatically reduce its consumption of both coal and gas.

• Commenters stated the proposed regulations encourag e the expanded use of natural gas, which would actually make the climate crisis worse, not better, because they propose to directly regulate only CO2 from fuel combustion. Commenters stated replacing CO2 with methane is not a "clean power plan." Commenters stated several independent studies indic ate that at least 3% and potentially as much as 7% of the methane in natural gas is lost to the atmosphere during extraction, processing, and loading for tran sport, a leakage rate that would make natural gas just as bad, or worse than, coal a s an overall driver of climate change. Commenters stated a series of scientific st udies clearly demonstrate that methane is not an environmentally acceptable altern ative to coal. Commenters stated the political pragmatism of the CPP's encour agement of natural gas cannot be justified by real scientific or economic analysi s. Commenters stated methane is not a "bridge fuel"; it will lock us into a fossil- fuel dependent future, and is
therefore a road to climate chaos. Commenters state d methane is not a clean alternative to coal and fracking, the process by wh ich most natural gas is now produced, is environmentally destructive and produc es fugitive methane
emissions that contribute much more to climate chan ge than a commensurate amount of carbon dioxide. Commenters stated our agi ng methane infrastructure leaks, and should be gradually decommissioned, not expanded. Commenters stated the economic and ecological damages resultin g from coal and oil users switching to methane will plague us for several dec ades to come, as those who
have invested in new infrastructure will be loath t o abandon it for more climatefriendly equipment such as is needed to support geo thermal, solar, and wind.77 • Commenters expressed concern that, while many coal plants are receiving a "new lease on life" via conversion to natural gas, this is not necessarily the most appropriate long-term solution. Commenters stated t he energy prices will remain volatile due to global factors beyond our control - so long as we are paying for carbon-based fuels, as opposed to utilizing "free f uel" solar-, wind-, and geothermal-based technologies. Commenters stated th at self-sufficiency should begin with energy efficiency, rather than building yet another carbon bubble.

• Commenters stated the EPA should be cautious in pro moting the switch from coal to natural gas because promoting natural gas at the expense of energy efficiency measures and renewables may in fact do more harm th an good from a climate change perspective. Commenters suggested that the l eakage of methane during the extraction, processing and transportation of na tural gas needs to be evaluated. Commenters stated recent studies suggest that a lea kage rate higher than 2.4-3.2% will mean that natural gas is more of a global warm ing threat than coal is.

• Commenters stated that the EPA should re-visit the definition of re-dispatch and its usefulness to achieve the goal of reduced emiss ions. Commenters stated that there is no legally binding language in the propose d rule's flexibility plan for additional deployment of zero-emissions EGUs except at the state level under CPPs enforcement of market conditions for pollution credits and emissions offset trading. Commenters stated that zero-emissions stan dards should mean zero emissions and have no permitted allowable releases or venting of permissible
levels of toxic air contaminants or radioactive rel eases.

• Commenters stated that federal action is also neede d to ensure that decreased electricity sector demand for coal leads to corresp onding decreases in coal production, rather than a shift to coal exports, wh ich would undermine EPA's conclusion regarding a net decrease in methane emis sions.

• Commenters expressed concern over the fugitive emi ssions that are associated with natural gas. Methane is greenhouse gas much mo re potent that CO2, and the commenters feared that more leakage occurs in the t ransportation and use of natural gas than is reported. Commenters stated tha t switching to natural gas will not represent true progress in the fight against gl obal warming.

Fracking and Shale

Several commenters were concerned that the CPP may lead to more fracking and shale gas activities which can have harmful environmental imp acts.

• Commenters expressed concern that fracking threaten s water supplies and releases pollutants into the air including benzene, formaldehyde, and particulate

matter.

• Commenters expressed concern that the proposed Clea n Power Plan BSER encourages unsustainable practices that neither red uce climate change nor best78 protect environment and human health. Commenters ex pressed particular concern over the EPA's emphasis on re-dispatch in building block 2 since the U.S. Energy Information Administration predicts that most, if n ot all, natural gas will soon come from unconventional sources including shale ga s retrieved by hydraulic fracturing. Commenters stated that the science on f racked gas is controversial, and it is unclear if the lifecycle of fracked gas cause s fewer greenhouse gas emissions
than other carbon based sources. Commenters also st ated concern with possible ground water and surface water contamination from f racking practices.
Commenters also stated that it is unclear the exten t to which fracked gas depletes

scarce water resources.

• Commenters stated that the adverse impacts of frack ing are greater than coal.

• Commenters expressed concern that the new rule will further enable shale gas and oil industries to secure its hold in Pennsylvania a nd do more damage to ecological
and human health. Commenters stated that the new ru le would force Pennsylvania to reduce its air pollution and burn less coal, but commenters stressed that it is
how less coal occurs is what makes the difference. Commenters stated that doing nothing but replacing coal with fracked gas will ca use the air and atmosphere to worsen. Commenters stated the rule implicitly give consent to burn more trash, tires, coal sludge, and other forms of toxic waste for electricity. Commenters stated the rule is a good first step, but it will t he unintended consequence of replacing one dirty fuel with many others.

• Commenters stated that the CPP promotes fracking, a nd fracking contributes to climate change and threatens Americans' air and wat er quality. Commenters cited a 2010 study by Theo Colburn and later the Colorado School of Public Health which found that fracking releases volatile organic compounds (VOCs) into the air; the VOCs can combine with diesel emissions to form ground level ozone due to high truck traffic which accompanies fracking. C ommenters cited a University of Texas at Arlington study in Parker County, TX, w hich found an unacceptable level of methane (83 with 10 being the acceptable v alue) in the groundwater which the study contributed to nearby fracking. Com menters also mentioned the link between the disposal of toxic fracking waste i n injection wells and earthquake activity in many states.

• Commenters stated that unconventional gas wells emi t toxins including benzene and radon as well as emitting methane; the toxins a re then sent through compressor stations and pipelines. Commenters noted that the overall methane emissions are considerably higher than the official inventories report.

• Commenters suggested that the EPA consider water qu ality and quantity issues related to fracking before encouraging additional f racking. Commenters referred to a congressionally mandated drinking water study of the shale gas extraction life cycle and the notice and comment process evaluating the promulgation of hydraulic fracturing chemical and mixture disclosur e rules under the Toxic Substance Control Act (TSCA).79 • Commenters stated the EPA's modeling assumptions do not take into account
outside-the-fence limitations such as water withdra wal and thermal restrictions.

• Commenters stated that other impacts potentially ex acerbated by the additional gas production made necessary by the Proposed Rule include drilling fluids impacts to drinking water, flaring emissions, and s eismic activity.

• Commenters also stated that the rule should not inc entivize using more natural gas by counting changes to fracked gas power as an emis sions reduction. Commenters mentioned that fracked gas has lifecycle greenhouse gas emissions close to and possibly worse than coal. Commenters also mentioned the associated release of
methane.

• Commenters stated that natural gas companies cause irreversible environmental
destruction. Commenters called for no subsidies or incentives for the natural gas industry. Commenters said that taxpayer money shoul d instead be used to encourage clean, sustainable, renewable energy and not build infrastructure for pipelines.

• Commenters stated that increased dependency on gas would also lead inevitably to more fracking, with its associated air and water contamination, earthquakes, and its attendant litany of other environmental and human health problems. Commenters stated methane is a dangerous substitute for coal: fracking destroys landscapes, contaminates air and groundwater, and d redges up hazardous chemicals and radioactivity,11 some of which are pi ped directly into customers' homes, and all of which is leading to a public heal th crisis. Commenters stated methane pipelines fragment ecosystems, permanently scarring the countryside and threatening the safety of our communities with expl osive failures. None of these
terrible effects are factored into the CPP. Comment ers stated the EPA must factor in the cost of the 72 trillion gallons of water use d to operate the current 500,000 fracking wells. Commenters stated the huge amount o f water used for fracking, which becomes toxic waste in the process, will seri ously drain the country's fresh water supply, causing loss of safe wells and loss o f water available for agriculture. Commenters stated that water shortages and even dro ught are common results of climate change, and water systems play a crucial ro le in the balance of the planet's ecosystems; by removing trillions of gallons of fre sh water from the finite world water supply, fracking is exacerbating both climate change and the results of climate change.

• Commenters expressed concern about several adverse impacts related to natural gas. Commenters stated that natural gas obtained by hydraulic fracturing is not clean from a public health or climate perspective. Commenters stated that fracking is associated with local and regional air pollution, adverse birth outcomes and contamination of drinking water. Commenters que stioned the metrics used by the EPA to predict the effectiveness of this strate gy and stated that emission estimates should encompass the entire life cycle in stead of just carbon emissions from the smokestack. Commenters stated that it may also be necessary to80 differentiate between fracking and conventional dri lling, since these extraction
methods have different carbon intensities.

• Commenters also expressed concern with potential ne gative impacts from the process of hydraulic fracturing or "fracking" to ex tract natural gas. Commenters stated that whether the life cycle of fracked gas i n fact causes less greenhouse gas
emissions than those from other carbon based source s is unclear that the extent to which fracked gas causes contamination of ground wa ter and surface waters is unclear and that the extent to which fracked gas ca uses depletion of scarce water
resources is unclear. Commenters asserted that both the health effects and environmental impacts of fracked gas are still very unclear.

• Commenters expressed concern that the process of fr acking will be with us for a very long time. Commenters stated that currently ab out 30% of our national power plants rely on natural gas to generate electr icity and, if the 38% of coalfired power plants are converted under the re-dispa tch program, then 68% of our power plants will rely on fracked gas. Commenters c oncluded that, if 68% of the nation's power is dependent on natural gas, then th e process of fracking will be with us for a very long time and natural gas will n ot be a bridge fuel.

Commenters stated that the Proposed Rule fails to a ccount for the fact that increased use of natural gas will cause a further increase in hydrau lic fracturing and associated methods, and their attendant environmental damage. Commenters stated t hat hydraulic fracturing and associated methods have significant negative health and enviro nmental impacts that the agency must evaluate in determining whether its decision to inc rease those activities does in fact constitute BSER as defined in section 111(a)(1), which require s the agency to take into account any non-air quality health and environmental impact. Commenters stated EPA has failed to do so in related rulemakings and has failed to do so again here. Com menters requested that EPA re-visit many of the assumptions underlying its conclusion that swit ching to natural gas creates a 40% climate benefit and provide revised calculations. Commenter s recommended the final rule include language to encourage adherence to best practices f or hydraulic fracturing to mitigate associated adverse impacts. Commenters recommended encouraging best practices related to (i) having a systematic approach to assessing and managing human rights and health impacts, (ii) ensuring adequate community consultation to minimize impacts , (iii) requiring disclosure of the chemicals used in the fracking process, (iv) using best pract ices to reduce fresh water use, for example through increased use of recycled or brackish water , and (iv) adopting measures to minimize the
risk of water contamination.

Methane versus Carbon Dioxide

Several commenters were concerned that the global w arming potential of methane be accurately portrayed.

• Commenters stated that methane is 34 to 86 times mo re harmful than CO2.

Commenters stated that the EPA's failure to use the most up-to-date 20-year GWP for methane and accurately account for methane loss creates the dangerously false impression that meaningful greenhouse gas reduction s can be achieved by simply81 running (dispatching) gas-fired power plants more a nd coal-fired plants less - the primary emphasis for building block #2 of the rule. Commenters stated that, since re-dispatch relies on excess capacity, this is an i nherently temporary measure in the face of growing demand; unless fossil fuel alte rnatives become a much greater portion of the nation's energy portfolio, greater d ispatch of existing gas-fired facilities will simply hasten the eventual need for additional new gas-fired capacity or the need to resume the increased dispat ch of coal.

• Commenters stated that the rule also misstates meth ane's 100-year Global Warming Potential (GWP), which was upgraded by the IPCC in 2013 from 25 to 34. Commenters stated that, given the need for rapi d GHG reductions to protect health and the plan's goal to lower emissions by 20 30, the 20-year GWP, at 84, is more relevant. Commenters stated that, regardless o f which GWP is used, measurements of methane over gas fields suggest tha t leaks are large enough to eliminate any advantage over coal even without incl usion of leaks in pipelines and storage facilities. Commenters stated that they und erstand that the EPA intends to address methane emissions from oil and gas developm ent in the future, but they are pessimistic that discrepancies in measurement c an be resolved and adequate reductions achieved during the time frame of the Cl ean Power Plan. Commenters stated that economic analyses predict that increase d exploitation of natural gas will not result in lower greenhouse gas emissions i n the absence of carbon pricing because low cost will increase demand and discourag e investment in clean

energy.

• Commenters stated that, in discussing the proposed rule, the EPA and advocates for the gas industry often refer to emissions of "c arbon" instead of "carbon dioxide." Commenters stated this is misleading beca use the rule regulates only CO2; however methane is 34 times more potent, pound for pound, than carbon dioxide as a greenhouse gas over one hundred years and 86 times more potent over twenty years--the most critical timeframe for taking action to avoid climate catastrophe. Commenters stated climate scientists a gree that rising levels of greenhouse gas in the atmosphere are causing the Ea rth to rapidly approach critical tipping points, beyond which major changes are likely irreversible due to environmental feedbacks, such as the melting of sea ice or thawing of permafrost which further accelerates climate change. Commenter s stated this makes the powerful global warming potential (GWP) of methane over the next two decades extremely damaging. Commenters stated the EPA disco unts these effects by using an outdated GWP for methane, and by focusing its an alysis on the hundred year
timeframe.

• Commenters stated the EPA's failure to use the most up-to-date 20-year GWP for methane and accurately account for methane loss cre ates the dangerously false impression that meaningful greenhouse gas reduction s can be achieved by simply running (dispatching) gas-fired power plants more a nd coal-fired plants less, the primary emphasis for building block #2 of the rule. Commenters stated that, since re-dispatch relies on excess capacity, this is also an inherently temporary measure in the face of growing demand; unless fossil fuel a lternatives become a much82 greater portion of the nation's energy portfolio, g reater dispatch of existing gasfired facilities will simply hasten the eventual ne ed for additional new gas-fired capacity or the eventual need to resume the increas ed dispatch of coal. Commenters stated that, while the rule does not spe cifically rely on the construction of new gas-fired facilities in the dev elopment of targets for building block #3, the construction of new gas-fired power p lants are nevertheless contemplated as a means of achieving compliance and intrinsically incentivized because success is measured only by reduced emissio ns of carbon dioxide. Commenters stated these are fundamental problems wi th the rule as presently structured. Commenters stated the most comprehensiv e approach to regulating greenhouse gas emissions would involve setting targ ets that account for not only carbon dioxide, but the full-cycle of total greenho use gas emissions, including methane lost to the atmosphere prior to and during combustion.

Time Dependent Impacts

Commenters stated that potentially higher upstream methane emissions and their time dependent impacts, as well as the costs of additional climate change mitigation efforts, should be taken into account by the EPA. Commenters stated the effective ness of the EPA's policy formulation regarding upstream methane emission is dependent on two important assumptions: 1) an expectation of the continuation of historical emiss ions reductions, achieved by voluntary emissions reductions on the part of natural gas sup pliers, as well as expected regulatory emissions reductions through New Source Performance Standards and 2) the use of the static GWP (100) emissions equivalency metric to convert m ethane emissions to CO2-equivalent quantities. Commenters stated it is because of thes e assumptions that, despite the growth of natural gas production, the agency expects a net re duction of upstream methane emissions.
Commenters stated the EPA's calculations simulate a constant level of effort toward voluntary reductions into the future, as noted in the Regulat ory Impact Analysis published along with 111d,
but no corrective measures are detailed in case vol untary reductions do not occur. Commenters stated that potentially higher upstream methane emi ssions and their time dependent impacts, as well as the costs of additional climate change miti gation efforts, should be taken into account accordingly. Commenters stated that significant add itional upstream emissions reductions are required when the time-dependent emissions impacts of methane are recognized.

Commenters stated that a simple scaling analysis il lustrates the risk of underestimating the resulting methane impacts: if upstream methane emis sions from natural gas increase proportionally to the projected gas production incr ease - and upstream coal emissions decrease by the same mechanism - 2030 emissions in CO2-equiv alent terms would be between 22% and 27.5% lower, instead of 30% lower, than 2005 emissi ons; while a mean reduction of 25% is still significant, it demonstrates the high sensitivity o f reductions to assumptions about upstream emissions reductions; and a trajectory of 2% reduct ions per year between 2011 and 2030, both for coal and gas upstream emissions, would be requi red to allow the 30% target (compared to 2005 levels) to be reached in 2030.

Commenters stated that CO2 and methane emissions ou tcomes are interrelated through the choice of energy sources, because both gases are em itted in differing proportions in the life cycle of various fuels. Commenters stated that, even if d ifferent greenhouse gases are regulated by83

separate policies, coupled effects can be understoo d and addressed by comparing gases on a single scale, which requires a conversion of impact s into carbon dioxide equivalent units. Commenters stated the most widely used equivalency metric, the global warming potential (GWP (100)), assigns values to each gas depending o n the ratio of its cumulative radiative forcing contribution, over a time period of 100 yea rs, to that of carbon dioxide; however, the
associated conversion factors and the resultant emi ssions impact remain constant over time, which does not reflect the time-dependent effects o f short- versus long-lived greenhouse gases. Commenters stated a new set of dynamic metrics capt ures the impact of emissions timing relative to an intended radiative forcing stabiliza tion year, based on a target of stabilizing radiative forcing at 3 W m-2, a level that is consi stent with commonly-cited climate policy goals. Commenters stated these dynamic metrics assign a hi gher conversion factor to each unit mass of methane the closer in time that the gas is emitted to the stabilization target. Commenters stated that, using the instantaneous climate impact metric (ICI) to assess the CO2-equivalent value of methane in the years 2020, 2025 and 2030, estimated emission reductions do not reach the target 30% reduction of power sector CO2-equivalent emissi ons by the year 2030 (compared to 2005 levels). Commenters stated that, based on the ICI, emissions reductions range between 22% and 18.2% in the near term (2020), compared to the anti cipated 27% (2020 compared to 2005), and between 20.6% and 7.9% in the long term (2030), com pared to the anticipated 30%. Commenters stated the wide range of estimated emission reducti ons required is a result of uncertainty estimates for methane emissions from natural gas sy stems and coal mining, published in the 2013 US GHG Inventory. Commenters stated that highe r percentages of emission reductions are generated assuming a continuation of historical 2% per year methane emissions reductions from natural gas production overall between 2005 and 201 2 until the year 2030; and lower percentages result from upper bound EPA estimates. Commenters s tated these results demonstrate that even using lower bound estimates for upstream coal and g as emissions, the projected emissions reductions (-16.4%) are roughly half the expected p ercentage for 2030 (30%), when climate stabilization goals are taken into account.

Commenters stated the plausibility of EPA's expecta tions regarding upstream emissions reductions can be assessed by looking at past achie vements. Commenters stated that, between 2005 and 2012, methane emissions from natural gas s ystems decreased by 14.5%, which corresponds to a roughly 2% reduction per year. Com menters stated that, during the same period of time, the coal and gas industry together achieve d a 1.4% annual reduction in coal and gas upstream emissions. Commenters stated that, despite these accomplishments, addressing the time-dependent effects of GHG emissions will requir e significantly larger efforts: the closer methane is emitted to a target stabilization year, the higher its impact may be. Commenters stated that, as a consequence, the margin for allowed meth ane emissions becomes smaller and smaller over time, requiring tighter constraints on emissio ns despite rising production levels. Commenters stated that, as an example, a 30% reduct ion of overall GHG emissions (in carbon dioxide equivalent units) would require annual upst ream emissions reductions in the range between 4% and 12%; percentages that are between tw ice and six times as large as what has been achieved by the industry in the past. Commente rs stated that, even in a scenario with 2% annual emissions reductions starting in 2011 (the b ase year of EPA's calculations), emissions reductions based on time-dependent metrics would on ly be in the order of 20% in 2030, compared to 2005 levels (instead of the projected 3 0%).84

Commenters stated that, while this calculation lead s to quantitative targets for reducing upstream methane emissions, it is also important to highligh t the opportunities to meet these targets.
Commenters stated that a number of recent studies i ndicate that not all devices in natural gas production and processing contribute equally to ups tream emissions, suggesting that knowledge of the distribution of upstream emissions across de vices and sites can create opportunities for regulators to take action. Commenters stated that w ell-designed regulation might allow for significant reductions with limited cost increases. Commenters stated that, in a widely cited 2006 EPA study of five gas processing plants, less than 1% of devices account for a plant-specific range of 30% to 90% of overall emissions, while a 2 014 study of well pads in Pennsylvania identifies several high-emitting pads responsible f or a 4-30% range of regional methane flux. Commenters stated that, in a projection of 2018 oil and gas methane emissions by source category, a recent ICF International study attribut es roughly 40% of methane emissions to only five device types. Commenters stated that, comparin g direct measurements in different locations Allen et al. find significant variability. Commente rs stated that extrapolating these results to the entire gas system should be done with caution, but current numbers point in a clear direction: cost-efficient emissions reduction opportunities sh ould target geographical and device-specific super-emitters. Commenters stated that more data on high-emitting devices is needed-heavy tail distributions in current samples indicate that supe r-emitters might be underrepresented in overall emissions estimates, as pointed out by Brandt et al

.

Methane Leakage

Many commenters were concerned that the CPP may be ineffective in reducing climate change due to methane leakage.

• Commenters stated that if methane leakage is betwee n 1 and 3 percent, then it is on par with natural gas, but the balance of natural gas and coal fade quickly when leakage is above 3 percent. Commenters stated that private testing shows that there are places where it is 20 percent, and L.A.'s is 17 percent. Commenters stated that leakage from distribution is a problem in cities like Atlanta, and Atlanta is not closely monitoring it.

• Commenters stated that natural gas powered generati on would result in a 40 percent emission reduction, but this could result i n methane leakage at any point in the process. Commenters noted that the leakage r ate is higher than what the
EPA uses in its formulas. Commenters stated that le aked methane is 100 time more harmful than CO2 emissions, and natural gas us age would lead to an increase in fracking that endangers the public and freshwater resources. Commenters stated that the technology forcing requi rements of the CAA should be enforced by requiring increases in efficiency at existing natural gas plants.

• Commenters expressed concern that the phasing out o f older coal-fired power plants by increasing electricity generation at natu ral gas-fired power plants may result in greater emissions of fugitive methane fro m the natural gas distribution
network.85 • Commenters expressed concern that pollution is crea ted at several stages in the production and use of natural gas, including remova l from the earth, transport, compression, and use to create electric power. Comm enters noted that natural gas extraction is subject to leakage and loss of methan e during transportation, and that methane is a powerful GHG with an impact on climate change over 20 times greater than CO2 over a 100-year period. According to the commenters, studies indicate that methane leakage at levels above 3% is enough to negate the climate benefits of natural gas over coal. Commenters belie ved that the EPA may be proposing in the near future a rule that addresses methane emissions from EGUs and other sources, which commenters welcome. Commen ters recommended that the EPA look for guidance from those states that ha ve already implemented
measures to address methane emissions such as Color ado, which has a comprehensive plan for cleaning up methane pollutio n from its natural gas sector, and Ohio, which requires natural gas drillers to co nduct quarterly inspections to detect and fix leaks in their systems. Commenters a lso stated that concerns have been raised about the effects of natural gas extrac tion on drinking water supplies due to the use of fracking. Commenters recommended that the Proposed Rule acknowledge the potential dangers of fracking and t hat states take all precautions necessary to protect drinking water supplies from t he effects of fracking.

• Commenters stated the EPA's failure to use independ ently-produced and peerreviewed data and analyses about natural gas ventin g and leaks may hide critical errors that would preclude designation of natural g as as BSER. Commenters stated that, if natural gas venting and leak rates are significantly higher than the EPA estimates--and published estimates indicate tha t they may well be--the positive impacts of displacing coal by natural gas generation, could be largely or completely negated, especially if the 20-year warmi ng potential of methane is
used. Commenters stated it is essential to consider effects on this shorter time frame since greenhouse gas accumulations are now cr eating impacts faster than previously estimated. Commenters stated that it is now estimated that essentially complete summer Arctic ice melting ' a potential 't ipping point' ' may happen on a ten to thirty year time frame.

• Commenters noted that, in order for these emission reductions to mitigate rising atmospheric levels of greenhouse gases, it is also critical that EPA act to reduce the methane leakage that occurs during the producti on and distribution of natural gas and during the mining of coal.

• Commenters stated methane leaks associated with nat ural gas used in the combustion processes for thermal electric power pro duction should be included in the accounting for electricity production. Commente rs stated that substituting natural gas for coal lowers carbon dioxide during c ombustion, but the leakage rate of natural gas during production and transport can far exceed the reduction in carbon dioxide equivalents. Commenters stated that natural gas that is supplied with certified zero leaks should get the full credi t, but all other sources would count only the difference between the avoided emiss ions from not burning coal and the actual global warming from burning natural gas including the warming86 due to leaks. Commenters stated that, while the lea kage of natural gas is a carbon intensity continuum, one may think of natural gas w ith few or no leaks as "low carbon natural gas,'' and natural gas produced with large leaks as "high carbon natural gas." Commenters stated that, in some cases , the global warming associated with "high carbon natural gas" will exce ed that of coal combustion. Commenters stated that, perhaps coal bed methane le aks associated with coal mining should be counted as well in determining the baseline for coal consumption. Commenters stated that often the short er lifetime of methane is cited as a factor to consider, but for several hund red years, it traps more heat than carbon dioxide, and when it disappears it is conver ted into ultra-long lasting
carbon dioxide.

• Commenters stated the best science shows that the s ystemic venting and leakage of methane which occurs during extraction, processi ng, and transport, along with carbon dioxide released during its combustion, nega tes any meaningful benefit that gas may have over coal with respect to climate change. Commenters stated that real-world measurements by the National Oceani c and Atmospheric Administration and several other independent "top-d own" analyses indicate that at least 3% and potentially more than 7% of methane fr om natural gas is lost to the atmosphere prior to burning, far exceeding EPA esti mates, which have been increasingly criticized by the scientific community as wishful thinking. Commenters stated that, based on the most recent IP CC 20-year GWP for methane, a leakage rate of 2.8% or higher actually causes natural gas to be more damaging than coal as a driver of climate change. C ommenters stated that, when the full life-cycle emissions of methane are consid ered, it becomes clear that switching from coal to gas has little climate benef it and could in fact make matters worse. Commenters stated that, depending on the extent to which states try to comply with the rule's meager targets by swi tching from coal to gas instead of taking useful action like improving the efficien cy of existing power plants or renewables, carbon dioxide reductions could be subs tantially masked by the climate driving impacts of methane.

• Commenters stated that natural gas is not a satisfa ctory "bridge" fuel. Commenters stated that methane emissions from the p roduction, processing, and transportation of natural gas need to be dramatical ly reduced. Commenters stated that investors should be put on notice now as to wh en the end of the bridge will be reduced. Commenters stated that natural gas may bur n more cleanly than coal (it emits about half as much CO2 as coal), but it is no t "low carbon" in any realistic sense since it results in methane leaks from produc tion and distribution. Commenters stated that the methane leaks offset any apparent advantage of using natural gas since methane is an extremely potent gr eenhouse gas; methane emissions may be 9 to 10 percent of production. Com menters stated that the end of "bridge" should be defined, and investors need t o be given a definite date as to when new natural gas plants would need to be replac ed with zero-emissions power, which would probably be before 2040-2050. Co mmenters stated that investors would otherwise invest more in natural ga s plants and will face more87 stranded costs than is reasonable. Commenters state d that the sooner we move to zero-carbon generation, the better.

• Commenters stated it is clear that a great deal of the natural gas will come from fracking and studies show that methane leakage from unconventional drilling, such as fracking, is significantly higher than it i s from conventional drilling. Commenters stated methane is the main component of natural gas, and it is leaking into the atmosphere at approximately one an d one half times the rate estimated by the EPA. Commenters stated that, while methane degrades more quickly in the atmosphere than carbon dioxide, poun d-for-pound it is more efficient at trapping heat. Commenters stated the I PCC now estimates that a pound of methane traps 87 times as much heat as a p ound of carbon dioxide in the 20 years after being emitted, and 36 times as much heat as a pound of carbon dioxide over a 100-year time frame. Commenters stat ed these 20-year and 100- year methane global warming potentials (GWPs) are s ignificantly larger than previous IPCC estimates, with the 20-year GWP refle cting about a 20 percent
increase.

• Commenters noted that, with the recent advances in natural gas extraction technologies, environmental concerns have been rais ed that could erode or negate the EPA objectives. Commenters stated natural gas c an leak from wellheads, valves, tanks, pipes, processing plants, and other parts of the energy supply chain. Commenters stated that a recent study utilizing sat ellite measurements of methane found leakage rates in certain gas producing region s in the 2 to 17 percent range, much higher than the 1.2 percent leakage rate calcu lated by EPA. Commenters
stated that scientists have found that a methane le akage rate above 3.2 percent may negate the fuel's climate benefits in the power plant.

• Commenters expressed concerned that, although natur al gas power plants have lower carbon emissions than coal, they are not emis sions-free. Commenters stated that methane leakages across the natural gas supply chain, potential health impacts from poorer air quality, and potential grou ndwater contamination in shale gas plays, are all of significant concern. Commente rs stated that natural gas as a compliance strategy is effective only to the extent that the issue of life cycle emissions (including methane leakages in the overal l system) is addressed. Commenters expressed concerned that the proposal pu ts too much stock in natural gas as a compliance strategy and should instead shi ft more focus toward renewable generation and energy efficiency measures

.

• Commenters expressed concern about the climate and public health impacts of fugitive methane emissions from natural gas product ion and transport. Commenters stated methane is a powerful climate war ming pollutant, 87 times more powerful than carbon over a 20-year time span. Commenters stated the EPA estimates that gas leaks from the oil and gas secto r are responsible for 29 percent
of U.S. methane emissions. Commenters stated the EP A's estimate may be too low and fugitive emissions from this sector will si gnificantly increase because of the Clean Power Plan. Commenters stated that, if me thane leaks are not88 controlled, the climate gains of moving away from c oal-fired power may be completely cancelled out. Commenters stated it is n ot enough to reduce carbon emissions; instead greenhouse gas pollution (includ ing methane) must be considered as a whole, and targeted accordingly. Co mmenters stated this is necessary for the world to slow the rate of warming and limit total warming, and is also necessary to accomplish the goals of the Pr esident's Climate Action Plan.

• Commenters expressed concern that a significant bod y of evidence indicates that methane leaks associated with nonconventional produ ction of natural gas (such as shale or tight gas extraction), as well as with the processing, transmission, and distribution phases of the industry, may cause clim ate change impacts on a par
with those of coal combustion. Commenters stated th at Building Block 2 has the favorable attributes of being objectively determine d using current data, being demonstrably feasible, and setting target emission rates that are likely to meet or
exceed the reductions that would flow from "busines s as usual" retirements and curtailments. Commenters stated that, while they su pport the use of a limitation on coal-fired EGU dispatch under Building Block 2 f or target setting, they intend to work with our state partners to ensure that comp liance under state plans does not lead to increased use of natural gas. Commenter s stated that displaced coal should be replaced with renewable energy and energy efficiency (as opposed to natural gas) to the greatest extent possible. Comme nters stated the agency underestimated the impact of recent RE cost reducti ons and the growth in momentum in that sector and suggested that the EPA set a more aggressive set of EE/RE targets.

• Commenters stated a growing body of published, peer -reviewed research indicates that methane emissions from natural gas p roduction are significantly higher than estimated by EPA's 2013 Greenhouse Gas Inventory. Commenters stated that certainty in source attribution has inc reased in recent years as scientists are better able to distinguish methane sources base d on detected levels of cooccurring compounds such as ethane or isotopic comp osition of atmospheric methane. Commenters referred to the following studi es:

• An early top-down study, Xiao et al. (2008), estima tes that nationwide emissions
of methane from fossil fuel sources in 2004 were 50 to 100 percent higher than bottom-up inventories estimate. More recently, Mill er et al. (2013), uses atmospheric measurements of methane in 2007 and 200 8 to estimate that methane emissions from all U.S. sources were 50 percent hig her than estimated for that year by the 2012 U.S. GHG Inventory. The study show s that oil and gas emissions constitute a significant portion of the o bserved emissions not accounted for in EPA's Inventory. Atmospheric studies examini ng individual regions have found even higher methane emissions in the regions studied. Two studies of Colorado's Denver-Julesberg Basin have concluded th at during gas production alone (not including emissions from downstream segm ents of the industry - transmission and distribution), the gas leak rate w as about 4 percent. The same team of researchers found even higher methane leak rates in Utah's Uinta Basin. Brandt et al. (2014) systematically reviews eleven top-down and a number of89 bottom-up studies, including the studies discussed above (with the exception of Petron et al (2014), which was not published at the time of Brandt et al's review). Brandt et al. demonstrates that for many years top- down studies have very consistently shown higher emissions from oil and ga s than do bottom-up studies.
The authors estimate that total U.S. methane emissi ons from all sources were 25 to 75 percent higher than the U.S. GHG Inventory es timated for 2011, and find that oil and gas are important contributors to thes e unreported emissions. These top down studies provide compelling evidence that t he aggregate methane emission estimates based on "bottom up" studies, su ch as the estimates used by the RIA as a starting point here, underestimate oil and gas sector methane emissions by a significant margin.

• Commenters stated the EPA has not shown that increa sed natural gas use by using NGCC generation to displace coal and oil and gas bo ilers can be part of a best system of emission reduction or even that an increa se in natural gas use in the power sector can be used for compliance with the CP P. Commenters stated that a more careful examination of leakage data using both 20-year and 100-year warming potentials is needed to make such a conclus ion and, until that time, the second building block in the CPP, increased use of NGCC generation, cannot be considered part of the best system of emission redu ction. Commenters stated that, in the worst case, it may not reduce CO2 equivalent emissions at all or could even exacerbate them somewhat. Commenters suggested that a constraint on compliance plans should be that there should be no net increase in natural gas use in the power sector; changes in the use of natural gas can be allowed within that
overall constraint.

• Commenters stated the EPA's estimates of methane em issions from natural gas production, processing, transportation, storage and distribution are underestimated, which has resulted in a skewed repr esentation of the climate benefits of switching from coal to natural gas. Com menters stated there is compelling evidence that leakage rates from natural gas operations are far higher than EPA emission factors suggest. Commenters state d the EPA currently assumes that natural gas systems have a combined up stream and downstream leakage rate of 1.8 percent. Commenters stated this was recently reduced from 2.5% for conventional gas and 3.9% for fracked natu ral gas (the revision occurred after the publication of an industry study that was not subject to peer review). Commenters stated that, since that time, the Office of the Inspector General has issued a report indicating that EPA must improve it s emission factors to better reflect direct measurements of methane leakage from natural gas production. Commenters stated that, for instance, a recent stud y using atmospheric
measurements estimated fossil fuel methane emission s at more than two times higher than EPA's emissions factors would indicate. Commenters stated that observations from oil and gas operations in Colorad o indicate that inventories underestimate methane emissions by at least a facto r of two. Commenters stated that leakage rates over a Utah gas field were recen tly estimated at 6.2 to 11.7%, well above the rates assumed by national inventorie s. Commenters stated that a recent meta-analysis of studies conducted over the last 20 years suggests that90 EPA's estimate of 1.8% is far too low, with actual leakage rates between 3.6 and
7.1%.

• Commenters stated there are multiple aspects of nat ural gas production that may result in significant undercounted fugitive methane emissions. Commenters stated that one study surveyed methane plumes over Marcell us shale operations in Pennsylvania. Commenters stated that the authors fo und that seven well pads in the drilling (pre-production) stage were emitting a relatively large proportion of the observed methane flux, with leakage rates of 2. 8 to 17.3%. Commenters stated that this is a production stage not typically consi dered to cause large methane leakage in national inventories, and thus is exclud ed from consideration by EPA. Commenters stated that this study provides another indication that current leakage rates are significantly underestimated. Commenters stated that new work also suggests that both plugged and unplugged abandoned wells in Pennsylvania leaked at much higher rates than reflected by curre nt emission factors.
Commenters stated that the EPA must revisit its ass umptions regarding cradle to grave leakage to create a sound scientific basis fo r the Proposed Rule.

• Commenters stated that another major source of meth ane emissions from the natural gas sector is leaks from pneumatic devices. Commenters stated a recent study calculated emission factors for these devices at likely at least twice the amount predicted using the emission factors in EPA' s official U.S. greenhouse gas emissions inventory. Commenters stated that recent reports have also substantiated an alarming rate of leaks from decayi ng gas pipeline systems across the country, creating the need for systematic, on-t he-ground data collection to obtain an accurate quantification of emissions from this source. Commenters stated that, for example, according to a recent stu dy, the two distributors of natural gas in New York City and Westchester County reported 9,906 leaks in their combined system for 2012 alone, and gas distr ibutors nationwide reported an average of 12 leaks per 100 miles of the 1.2 millio n miles of gas main pipes across the country. Commenters stated that more tha n 5,800 leaks were detected from aging gas pipelines underneath the streets of Washington, D.C. Commenters stated the Office of the Inspector General issued a report this year indicating that the EPA should work with other agencies to track em issions from distribution pipelines, consider future regulation, and update i ts emissions factors.

• Commenters stated the EPA must use accurate estimat es of methane leakage from natural gas systems. Commenters stated that vented, fugitive and other methane emissions from natural gas undercut the climate ben efits of using natural gas to produce electricity. Commenters stated the Proposed Rule's analysis assumes a methane leakage rate that is contradicted by recent studies to which the EPA does not refer and apparently has not taken into account . Commenters stated that employing an accurate leakage rate is another cruci al component in the analysis of the climate impacts of switching from coal to natur al gas. Commenters expressed concern that, while many of these studies are peer- reviewed and directly on point,
the EPA does not include them in its references. Co mmenters stated that the EPA cannot cherry-pick the data on which it relies but must take these scientific studies91 into account. At a minimum, EPA must explain why it dismisses this information.
Commenters stated that the observational data indic ate that much more methane is reaching the atmosphere from natural gas production than EPA currently estimates. Commenters stated that whether from supe r-emitters or indicative of higher average methane emissions per site, or both, there is a clear underrepresentation of methane from natural gas producti on in EPA's analysis of the climate impacts from natural gas.

Fugitive Methane Rules

Several commenters wanted the EPA to develop regula tions to reduce fugitive methane
emissions.

• Commenters stated that, for the clean power plan to achieve its full potential,

rules must be adopted for capturing fugitive methan e and other volatile organic compounds from oil and gas operations.

• Commenters stated the most serious failure with the EPA plan is that it shifts fossil fuel usage for electric generation primarily to natural gas, while simultaneously not dealing with the extraordinary m ethane emissions from production, storage transmission and distribution. Commenters stated that commitments have been made by the Administration an d EPA to control methane and they are looking for that commitment to be real ized.

• Commenters stated that, while greater reliance on g as-fired power under the Proposed Rule will place a heightened responsibilit y on natural gas producers and pipeline operators to mitigate fugitive emissions o f methane across the supply chain, there is significant evidence that American industry can meet the challenge

• Commenters urged the EPA to use the Clean Air Act t o address fugitive emissions of methane resulting from natural gas dev elopment. Commenters stated that a clean energy plan under which states meet th eir carbon reduction requirements simply, or even mostly, by switching w holesale to natural gas will not represent true progress in the fight against gl obal warming; rather, states must make substantial investments in energy efficiency m easures and renewable energy sources, and reduce America's use of all fossil fue ls.

• Commenters stated that, even if the EPA eventually considers separate efforts to limit methane loss, the rule is deficient because i t would lead states to make decisions about electricity generation based on com bustion emissions only. Commenters stated this will lead to poor choices re garding energy production, as seen in the rule's own Regulatory Impact Analysis ( RIA). Commenters stated that, compared to baseline forecasts, the rule would boos t the amount of additional electricity generation from natural gas by nearly t en times the meager gain projected for renewables before 2020. Commenters st ated that, by accelerating gas investments in the near-term, the plan could ti p the scales toward fossil fuels for decades to come; once gas-fired plants are in o peration, there will be less92 incentive for utilities to reinvest in renewables b ecause the massive capital outlay for gas infrastructure will have already occurred.

• Commenters stated the EPA's projections include ext remely optimistic forecasted results of voluntary emission reduction programs. C ommenters stated that, while the EPA assumes that voluntary reduction efforts wi ll continue at a constant historic percentage level over the entire rulemakin g period, the explosion in natural gas production over the last several years renders this assessment dubious at best, and EPA itself admits its uncertainty. Com menters stated that nothing indicates voluntary reduction efforts have kept pac e with the recent tempo of extraction; instead, the recent observational studi es indicate the opposite.

Lifecycle Analysis

Several commenters suggested the EPA should use a l ifecycle analysis to determine the net
emissions of methane associated with the CPP.

• Commenters stated that CO2 and methane are lost dur ing the production, processing, and transmission of natural gas. Commen ters stated that this coupled with a consideration of natural gas's lifecycle emi ssions shows that natural gas is not any better than coal from a climate change stan dpoint. Commenters stated that the effect and intent of the proposed rule was to a ccelerate the use of fracked gas and to facilitate the development of gas-fired powe r plants, which is a problem. Commenters stated that the proposed rule is defecti ve since states and utilities would make decisions about electricity based on car bon dioxide emissions from combustion only, and that will lead to bad decision s.

• Commenters stated that, if one considers the fugiti ve gas from mining to transport to storage, natural gas is not any better than coal . Commenters asserted that the proposed rule would be improved by less emphasis on natural gas, which is a fossil fuel that "emits 50 percent carbon dioxide i nto the atmosphere" when it is burned. Commenters recommended putting more emphasi s on energy efficiency and green renewable energies to make the rule stron ger and provide us with less
health threats in the future.

• Commenters stated that natural gas from shale has a n 8 to 11 percent larger greenhouse gas footprint than conventional gas over its lifecycle which could be changed with improved practices. Commenters emphasi zed that the rule not incentivize shifting from natural gas to coal and c alling it an emission reduction.
Commenters said that the rule must not allow states to let polluters buy pollution offsets to meet emissions requirements. Commenters cited current cap-and-trade programs that allow polluters to pay farmers, fores ters, et cetera to reduce their
emissions and then claim those cuts for themselves.

• Commenters stated that the proposed rule would acce lerate the conversion from coal to natural gas by only quantifying the smoke s tack emissions at generating plants and by disregarding the release of methane i n the natural gas lifecycle.93 Commenters said the president's address to natural gas is wrong in many ways, and that the president's approach is poisoning us. Commenters stated that there is
scientific evidence that shows that carbon-based fu el is no better than and sometimes worse than the coal industry. Commenters stated that France has banned fracking, Germany reinstituted their morator ium on the practice, and
mentioned that communities across the nation contin ue to fight or ban fracking.
Commenters stated that EPA studies have underestima ted the impacts of methane and natural gas drilling on the climate; drilling a nd fracking expanded the use of natural gas, which threatens to exacerbated climate change and to stifle investments and the expansion of renewable and sust ainable energy.

• Commenters expressed great concern over practices u sed to obtain coal, oil, and natural gas, and their effects on the environment. Commenters stated that the proposed standards fail to consider the process fro m extraction to combustion, and fracking is used an example of this. Commenters sta ted that methane gas is released at drill sites, and byproducts affect the air, soil, aquifers, and streams. Commenters also stated that fracking adversely affe cts the democracy with fracking exemptions to home rule, large amount of m oney going to state legislatures, corrupting of regulatory agencies, an d the use of gag order to silence those who have been harmed by fracking wells. Comme nters stated that natural gas is a bridge fuel to nowhere. Commenters stated that promoting natural gas to deal with climate change is like an alcohol treatme nt that urges sobriety by asking members to switch from vodka and whiskey to beer an d wine.

• Commenters stated that enhancing the amount of natu ral gas that is produced, transported, and burned for baseload power generati on will inevitably lead to greater emissions of this dangerous methane. Commen ters noted four independent studies which show that lifecycle methane emissions have a global warming potential as bad, or worse, than coal. Commenters a sserted the United States must: 1) craft mandatory methane capture and mitiga tion regulations to deal with the drilling and transmission of NG, as well as in the agricultural sector, which all contribute greatly to CH4 emissions and, 2) engage in a large-scale renewable energy build-out to replace our non-economic and po lluting coal plants without transitioning to other, potentially worse, greenhou se gas producing fossil fuels.

• Commenters stated that increasing bodies of researc h show that the complete life cycle of natural gas produces more carbon emissions than coal-fired generation.

• Commenters objected to the proposed regulations bec ause recent scientific studies suggest that current estimates of methane emissions from natural gas extraction are too low, Commenters stated the Office of the In spector General reported that "[t]he EPA's existing methane emissions data for di stribution pipelines may not be
valid." Commenters stated the EPA estimates emissio ns using a bottom-up approach, beginning with an inventory of all of the different industry activities undertaken in a given year and then uses largely da ted estimates of average emissions of each activity to arrive at an estimate of total emissions from the oil and natural gas systems. Commenters stated this app roach relies heavily on94 voluntary self-reporting from the industry. Commenters stated that data on the actual levels of various hydrocarbons in the atmosp here, taken from aircraft flights and/or from surface monitoring locations, m ake possible an alternative, top-down approach to estimating industry emissions. Commenters stated that scientists using this aircraft measurement approach in Utah, Colorado and Pennsylvania suggest that much more methane and oth er air pollutants are flowing from oil and gas sites than bottom-up estim ates based on dated emission factors and industry self-reporting. Commenters sta ted Karion et al. measured very large levels of methane, the equivalent of bet ween 6.2 percent and 11.7 percent of natural gas production. Commenters state d Caulton et al. published a study of methane emissions during the drilling stag e at well sites in Pennsylvania and found several super- emitters, each releasing 1 00 to 1,000 times the EPA's estimate of emissions during the drilling phase, as utilized in its bottom-up, inventory estimates. Commenters stated P'tron et al . published a study looking at methane emissions in the Denver-Julesberg basin in Colorado over a two-day stretch in 2012 using monitoring equipment on tower s and on aircraft flown above the play, and concluded from the measurements that methane emissions were "close to 3 times higher than an hourly emission es timate based on EPA's Greenhouse Gas Reporting Program data for 2012."

Commenters stated the EPA needs to conduct a more c omprehensive assessment of upstream
GHG emissions and an examination of emissions from potential changes in upstream emissions generated by changes in natural gas and coal produc tion, processing, and transportation activities
outside of the US. Commenters stated these exclusio ns are not trivial, but instead constitute yawning gaps in an assessment of a rulemaking that, because of its drive to increase natural gas usage across the entire power generation market for decades, will fundamentally affect the broader power sector, related market inputs, and ex ports of coal and gas outside of the US. Commenters stated that the EPA's analysis of the up stream methane emissions changes (reductions in total net upstream methane reduction s of between 7.4 and 10.6%) due to increased use of natural gas is incorrect for at least three reasons. Commenters stated (1) the EPA uses an outdated 100-year global warming potential measurem ent for methane of 25 and does not consider the 20-year methane GWP at all, which is c rucially relevant to evaluating compliance between now and 2030; (2) the EPA assumes methane l eakage rates from natural gas extraction, processing, transportation and distribution systems that are far too low; and (3) the EPA does not fully account for the increased methane emissions a ssociated with natural gas extraction through fracking and similar unconventional methods. Commen ters stated that, using corrected values will show that the Proposed Plan as currently struc tured will not achieve the emission reductions EPA projects; indeed, studies have concluded that n atural gas-fired power generation may approach, equal or even exceed the lifecycle greenh ouse gas footprint of coal-powered plants. 62 Commenters stated the EPA must revise its lifecycle greenhouse gas analysis of coal- and natural gas-based power generation to arrive at accurate pr ojections of the rulemaking's effect, and adjust the building block targets and their interre lationship according.

Commenters stated they identified six significant t echnical deficiencies in EPA's analysis of methane emissions. Commenters agreed with the IEER comments that EPA has not properly reviewed the impacts of methane releases in the fue l cycle and stated six points from IEER are of particular concern:95 • The EPA relies mainly on industry-supplied data forestimating natural-gasrelated methane emissions, especially for emissions from hydraulic fracturing operations. EPA also used an earlier joint study it did with the Gas Research
Institute which included field measurements done in 1992.

• In the one case where the EPA concluded that a set industry data underestimated emissions from completed hydro-fractured wells, the EPA estimated emissions using the defective industry data and made another estimate without it; but it never used its own, much higher venting estimate.

• The EPA oil and natural gas technical support docum ent failed even to refer to, much less to evaluate or use, recent independent me asurements, including
measurements made from aircraft that indicate that leaks from production may be far higher than the values used by the EPA. For exa mple the EPA document did not refer to or use Howarth et al. 2011, which esti mated venting rates from conventional and hydro-fractured natural gas produc tion wells as well as all downstream emissions. The range of overall venting rates in Howarth et al. was 1.7 to 7.9 percent.

• The EPA used leak rates averaged over all natural g as production. However, the increase in production that will be required to sup ply the fuel for the increase in Natural Gas Combined Cycle (NGCC) generation envisa ged by the CPP is projected to come from tight gas and shale gas form ations. There is a significant
difference between the two.

• The EPA entirely ignored the 20-year value of the g lobal warming potential of methane, which is critical to examine whether serio us excursions in CO2eq concentrations might occur between now and the end of the century, when the IPCC analysis indicates that essentially all fossil fuel use needs to be phased out if the temperature rise is to be kept below 2 degrees C.

The EPA did not consider the impact of setting a co urse of greatly expanded natural gas use in electricity generation up to the year 2030 beyond t hat year. Specifically, the EPA did not examine whether its trajectory of increasing natura l gas use is compatible with longer-term goals for much greater reduction in greenhouse gas emissi ons.

Clarification

Commenters requested clarification of an issue rela ted to the methane emissions comparison between coal and natural gas production as set out in the RIA at Tables 3A-3 to 3A-5, which provides estimates of changes in coal and natural g as production. Commenters stated that, under Option 1 of the Proposed Rulemaking, coal productio n is predicted to decrease by between 22 and 24% in 2020, while natural gas production for t he same time frame and option is predicted to increase by only 3 or 4%. Commenters stated the pre amble to the Proposed Rule, however, states that coal production is predicted to decrease by ro ughly 25% (an amount at least within the range of the RIA prediction), while natural gas productio n will increase much more dramatically than stated in the RIA, by between 12-14% (four building block approach) or between 19 and 22%96

(the two building block approach). Commenters state d that, as to the key question of how much additional gas will be produced, the preamble and t he RIA appear to disagree by as much as a factor of four for Option 1 only, and by nearly an order of magnitude for Option 2. Commenters stated this point is critical because the RIA's com parison of methane emissions from coal versus natural gas assumes a relatively small (3-4%) incre ase in natural gas production, which in turn crucially informs the Proposed Rule's assumptions a bout the amount of methane leakage and the basic rationale that replacing coal-fired power pla nts with natural gas-fired units significantly decrease greenhouse gas emission reductions. Commen ters asked that the EPA clarify which values are actually correct.

Oil and Gas NSPS

Commenters stated that, in its analysis, the EPA re lied on the newly promulgated oil and gas NSPS which set standards for non-greenhouse polluta nt emissions from the production stage of natural gas extraction through green completions an d other methods and its impact on methane emissions in 2015 and beyond. Commenters stated the EPA's assumption that compliance with that rulemaking will result in methane emission red uctions between 60 to 96% from the targeted leakage areas is overly optimistic. Commenters stat ed that these values are much below those established by the direct-observation studies cited by commenters. Commenters stated that the EPA assumes no leakage during drilling operations, which is clearly incorrect. Commenters stated that, although it is not clear from the RIA, fugitive methane emissions from coproducing wells presumably are not included even though a num ber of studies have found significant methane leakage from hydraulically fractured, co-pr oducing wells. Commenters stated the current NSPS for the oil and gas sector does not re quire these wells to perform green completions. Commenters stated the NSPS also does n ot address methane escaping during periods of flowback, which, for extraction of gas f rom shale, can involve millions of gallons of
fluid and last for weeks. Commenters stated the EPA also does not account for leakage from newly drilled or reworked wells that will be abando ned during the rulemaking period, for fugitive emissions from the de-pressurization of va rious well components, and for the acute shortages in the new equipment the NSPS assumes wil l be installed. Commenters concluded the EPA should revise its estimates of the oil and gas NSPS' impact on methane leakage.

Ozone Nonattainment

Commenters stated the EPA should evaluate the incre ase in emissions caused by the increased use of natural gas under the Proposed Rule, includi ng impacts on ozone. Commenters stated that an increase in natural gas usage from re-dispatch m ay increase NOx, VOC and methane emissions from upstream oil and gas operations in a reas that are at risk for ozone nonattainment, and that should these areas become designated as no nattainment, new constraints would be necessary regarding production. Commenters added th at all of New Mexico's NGCC facilities
are located in areas at risk for ozone nonattainmen t, and increased usage of both oil and gas
facilities and NGCC facilities will increase emissi ons, leading to additional permitting requirements. According to the commenters, this cou ld lead to additional economic burdens and
additional costs for controls. Commenters stated th at the timing for this rulemaking will be inappropriate for integrated planning regarding ozo ne, as discussed further elsewhere in this
document.97

Commenters urged the EPA to address emissions of me thane, a potent climate pollutant,
Commenters stated that President Obama committed to taking action on methane as part of the
Climate Action Plan and it is vital that EPA follow through on this pledge by promptly commencing a rulemaking to set standards limiting e missions of dangerous climate and public health harming pollutants from new and existing sou rces in this sector.

Commenters stated an increase in natural gas usage from re-dispatch may increase NOx, VOC and methane emissions from upstream oil and gas ope rations in areas that are at risk for ozone nonattainment. Commenters stated that, if these are as become designated as nonattainment, new constraints would be necessary regarding production . Commenters stated that all of New
Mexico's NGCC facilities are located in areas at ri sk for ozone nonattainment. Commenters stated that increased usage of both oil and gas fac ilities and NGCC facilities will increase emissions, leading to additional permitting require ments, which could lead to additional
economic burdens and additional costs for controls. Commenters stated the timing for this rulemaking will be inappropriate for integrated pla nning regarding ozone.

Comment 23: Commenters stated the EPA must determine whether a difference in methane emissions between conventional and unconventional g as wells exists and, if so, account for it.

Response 23: The EPA has analyzed the contribution of methane a nd determined that no adjustments need to be made for it. See Chapter 3 of the Regulatory Impact Analysis of 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 the EPA must fully account for em issions from unconventional gas extraction methods such as hydraulic fracturing, or fracking, which cause much higher methane
emissions than conventional methods. Commenters sta ted that unconventional gas currently accounts for about 60% of gas production, and is pr edicted to increase to 75% by 2035. Commenters stated that, although large methane emis sions are associated with flowback and drill-out of hydraulically fractured wells, particu larly for gas extraction from shale, the EPA does not currently distinguish between conventional and unconventional sources of fugitive and vented methane. Commenters stated that, in 2011, wh en EPA updated its emission factors for natural gas production, it did differentiate betwee n conventional and unconventional (shale) gas, with values of 1.6% and 3.0%, respectively. Comment ers stated that the EPA action in 2013, to
reduce these emission factors and remove the distin ction between wells drilled with conventional and unconventional sources, was directly contrary t o scientific evidence demonstrating higher methane emissions than believed, especially for unc onventional compared with conventional natural gas extraction. Commenters stated that, as detailed in 2011, during the development phase, fracked natural gas likely results in 1.9% h igher methane emissions as compared to conventional natural gas, resulting in average meth ane emissions from fracked wells of 3.3% as opposed to 1.4% for conventional gas. Commenters st ated these estimates have since been corroborated by other studies. Commenters stated, f or example, a new study has provided98

evidence that another potential difference between conventional and unconventional gas is the incidence of impairment and consequent leakage from cement and/or casings of fracked wells; the study, which examined public records to constru ct a database and model of impaired structural integrity of wells in Pennsylvania, show ed that unconventional wells were two times more likely to experience a loss of integrity and i ncreased methane leakage than conventional wells. Commenters stated that another study that fo und methane emissions during the drilling phase to be two to three times higher than EPA's em issions factor was conducted at wells subject to hydraulic fracturing. Commenters stated the EPA must determine whether a difference in
methane emissions between conventional and unconven tional gas wells exists and, if so, account
for it.

Comment 24: Commenters urged the EPA to propose fugitive methan e emission rules as part of

the CPP.

Response 24: A response is not provided here as this comment is outside the scope of the CPP.

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

Commenters stated that the EPA should be concerned about life cycle emissions from natural gas production, and the EPA should move forward with pa rallel additional regulations to ensure that methane pollution does not erase the climate benefi ts of increased reliance on natural gas over
coal.

Commenters expressed concern that natural gas extra ction is subject to leakage and loss of methane during transportation. Commenters stated th at methane is a powerful GHG whose atmospheric lifetime is much shorter than CO2, but whose comparative impact on climate change is over 20 times greater than CO2 over a 100 -year period. Commenters stated that studies indicate that methane leakage at levels above 3 per cent is enough to negate the climate benefits of natural gas over coal. Commenters stated the TEP C understands that EPA may be proposing
in the near future a rule that addresses methane em issions from EGUs and other sources.
Commenters stated welcomed such a rule and recommen ded that EPA look for guidance from those states that have already implemented measures to address methane emissions such as Colorado, which has a comprehensive plan for cleani ng up methane pollution from its natural gas sector, and Ohio, which requires natural gas dr illers to conduct quarterly inspections to detect and fix leaks in their systems.

Commenters urged the EPA to take action to reduce f ugitive methane emissions released during the natural gas extraction, transportation and deli very process. Commenters encouraged the EPA to engage in updated research to assess the extent of the fugitive emissions problem and begin a rulemaking under its CAA authority to control it. C ommenters stated the EPA should assign responsibility for reducing fugitive discharges to firms across the supply chain. Commenters stated that failure to control these emissions may seriously undermine the EPA's national climate pollution reduction efforts.99

Commenters noted that the EPA is considering fugiti ve methane regulations for the oil and gas sector, and that draft rules may be published soon. Commenters encouraged the EPA to pursue strong standards with this rule, and to treat the u pcoming proposal as a critical component of the Clean Power Plan strategy. Commenters stated the kn owledge and technology needed to reduce methane leakages is well known and available, and i n many cases preventing leaks has financial
benefits. Commenters stated the Natural Resources D efense Council estimates that enhanced standards to cost-effectively address the issue cou ld cut methane leakage in half, the rough equivalent of removing 150 million metric tons of c arbon over five years. Commenters stated that some industry leaders are beginning to take ac tion to reduce fugitive methane, but many others are failing to make the proper investments; EPA action is therefore necessary to level the playing field and ensure all industry players take the needed steps. Commenters stated that, if the EPA fails to take strong action on this issue, the Clean Power Plan will not live up to its intended promise, regardless of whether states achieve their 2030 carbon emission targets.

Commenters suggested that the EPA undergo rulemakin g in a timely manner in order to address the potential dangers from fracking, such as contam ination of ground water supplies, stress on the availability of water supplies, and management of wastewater. Commenters also expressed concerned with air emissions from flares operated a t some fracking installations. Commenters stated that, according to a Natural Geographic arti cle published on May 22, 2014, an estimated 5 million cubic feet of natural gas was flared withou t permits on public land in 2013, which is enough to meet the annual needs of about 50,000 Ame rican homes. Commenters urged the EPA to pursue rule-making to address this waste and unn ecessary pollution in a timely manner. Commenters expressed concern with any potential add ition/expansion of pipelines due to the increased use and production of natural gas. Commen ters stated that any pipelines that are added or expanded due to increased capacity must undergo careful environmental review to make sure that any potential leaks are minimized and are swif tly and adequately addressed when they

occur.

Commenters recommended the EPA set standards to dir ectly curb methane emissions from the oil and gas sector, the second largest industrial c ontributor to greenhouse gas emissions.

Comment 25: Commenters stated that, because upstream emissions or impacts are not part of the source category sought to be regulated, and the EPA has appropriately not considered those impacts in this proposal.

Response 25: See section V.D. of the final rule preamble of the CPP and Chapter 3 of the GHG Mitigation Measures TSD for the CPP Final Rule supp orting the final CPP for EPA’s response to
this comment

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

Commenters noted that, as part of the Regulatory Im pact Analysis ("RIA") for the proposed rule, EPA analyzed potential upstream net methane emissio ns impacts associated with increased use of natural gas in the power sector. Commenters stat ed that the EPA's consideration of these impacts was appropriately limited to an appendix to the chapter of the RIA considering economic100

and energy impacts. Commenters stated that CAA sect ion 111(d) provides for state plans to regulate "any existing source", thus, the EPA canno t include "upstream" emissions in its determination of guidelines for state determination of BSER. Commenters stated the affected sources in this proposed rule are fossil fuel-fired boilers, IGCC units, and stationary gas-fired combustion turbines. Commenters added that, on the specific analysis EPA performed in this area, ANGA did not agree with EPA's use of the 2013 Greenhouse Gas ("GHG") Emissions Inventory for underlying data in the analysis as op posed to the more recent 2014 GHG Emissions Inventory. Commenters encouraged the EPA to rely on the most recent inventory, given the significant changes to the inventory over the past five years. Commenters added that they do not support the use of the inventory for regulatory pur poses and we look forward to continuing to work with EPA to update the inventory to more accur ately reflect emissions.

3.2.2 Magnitude of generation shifts among existing EGUs

This section discusses specific issues related to t he EPA’s building block 2—Generation Shifts Among Affected EGUs. Issues are largely related to NGCC units and include historical capacity, nameplate capacity, baseline capacity, permit const raints, individual unit limitations and abilities, annual average availability, and peak demand.

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

Comment 1: The EPA should adjust the 2012 baseline NGCC capaci ty factors using a 50% displacement factor in states with high wind penetr ation.

Response 1: The EPA disagrees. The EPA believes that the annua l capacity factor in the final rule is sound and can be met in states with high wi nd penetration. The annual 75% net capacity factor is conservative (see GHG Mitigation Measures TSD). In response to additional analysis and many comments, we have modified the proposal an d RIA – the establishment of CO2 emission reduction standards is regionally based. T he 111(d) final rule requires that states develop plans that establish emission standards for affected EGUs. We are providing states with substantial flexibility as to how they structure th ose plans to achieve the 111(d) requirements. The flexibility includes, for example, the choice o f approaches, trading, time to develop plans, additional time before the start of the interim per formance period (postponed from 2020 until 2022), and the ability to shift emission rate achie vement between performance periods. The Building Blocks are not prescriptive, and states ma y consider local circumstances as they develop their plans, including system reliability, fuel diversity, other regulatory requirements and infrastructure. See sections V.D, VIII.A, VIII.C an d VIII.G of the final rule preamble of the CPP and Chapter 3 of the GHG Mitigation Measures TSD fo r the CPP Final Rule supporting the final

CPP.101

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

Commenters argued that EPA needs to consider the im pact of high levels of wind penetration and recalculate the baseline NGCC capacity factors for each state. The commenters argued that the flexibility and dispatch characteristics of NGC Cs means that wind power sources tend to displace NGCC generation; from 32.6% in the MISO re gion up to 83% in the West and 87% in ERCOT. The commenters stated these wind/NGCC "displ acement factors" demonstrate that NGCCs in states with high wind penetration have a l ower capacity factor due to the operation of wind generation in those states and their utility s ystems. Therefore, the commenters added, the 2012 baseline NGCC capacity factors used in EPA's B lock 2 methodology are lower in states with significant renewable energy than they would h ave been absent these pre-2012 RE investments and resulted in more stringent Block 2 calculations and emission targets in states with higher renewables. The commenters suggested th at a reasonable national estimate of the wind/NGCC displacement factor is 50% and provided a table with re-calculated 2012 baseline NGCC capacity factors for states that have NGCCs.

Commenters opposed EPA's existing NGCC capacity fac tor (70%) and argues that it penalizes states and companies that operate these facilities to support the integration of renewable generation. The commenters requested that EPA recal culate the emission rate goals by applying a 50 % displacement factor to existing combined cyc le capacity for states with high integration
of renewable resources.

Comment 2 Commenters suggested the EPA’s analysis did not acc ount for permit restrictions on NGCC units that limit ramping up operations.

Response 2 For the EPA’s response to this comment, see section V.D of the final rule preamble

of the CPP.

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

Commenters questioned why EPA's analysis didn't account for p ermit limits on NGCC units that limit ramping up operations. If the EPA correc ts this error, the commenters questioned if this will this change be made prior to finalization and reflected in reduced state goals with adequate
time for comment.

Comment 3: Some commenters generally supported the EPA's propo sal for Building Block 2 with respect to a 70 percent capacity factor.

Response 3: The EPA disagrees with the establishment of a CO2 emission reduction standard calculation using less than a 75 percent capacity f actor for NGCC units. For the EPA’s response to this comment, see section V.B and V.D of the fin al rule preamble of the CPP and chapter 3 of the GHG Mitigation Measures TSD for the CPP Final R ule.102

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

Commenters stated that the CPP's emission reduction targets reflect an achievable, adequately demonstrated and cost-effective system of emission reduction, and that the Proposed Rule has appropriately determined that it is feasible and co st-effective for states to take advantage of existing NGCC fleets and low natural gas prices. Co mmenters noted that the CPP supports, through IPM modeling, that 70 percent utilization o f existing and under construction NGCC is technically feasible. Commenters added that IPM als o was able to successfully simulate 75 percent NGCC utilization nationally.

Commenters agreed that past NGCC dispatch increases show the practical feasibility of increasing dispatch. Commenters stated that IPM mod eling confirms the feasibility of a 70% NGCC dispatch target (79 FR 34864).

Commenters expressed the belief that most NGCC faci lities have the technical capability to operate at an average annual capacity factor of 65 or 70 percent. Commenters stated that FPL currently operates approximately 14,000 MW of NGCC capacity in Florida, and that in FPL's operating system, nuclear units generally satisfy b ase load needs while the NGCC units operate primarily in a load-following mode with capacity fa ctors ranging from 50 percent to 70 percent. However, according to the commenters, the NGCC unit s are designed for and capable of operating in base load, which would include a 70 pe rcent capacity factor.

Commenters said that the capacity to operate NGCC p lants at a 70 percent capacity factor is well established, as more than ten percent of existing N GCC plants have operated at a 70 percent capacity factors in recent years. (Greenhouse Gas A batement TSD) Commenters added that IPM modeling demonstrates that operating each state's N GCC fleet at such a capacity factor (on average) is technically feasible, and the costs of such re-dispatch are also reasonable.
Commenters stated that the IPM model shows the cost of such re-dispatch to be 30 or 33 dollars per metric ton of avoided carbon, depending on whet her a regional or state-specific approach was taken. Commenters agreed with the EPA's conclus ion that these costs are reasonable even without considering the additional public health an d climate benefits that such a shift in dispatch
would create.

Commenters stated that the proposal rightly recogni zed that due to the interconnected nature of the power grid and interoperability of different ge neration resources, reduced use of high carbonintensity EGUs would result in increased utilizatio n of other generation resources, such as efficient NGCC plants.

Comment 4: Some commenters supported the position that a 70 pe rcent utilization rate is technically and economically feasible.

Response 4: The EPA disagrees with the establishment of a CO2 e mission reduction standard calculation using less than a 75 percent capacity f actor for NGCC units.. For the EPA’s response to this comment, see section V.D of the final rule preamble of the CPP and chapter 3 of the GHG Mitigation Measures TSD for the CPP Final Rule.103

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

Operating experience supports the Proposal.

Commenters stated that the proposed 70% NGCC utiliz ation rate is technically and economically feasible under a wide range of operating conditions in various regions and climatic conditions. Commenters stated it is the operator of the largest fleet of NGCC facilities in the U.S., and that Calpine has extensive experience operating NGCC fac ilities. Commenters supported several statements in the Proposed Rule (79 FR 34830, 34864 ):

The primary re-dispatch opportunities among existin g units available to EGU owners and grid operators generally consist of opportunities to shi ft generation among various fossil fuel-fired units, in particular between coal-fired EGUs and NG CC units. In 2012 roughly 10 percent of existing NGCC units operated at annual utilization rates of 70 percent or higher, while on a seasonal basis, a significant number of NGCC units have achieved utilization rates between 50 and 80 percent. In modeling the impact of a 70% NGC C utilization rate, EPA found that projected wholesale electricity price increases ove r the period were less than seven percent in both cases, which is well within the range of histo rical electric price variability.

Commenters supported the EPA's goal of significantl y increasing generation from existing NGCC capacity. Commenters stated that LS Power owns approximately 9,500 MW of natural gas fired generation and, based on LS Power's own e xperience, it is clear that a considerable amount of the country's existing NGCC generation is underutilized. The commenters further stated that these units represent significant sunk capital investment with existing infrastructure in place. The commenters asserted that greater relianc e on these units represents some of the lowest hanging fruit available to bring about GHG reductio ns (NODA at p. 19). Commenters reported that they are confident that well-maintained units can reliably achieve the 70 percent utilization rates described by EPA in its proposal.

Commenters stated the EPA's proposed rule underesti mates expanding unit-level utilization capabilities throughout the NGCC fleet since high u tilization (greater than 70 percent) of NGCC power plants is technically feasible and has been d emonstrated in operation. Commenters stated gas turbine manufacturers can supply gas turbines w ith a mechanical availability of greater than 90 percent. The commenters further stated the gas t urbine's performance establishes a baseline for the overall reliability and availability of the NGCC suite of equipment, as the HRSG and STG components have greater reliability than the ga s turbine, and planned maintenance is simultaneous for the GTG: the HRSG is a piece of fi xed equipment that requires inspections every 5 to 10 years and the steam turbine generator 's availability is greater than 99 percent.

While seeing no technical issue with individual NGC C units physically operating at a 70% capacity factor, commenters noted that there is lit tle long-term operating experience with widespread and sustained operation of a majority of NGCC units at 70% capacity factor.

NGCC units are more efficient running at a higher c apacity.

Commenters stated it is worth noting that LS Power' s experience with these units demonstrates greater efficiencies can be achieved when operating at even higher and more steady state
conditions. The commenters further stated these uni ts are quite capable of operating at or near a104

90 percent capacity factor and increased utilizatio n of these units should result in lower emission rates than such units experience at lower capacity factors. The commenters recommended that, where appropriate, EPA should consider capacity fac tors for NGCC units greater than the 70 percent benchmark identified in the proposal.

Given careful planning, 70% capacity is achievable.

Commenters stated the EPA's 70 percent NGCC utiliza tion rate target is achievable with a sufficient phase-in, and based on GE's experience i t represents a reasonable target for Building Block 2 for purposes of establishing state-specific emission goals.

Commenters stated that, if natural gas is to assume the base load required to meet EPA's scenario, the four issues listed below will need to be addressed with careful modeling and planning. The commenters asserted that, assuming st ates follow EPA's suggestion of tilting the market to an environmental dispatch, it would seem likely this will cause some increase in the price of electricity.

1. Economic or merit order dispatch: Even with today's historically moderate to low natural gas pricing, not all NGCCs can compete in all marke ts based on bidding into competitive markets. EPA proposes that states will fix this sit uation by forcibly adjusting dispatch
order.

2. Over-capacity in certain regions of the Federal Ene rgy Regulatory Commission, particularly regulated states: In many regions, the re still exists excess capacity, largely owing to the fact that electricity demand has not f ully recovered to pre-recession levels. With much of the NGCC capacity comprised of indepen dent power producers or merchant plants, we see preferential dispatch for t he regulated resources, thus leaving merchant plants as peak suppliers.

3. Available fuel resources: Distribution infrastructu re for natural gas still remains problematic in certain regions, so supplying NGCCs with adequate gas year round will cause some NGCCs to run on liquid fuels or shut dow n, reducing capacity factors.

4. Consideration of plant locations and grid requireme nts for geographical area power demand: A few units may be located in areas where t he demand is insufficient to reach these proposed capacity factors.

Average annual approach is appropriate.

Commenters recommended that, in evaluating feasibil ity on a unit by unit capacity utilization, the EPA should continue to use an average annual ap proach, consistent with the rule's compliance requirements. Commenters stated that som e public commentary misconstrues EPA's 70 percent target utilization as an assumption that every plant is capable of running at 70 percent every day of the year, concluding that limits on na tural gas supply for power generation during peak demand makes it impossible to meet the standar d. Commenters stated this conclusion is inappropriate and inconsistent with EPA's analysis. The commenters recommended that, in evaluating feasibility on a unit by unit capacity u tilization, the EPA should continue to use an average annual approach, consistent with the rule's compliance requirements. The commenters105

stated that such an approach allows for varying lev els of capacity utilization as market conditions dictate, the utilization of all types of power plan ts is an economic decision based on market demand, fuel cost, power price and available genera tion supply. The commenters further stated that, to meet an average 70 percent utilization, a given unit could run at a higher capacity utilization rate over some period of time and at a lower rate or not at all on other days.

Data support the 70% capacity factor.

Commenters stated that based on EPRI and other know n research, there are no technical reasons why individual NGCC units cannot maintain 70% capac ity factors over the long term.

Commenters stated that historical data analyses sug gest the 64 percent average NGCC utilization factor and 70 percent maximum NGCC utilization fact or relied on by EPA in goal setting are reasonable. According to the commenters, historical capacity and generation data from the Ventyx Velocity Suite shows the NGCC fleet historic ally has achieved utilization factors equal or close to the 64 percent average utilization fact or and 70 percent maximum utilization factor assumed in EPA's Building Block 2. Commenters state d that the U.S. NGCC fleet has operated at a 60 percent utilization factor on a week-long b asis, just four percentage points shy of the average utilization factor in EPA's methodology; si milarly, it has operated at 58 percent utilization on a month-long basis, just six percent age points lower than the 64 percent utilization factor EPA assumes. Commenters presented a figure i llustrating that all six regions of the country have achieved weekly utilization factors of 62 percent to 66 percent, close to or above the 64 percent average utilization factor, and that the six regions have also achieved monthly utilization factors between 55 and 64 percent. Comm enters included another figure showing that the NGCC fleets in 25 of 41 states with NGCC capaci ty have operated at a weekly utilization factor of 64 percent or higher, and that 16 states have operated at a monthly utilization factor of at least 64 percent.

Commenters stated that forecast analyses suggest th e 64 percent average NGCC utilization factor and 70 percent maximum NGCC utilization factor reli ed on by EPA in goal setting are
reasonable. The commenters indicated that forecasts show the potential to re-dispatch coal to NGCC generation within the existing fossil fleet an d energy system infrastructure. According to the commenters, the MIT Future of Gas study report ed the results of modeling, which estimated the availability of re-dispatch and associated CO2 emissions reduction between the existing coal and gas fleet in the country and that found approxi mately 420 million metric tons of CO2 could be reduced, by displacing 700 TWh of coal generatio n through re-dispatch of NGCC. Commenters noted that the study found an 87 percent capacity factor for these natural gas units.

Commenters stated that Power Switch modeling result s show that EPA's proposed 70 percent utilization factor for natural gas fired units is r easonable. Commenters compared the Power Switch results to the EPA CPP modeling, and found t hat the amount of coal generation (and, therefore CO2 emissions) displaced by higher utiliz ation of natural gas in the policy modeled in Power Switch is close to the re-dispatch effect mod eled by EPA in Building Block 2. (Compare EPA IPM result found at "Regulatory Impact Analysis for the Proposed Carbon Pollution Guidelines for Existing Power Plants and Emission S tandards for Modified and Reconstructed Power Plants" Table ES-2 (371 MMT CO2 reduction fro m base case in 2020) with Power Switch at 6 (308 MMT CO2 reduction from base case in 2020) .)106

Commenters indicated that because the Power Switch approach and EPA's building block 2 include comparable assumptions, the NorthBridge eco nomic analysis demonstrating the feasibility of the Power Switch approach also lends support for the reasonableness of the EPA's proposed building block 2, and therefore to the EPA 's proposed target emission rates in general. Commenters presented Figure 15 from the NorthBridge report, which shows the average national utilization factor (or capacity factor or ("CF")) f or coal units would fall from 67 percent to 58 percent, while the utilization factor for natural g as combined cycle units would increase from 48 percent to 65 percent. Commenters noted that this i ncrease in gas unit utilization factor is almost identical to the 64 percent national average natura l gas utilization factor EPA derived in building block 2 in the CPP proposal. Commenters stated that the NorthBridge modeling predicts that in several states, natural gas combined cycle units wo uld exceed the 70 percent utilization factor level, some by a substantial amount (up to 85 perce nt) and that, thus, the NorthBridge analysis provides evidence that EPA's proposed 70 percent ut ilization ceiling is reasonable, if not conservative, and provides support for EPA raising the natural gas unit utilization ceiling to at least 75 percent.

Commenters confirmed that a 70% average NGCC utiliz ation rate is technically and economically feasible. The commenters stated that C alpine recently analyzed the Generating Availability Data System ("GADS") data from Calpine 's NGCC facilities and the GADS data indicate that Calpine's NGCC facilities have operat ed at a 70% or greater capacity factor dozens of times in many different states and climatic cond itions. Commenters stated that, between 2001 and 2013, 25 different Calpine plants (including bo th cogeneration facilities and standalone (i.e., "merchant") power generation facilities) have opera ted at greater than 70% annual capacity
factor 97 times. Commenters stated this has occurre d in eight different states (Arkansas, California, Louisiana, Maine, New York, Oregon, Pen nsylvania and Texas), in all climatic
conditions from the desert southwest to the northea st. The commenters stated that the GADS data demonstrate that even higher annual capacity f actors are achievable: individual power blocks have operated at greater than 75% capacity f actor 57 times and greater than 80% capacity
factor 27 times.

Commenters stated that running NGCCs at high utiliz ation rates (>70 percent) is technically feasible and will be done in practice when power ge neration economics support it. Commenters stated that it is clear that a target utilization r ate at or above 70 percent is adequately supported by gas turbine manufacturers and available data. Th e commenters reported that, based on their review of EPA's CEMS hourly operating data, 40 perc ent of currently operating NGCCs in the U.S. (211 units) have achieved at least one year si nce 2000 where their annual capacity factor was greater than 70 percent. Commenters stated they have also found that 83 percent (444 units) of currently operating NGCCs in the U.S. have achie ved at least one month since 2000 where their monthly capacity factor was greater than 70 p ercent. The commenters concluded this data supports EPA's conclusion that NGCC units are able to achieve or exceed a 70 percent capacity
factor.

Commenters suggested that, because cogeneration uni ts have the same technical abilities as NGCC power plants from a capacity factor standpoint , high utilization of cogeneration units demonstrates that NGCC units can also run at high u tilizations. Commenters stated that, because cogeneration units are similar to NGCC units and li kewise include a GTG and HRSG, EPA should review the experience of cogeneration units. The commenters stated that, because of the107

steam linkage between the power generation and the steam generation for the industrial process, cogeneration units typically run as base-load gener ators to support the steam needs of the facility, often at a utilization rate of above 85 p ercent, as demonstrated by EPA CEMS hourly operating data.

Historically low dispatch not due to technical abil ity.

Commenters asserted that currently, many combined c ycle units may not run at a high capacity factor because of factors related to economic dispa tch, not technical ability. The commenters stated the demand profile throughout the day, as we ll as operating response characteristics, have typically favored coal plants running as base load generators with NGCCs running as mid-merit generators. The commenters further noted that coal plants have historically had cheaper fuel costs than gas plants and are not quick responders to operational changes, so they often run as base-load power generators (since 2009 the U.S. coa l fleet has had an average capacity factor less than 70 percent). Commenters concluded that, g iven their technical reliability, with the right economic conditions, NGCC plants can compete for ba se load operations with coal plants, as already demonstrated in 2012.

Commenters stated that NGCC plants are technically able to operate at much higher capacity factors than they have historically operated. The c ommenters stated that historical operation is more dictated by generation demand and economical d ispatch, not technical availability. The
commenters further stated that turbines in GE's ins talled fleet have demonstrated availabilities (the hours the turbine is available to operate whil e considering necessary downtime for maintenance or repairs) in excess of 90 percent. Th e commenters reported that GE's 7F is the most common gas turbine within the 60 Hz fleet, the re are nearly 800 7F turbines in operation with over 35 million fired hours and 850,000 starts across this population, and these units have demonstrated an average availability of over 95 per cent. The commenters further reported that a 7F NGCC plant-level availability--which includes an y necessary downtime for steam turbines, generators, or other balance of plant components--c onsistently exceeds 85 percent. The commenters concluded that, based on this fleet, the EPA's estimate of plant level availability of 87 to 92 percent is generally achievable across the operating fleet.

NGCC can meet load-following needs at the 70% utili zation rate.

Commenters stated that a 70% utilization rate is co nsistent with the role NGCC facilities are increasingly being called upon to play in assuring reliability of the electric grid in light of the increasing market penetration of intermittent renew able generation sources. Commenters stated that Building Block 2's assumed 70% utilization rat e is fully consonant with the role NGCC facilities are increasingly being called upon to pl ay in assuring reliability of the electric grid and providing both power and the other ancillary servic es needed to support the rapid integration of
intermittent RE sources. Commenters stated the exis ting fleet of highly efficient, flexible and fast-ramping NGCC facilities can deliver electricit y at the assumed 70% utilization rate, while operating as load following units, which are often controlled directly by the relevant independent system operator ("ISO") and have their output rampe d up and down on a real-time basis as both the demand for electricity and the load supplied by wind and solar generating sources changes throughout the day. Given the load-following and fa st-ramping capabilities of the existing NGCC fleet, commenters stated there is no inconsist ency between the assumed 70% utilization108

rate and the role NGCC facilities will increasingly play in enabling the integration of intermittent renewable generating sources and ensuring the relia bility of a more dynamic electric grid.

Commenters stated that, with careful modeling and p lanning, even at a 70 percent capacity factor, there can be adequate head room for NGCCs t o still provide significant backup to renewables, depending on demand. The commenters sta ted that backup for renewable power intermittency would seem most likely to be covered by simple cycle units that can quickly enter the market and, unless they exceed 219,000 megawatt hours of operation, will remain exempt from regulation. Commenters stated this may put fur ther strain on the natural gas delivery system. Commenters added that it will be logical th at backup power will come from a portion of the existing coal fleet that has been reduced in ca pacity factor in favor of NGCCs.

Comment 5: Commenters stated that 70 percent utilization for natural gas generation is achievable and addressed the ability of several spe cific states to meet a 70% capacity.

Response 5: The EPA agrees to the extent that data support an c apacity factor for NGCC units of 75 percent. For the EPA’s response to this comme nt, see section V.D of the final rule preamble of the CPP and Chapter 3 of the GHG Mitiga tion Measures TSD of the final CPP.

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

Commenters stated the 70 percent capacity factor is a reasonable benchmark for NGCC usage, since many of these plants were designed to run at much higher rates, above 85 percent. Commenters stated that a regionalized approach to s etting gas re-dispatch targets (see below) would help alleviate concerns that some stakeholder s have raised about the infrastructure needed to provide higher volumes of natural gas to these p lants.

Commenters stated Alabama has sufficient natural ga s capacity and sufficient natural gas supplies for re-dispatch to a 70 percent capacity f actor. Commenters stated that, although in 2012 Alabama's primary energy source was natural gas, on ly six years prior, Alabama's energy picture was much different: coal generation was dominant, e xceeding natural gas generation by more
than four times. Commenters stated the Clean Power Plan assumes Alabama will continue this trend and, considering that Alabama accomplished a much more significant shift over just the last several years, almost tripling its gas generat ion while cutting coal generation nearly in half, this comparatively moderate shift appears feasible. Commenters stated this shift is in line with pronouncements by Southern Company, the parent comp any to Alabama's largest utility, Alabama Power Company. Commenters stated that Alabama has significant amou nts of natural gas combined cycle (NGCC) capacity - more than 10,0 00 MW and the EPA's analysis shows this capacity was utilized at a rate of just 59 percent in 2012. Commenters concluded that Alabama has sufficient underutilized capacity to allow for re-dispatch up to the target rate 70 percent.

Commenters stated that a key related consideration is whether Alabama has sufficient natural gas supply. Commenters stated the EPA's analysis assume s that Alabama's NGCC units are fully unconstrained in terms of pipeline capacity. Commen ters stated it is important to test this assumption because states requiring pipeline expans ion to allow their NGCC units to achieve 70109

percent capacity factors will have higher costs of compliance associated with Building Block 2, and may therefore elect to pursue other more cost-e ffective compliance strategies. Commenters stated that Synapse Energy Economics, Inc. (Synapse ) analyzed the amount of increased gas consumption that would occur as a result of increas ing Alabama's NGCC utilization to 70 percent. Commenters stated Synapse determined that with gas re-dispatch, the total gas delivered to consumers during the peak winter month would inc rease by approximately 140 MMcf per day. Commenters stated this estimated increase in peak m onth gas use represents a 7-percent increase in consumption, but is less than 1 percent of the a vailable supply. Commenters stated that Synapse determined that additional gas infrastructu re would not be needed as a result of redispatching existing combined cycle generating plan ts in Alabama. Commenters stated Synapse also performed an analysis to determine whether the re would be sufficient natural gas capacity to meet demand during peak hours and determined that i n both of Alabama's two eGrid subregions there is sufficient natural gas capacity to meet pe ak loads.

Commenters stated that, because Alabama has both su fficient existing NGCC capacity and sufficient natural gas supplies for re-dispatch to a 70 percent capacity factor, the EPA's assumptions for Alabama under Building Block 2 are not unreasonable. Commenters noted that Alabama is not bound to pursue natural gas re-dispa tch to the degree assumed by EPA, provided the state meets the overall 2030 target. Commenters stated that, if Alabama simultaneously adds new renewable generation and energy efficiency meas ures at even just 80 percent of the levels assumed by EPA, and those measures are allowed to d isplace fossil generation, Alabama can achieve its target with re-dispatch to a capacity f actor of just 64 percent - and thereby avoid undue risk of fuel price volatility.

Commenters reported that the best system for emissi on reduction will work for Arkansas, with the initial and highest carbon emission reductions coming from increased deployment of natural gas through CCGT, combined cycle gas turbines, and a reduction of 30 percent, or 68 percent of the target from the state.

Commenters stated that Georgia has both sufficient existing NGCC capacity and sufficient natural gas supplies for re-dispatch to a 70 percen t capacity factor. Commenters stated that, under Building Block 2, EPA assumes that Georgia ca n reasonably and cost effectively increase the dispatch of its natural gas fleet by another 13 .8 million MWh, while proportionately decreasing its coal generation over a period of 14 years. Commenters stated such a shift is both feasible and in line with pronouncements by Souther n Company, the parent company to Georgia's largest utility, Georgia Power Company. C ommenters stated that, since the EPA's analysis shows Georgia's capacity was utilized at a rate of just 51 percent in 2012, Georgia has sufficient underutilized capacity to allow for re-d ispatch up to the target rate 70 percent.

Commenters stated that a key related consideration is whether Georgia has sufficient natural gas supply. Commenters referred to a 2013 Synapse study in which Synapse analyzed the amount of increased gas consumption that would occur as a res ult of increasing Georgia's NGCC utilization to 70 percent. Commenters stated that Synapse deter mined that with gas re-dispatch, the total gas delivered to consumers during the peak winter month would increase by approximately 350 MMcf per day. Commenters stated this estimated incr ease in peak month gas use represents an 18-percent increase in consumption, but is less tha n 5 percent of the total pipeline capacity into the state. Commenters stated that Synapse determine d that, while some amount of additional110

pipeline capacity may be required to facilitate thi s level of re-dispatch, the need for gas infrastructure does not appear to be as critical as it would be for other states.

Commenters stated that Synapse also performed an an alysis to determine whether there would be sufficient natural gas capacity to meet demand duri ng peak hours. Commenters stated Synapse examined hourly markets data for Georgia's two eGri d subregions - SERC South and SERC Tennessee Valley - and determined that in both ther e is sufficient natural gas capacity to meet peak loads. Commenters stated that the Synapse analysis indicat ed that, under the assumptions modeled, NGCCs in Georgia exceed the EPA's natural gas re-dispatch target of 70 percent and reach an 80 percent capacity factor.

Commenters asserted that, if EPA assumes a capacity factor of greater than the 55% for underconstruction NGCC units in NC (if EPA assumes that these under construction NGCCs could increase to a 70% capacity factor), an additional 1 5% of their ultimate output is assumed to be available for re-dispatch. The commenters reported that, in 2012, there were 2,249 MW of underconstruction NGCC capacity in North Carolina and th at the three million MWh of re-dispatch to
under-construction NGCCs would lower North Carolina 's target emission rate by an increment of
126 lbs/MWh. The commenters further asserted that N orth Carolina could achieve even greater generation from NGCC plants. According to the comme nters, a study by Synapse that analyzed the potential for NGCC plants to displace coal-fire d power plants, NGCC plants in North Carolina can achieve capacity factors of 80%.

Commenters stated that 70 percent utilization for n atural gas generation is achievable for Ohio, although this will depend on a number of policy and technical prerequisites. Commenters stated the national average natural gas power plant utiliz ation increased 10% between 2005 and 2010 and there is a surplus of underutilized baseload na tural gas generators in the United States, including in Ohio, so there is opportunity to use t hese ratepayer-funded plants to the fullest capacity possible. Commenters stated the availabili ty of adequate natural gas supply, storage and pipeline capacity will be a factor in achieving gre ater natural gas generation. Commenters noted that natural gas pipelines prefer to operate as clo se to capacity as possible to maximize revenue, which means adequate supply could easily be achieve d to support the increased firing of these plants.

Commenters stated that Tennessee could achieve a 70 percent capacity factor across its existing NGCC fleet with existing resources and without sign ificant capital investment. Commenters provided the following three points to support thei r position:

• First, EPA assumed that a state's generation can on ly be re-dispatched to this 70 percent level if there is enough historical fossil generation to be displaced. Since Tennessee's 2012 coal and steam generation was 34.4 million MWh, there is sufficient generation to allow for re-dispatch of t he state's NGCCs up to the 70 percent maximum.

• Second, the 70 percent natural gas capacity assumpt ion is reasonable in light of existing pipeline capacity. According to the U.S. E nergy Information Administration ("EIA"), the total capacity of the g as pipelines delivering into Tennessee is 14,685 MMcf per day. The 70 percent ca pacity assumption would111 increase the level of total gas delivered to custom ers during the peak month from 1,046 MMcf per day to 1,156 MMcf per day. After sub tracting the 5,460 MMcf per day that flows out of Tennessee to other market s, the average daily amount of pipeline capacity available to supply Tennessee mar kets would still be more than eight times the peak month gas use (~9,000 MMcf per day of capacity vs. ~1,100 MMcf per day of consumption). Thus, existing pipeli ne capacity should be able to accommodate the additional capacity at existing nat ural gas EGUs.

• Finally, Synapse Energy Economics analyzed the 2012 U.S. electric dispatch system and evaluated the available, unused natural gas generation that could feasibly displace coal-fired generation on a region -by-region basis. Tennessee is in the SERC Tennessee Valley subregion. The Synapse analysis indicated that this region could exceed EPA's natural gas re-dispatch t arget of 70 percent and, under the assumptions modeled, reach an 80 percent capaci ty factor.

Commenters supported the assumption that the existi ng pipeline capacity is adequate to achieve the 70 percent natural gas capacity assumption in V irginia. Commenters provided the following analysis of pipeline delivery in Virginia:

According to the EIA, the total capacity of the gas pipelines delivering into Virginia is 8,011 MMcf per day, which includes 1,800 MMcf per d ay of pipeline capacity entering Virginia from the Cove Point LNG terminal. The 70 p ercent capacity assumption would increase the level of total gas delivered to custom ers during the peak month from 1,485 MMcf per day to 1,583 MMcf per day. Even subtractin g the 1,800 MMcf per day of gas inflow capacity from the LNG terminal and the 2,175 MMcf per day that flows out of Virginia to other markets the average daily amount of pipeline capacity available to supply Virginia markets would still be more than tw o and a half times the peak month gas use (~4,000 MMcf per day of capacity vs. ~1,600 MMcf per day of consumption). Thus, existing pipeline capacity should be able to accomm odate the additional capacity at existing natural gas EGUs. In addition, Synapse Ene rgy Economics analyzed the 2012 U.S. electric dispatch system and evaluated the ava ilable, unused natural gas generation that could feasibly displace coal-fired generation on a region-by-region basis. Parts of Virginia are in three different sub-regions: SRVC, SRTV, and RFCW. The Synapse analysis indicated that each of these three regions could exceed EPA's natural gas redispatch target of 70 percent and could, under the assumptions modeled, reach an 80 percent capacity factor.

Commenters stated that, based on utility plans and the reasonableness of the assumption as applied to Virginia, they included the 70 percent a ssumption in our calculations. Commenters stated that, as with EPA's calculation, the increas ed capacity from existing NGCC units were assumed to operate at the average historical emissi ons rate of 903 lbs/MWh and applying this assumption results in a decrease from 1,383 lbs/MWh to 1,245 lbs/MWh, a reduction of 138
lbs/MWh.

Commenters stated that Clean Wisconsin's own analys is of NGCC EGUs in Wisconsin provides evidence both that those units could operate at hig her capacity factors, and that there is significant room for increases in operation. Commen ters stated they found that half of the fleet112

was operating at capacity factors between 45% and 5 5% in 2012, with an overall system average of just under 40%. Commenters stated these capacity factors are significantly higher than those of so-called "peaking plants," which have an averag e capacity factor of less than 10% in the Midwest Reliability Organization's territory, accor ding to the EIA suggesting that they could easily ramp up in the short-term, even before 2020, without a significant impact on their existing operation. Commenters supported the assumption that existing natural gas EGUs could operate at a 70 percent capacity factor in Virginia. Commenter s noted this 70 percent assumption reflects plans that Virginia's utilities already have in pla ce and stated that, excluding the units for which generation contracts with Dominion will expire in t he next few years (Hopewell and Doswell), the average capacity factor for existing natural ga s EGUs in Virginia was already 71.6 percent in 2012. Commenters also noted that, in Virginia, ther e is enough historical fossil generation to be displaced to achieve a 70 percent capacity factor i n the state's natural gas EGUs.

Commenters stated there is no technical reason why NGCC EGUs in Wisconsin and around the country could not ramp up dispatch to 70%. Commente rs referred to a report by the Massachusetts Institute of Technology which indicat ed that NGCC generators are able to operate at capacities as high as 85%. Commenters stated tha t, while there are a variety of factors that determine dispatch, there is no technical limitatio n for NGCC to ramp up their capacity to factor to at least 70%, as assumed by the EPA. Commenters referred to an analysis conducted by Synapse Energy Economics, Inc. which concluded that in the eGRID subregions that Wisconsin is in, there is a combined potential to increase ge neration from NGCC to 54 TWh assuming an 80% capacity factor. Commenters stated that nationw ide potential is far greater. Commenters stated that this report also concludes that there i s "ample, existing, unused potential that would require no additional plant construction costs to d isplace the generation from existing coal capacity."

Comment 6: Commenters suggested revising the capacity factor f or NGCC facilities under construction under Building Block 2.

Response 6: The EPA agrees to the extent that under constructio n NGCC units are appropriately considered to have a capacity factor of 55 percent. EPA has reviewed comments on this topic and is retaining the 55 percent capacity factor use d in the proposal. See Preamble Section VI and the goal setting TSD for further explanation.

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

Commenters stated this action would lower the capac ity factors of NGCC plants to achievable factors, based on the characteristics of specific e nergy markets such as the Electric Reliability Council of Texas (ERGOT). Commenters stated that op erating NGCC units at an average 70% capacity factor is not realistic for Texas, even wi th low natural gas prices resulting from shale. Commenters noted that NGCC capacity factors in Texa s are typically in the 40% range and adjusting the capacity factor from 70% to 50-55% pr ovides opportunity for carbon reduction to be achieved while maintaining reliability and affor dability for CPS Energy customers.113

Commenters questioned EPA's assumption regarding al location of capacity for "under construction" NGCCs. Commenters asked EPA to explai n its basis for assuming that NGCC
units which are "under construction" can allocate 1 5% of their capacity to displace coal generation.

Commenters recommended that EPA increase the amount of generation from under construction NGCC units incorporated in the BSER re-dispatch cal culation by allocating a capacity factor of 55 percent as available for re-dispatch purposes (a nd a capacity factor of 15 percent as unavailable), instead of the 15 percent available ( versus 55 percent unavailable) that is assumed in the draft proposal. Commenters said that EPA has overestimated the amount of generation that will be utilized to meet new power demand because m any under construction NGCC plants are being built to replace retiring coal generation dee med uneconomic due to age, lack of pollution controls, and cheaper alternatives. Commenters note d that of the nine states with under construction NGCC units incorporated into the Build ing Block 2 target methodology, all except for California have significant planned coal genera tor retirements scheduled between 2012 and 2018, and that the total capacity of planned coal r etirements in these states outweighs the capacity of under construction NGCC plants by nearl y a factor of 2 to 1 (16,366 MW vs 8,938 MW).Commenters stated that a substantial and quick shift from 45% to 70% by 2020 would fundamentally change the way the ERCOT market opera tes, moving from economic dispatch to emissions dispatch, and has the potential to cause reliability issues. Commenters requested the EPA use a 50-55% capacity factor for NGCC under Bui lding Block 2 and phase the switch in at a slower pace. Commenters stated this action would lower the capacity factors of NGCC plants
to achievable factors based on the characteristics of specific energy markets such as the Electric Reliability Council of Texas (ERCOT). Commenters st ated that operating all NGCC units at a 70% capacity factor is unrealistic for Texas. Comme nters stated that any dispatch method that preferentially selects resources based on emissions rates, without regard for underlying fuel cost structure, will lead to market uncertainty and seve re price increases. Commenters stated that when the grid is strained, ERCOT may need to requir e coal units to run outside of emissions constraints for reliability.

Comment 7: Commenters recommended the EPA use a less stringen t target of 60 percent annual average capacity factor for NGCC units due to zero- dispatch resources, peak usage needs, and

use of dual-fueled units.

Response 7: The EPA disagrees with the establishment of a CO2 e mission reduction standard calculation using less than a 75 percent capacity f actor for NGCC units.. In response to additional analysis and many comments, we have modi fied the proposal and RIA – the

establishment of CO2 emission reduction standards i s regionally based. The 111(d) final rule requires that states develop plans that establish e mission standards for affected EGUs. We are providing states with substantial flexibility as to how they structure those plans to achieve the 111(d) requirements. The flexibility includes, for example, the choice of approaches, trading, time to develop plans, additional time before the s tart of the interim performance period (postponed from 2020 until 2022), and the ability t o shift emission rate achievement between performance periods. Neither the Building Blocks no r the IPM analyses are prescriptive, and114

states may consider local circumstances as they dev elop their plans, including system reliability, fuel diversity, and other regulatory requirements. Peak load and dual fuel units are addressed in the preamble of the final CPP. See sections V.A, V. B, V.D, VIII.A, VIII.C and VIII.G of the final rule preamble of the CPP and Chapter 3 of the GHG Mitigation Measures TSD for the CPP Final Rule supporting the final CPP.

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

Commenters stated there are constraints on re-dispa tch that make 60 percent a more reasonable estimate of an achievable annual average NGCC utili zation rate for states with a high penetration of natural gas and zero-emissions resources. Commen ters stated that, even though the nationwide NGCC utilization rate is over 60 percent in some pe ak hours, a higher rate of even the suggested alternative of 65 percent will be very difficult to achieve on an annual basis. Commenters stated that market forces coupled with operational realiti es on the system will sustain a dispatch
schedule in the future that could be increased to 6 0 percent but not higher.

Commenters stated that, in states with a high penet ration of Natural Gas-fired generation, EPA's proposed method of increasing NGCC capacity factors to 70 percent cannot be implemented without undesirable re-dispatch of zero-emissions r esources during certain times of the year and reliability impacts during others. Commenters state d that, while unit capability is a relevant consideration, system capability must also be consi dered. Commenters stated that, in ignoring system capability considerations, EPA fails to acco unt for the seasonal variability of electricity demand. Commenters stated that, while capacity fact or is calculated as the total number of MWh produced by a plant divided by the total number of MWh it could have produced were it to operate at its rated capacity for all hours of the year, in reality, all plants cannot operate during all hours of the year as, in the power sector, supp ly must always equal demand for the system to operate within its reliability limits. Commenters s tated that during the spring and fall shoulder months, electricity demand typically falls to a fra ction of its summer and winter levels, which in the New York system means demand can dip below 12,0 00 MW. Commenters stated that, with more than 11,000 MW of zero emissions resources typ ically available during those hours, operating NGCC plants in the manner needed to produ ce a 70 percent annual capacity factor would displace those zero-emissions resources in fa vor of a relatively high-emissions fossil-fuelfired alternative.

Commenters stated that the EPA fails to acknowledge that other gas and coal units are needed during peak usage periods for reliability purposes, and are often dispatched when every NGCC plant is already running at full capacity. Commente rs stated that many of New York's older other gas units are used for specific system reliability purposes and cannot be re-dispatched to NGCC.
Commenters stated that location constraints further limit the ability of NGCC plants to displace other gas and coal units since existing transmissio n constraints do not allow NGCC capacity to be transferred from certain portions of the state t o others. Commenters stated they would welcome the inclusion of other gas units as part of meeting this compliance target implied by this Building Block, but due to the system limitations, additional reductions are not available due to additional utilization of gas units as outlined in the October 28th Notice of Data Availability (NODA).115

Commenters stated that an additional factor concern s the use of oil in these dual-fuel units and recommended that adjustments to the emissions shoul d be ensured for the region's associated CO2 emission rate. Commenters stated that, in order to protect reliable delivery of power during high natural gas use periods, whether during the pe ak summer time load period or winter periods when natural gas deliveries are constrained and pre ferentially routed to residential customers, NYISO rules require generators in the NYMA to combu st oil in dual fuel units to ensure the reliable provision of electricity in the event of a n unforeseen contingency on the natural gas transmission and delivery system. Commenters stated this requirement and its consequence for generation have previously been addressed by the EP A, particularly in its Cross State Air Pollution Rule (CSAPR). Commenters stated that in i ts October 14, 2011 revision to the final rule, EPA noted, in a Technical Support document, t hat it was revising the emission budget for New York because of very specific electric system c onstraints:

EPA is proposing to increase the New York state ann ual NOx, ozone-season NOx, and SO2 budgets to reflect the assumption of near-term operational constraints affecting specific units in New York City and Long Island. Th ese revisions are based on three types of local operating constraints that apply to certain generators in New York City and Long Island, which are referred to here as the N-1- 1 Contingency, the Minimum Oil Burn Rules, and local out-of-merit-order dispatch condit ions.

Commenters stated that, in its February 21, 2012 ru le (77 FR 10345), the EPA addressed the constraints in the NYMA and adjusted upwards the Ne w York NOx and SO2 budget to account
for oil use:

EPA is increasing New York's 2012 and 2014 annual S O2, annual NOx, and ozoneseason NOx budgets based on comments received on th e revisions rule demonstrating that the East River plant is in an out-of-merit-ord er dispatch area with conditions likely to necessitate what would otherwise be non- economic g eneration. EPA re-calculated the emissions from this facility with out-of-merit orde r dispatch to reflect the input assumption changes. These calculations yield increa ses to New York's 2012 and 2014 state budgets for annual SO2 of 84 tons, annual NOX of 694 tons, and ozone season NOx
of 127 tons.

Comment 8: Commenters supported consideration of options betw een 65-70%.

Response 8: The EPA disagrees with the establishment of a CO2 e mission reduction standard calculation using less than a 75 percent capacity f actor for NGCC units. In response to additional analysis and many comments, we have modified the pr oposal and RIA – the establishment of CO2 emission reduction standards is regionally base d. The 111(d) final rule requires that states develop plans that establish emission standards for affected EGUs. We are providing states with substantial flexibility as to how they structure th ose plans to achieve the 111(d) requirements. The flexibility includes, for example, the choice o f approaches, trading, time to develop plans, additional time before the start of the interim per formance period (postponed from 2020 until 2022), and the ability to shift emission rate achie vement between performance periods. Neither the Building Blocks nor the IPM analyses are prescr iptive, and states may consider local116

circumstances as they develop their plans, includin g system reliability, fuel diversity, other regulatory requirements and infrastructure. See sec tions V.A, V.B, V.D, VIII.A, VIII.C and VIII.G of the final rule preamble of the CPP and Ch apter 3 of the GHG Mitigation Measures TSD for the CPP Final Rule supporting the final CPP

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

Commenters stated that finding an intermediate pric e point between the 65% and 75% utilization rate can only provide more options to the utilities . Commenters generally supported the increased utilization of existing NGCC units to support the B SER and related Greenhouse Gas measure.

Commenters stated that Emera Energy's NGCC assets w ill support EPA's targeted NGCC utilization rate of 65 to 75 percent. Commenters ca utioned that the ability of their assets to increase NGCC utilization rates is strongly affecte d by infrastructure, system, and economic considerations, such as limits on the ability of th e natural gas industry to deliver the increased quantities of natural gas and the price of natural gas that is available, especially during times of peak load. Commenters were optimistic that the prop osed Clean Power Plan along with other federal regulations requiring emission reductions f rom fossil fuel-fired power plants will increase investment in the United States natural gas infrast ructure allowing for increased utilization of our NGCC assets and enhanced geographic parity in natur al gas prices which will provide an economic benefit to rate payers in our region.

Commenters agreed that 65% is more feasible than a 70% capacity factor and a lower capacity factor would provide greater operational flexibilit y and infrastructure transition.

Comment 9: Commenters recommended that, where appropriate, the EPA should consider capacity factors for NGCC units greater than the 70 percent benchmark identified in the proposal using average annual capacity.

Response 9: The EPA disagrees with the establishment of a CO2 e mission reduction standard calculation using less than a 75 percent capacity f actor for NGCC units. Implementing authorities may encourage more stringent capacity f actors. . In response to additional analysis and many comments, we have modified the proposal an d RIA – the establishment of CO2 emission reduction standards is regionally based. T he 111(d) final rule requires that states develop plans that establish emission standards for affected EGUs. We are providing states with substantial flexibility as to how they structure th ose plans to achieve the 111(d) requirements. The flexibility includes, for example, the choice o f approaches, trading, time to develop plans, additional time before the start of the interim per formance period (postponed from 2020 until 2022), and the ability to shift emission rate achie vement between performance periods. The Building Blocks are not prescriptive, and states ma y consider local circumstances as they develop their plans, including system reliability, fuel diversity, other regulatory requirements and infrastructure. See sections V.D, VIII.A, VIII.C an d VIII.G of the final rule preamble of the CPP and Chapter 3 of the GHG Mitigation Measures TSD fo r the CPP Final Rule supporting the final

CPP.117

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

Commenters advocated that the EPA consider re-dispa tching affected NGCC units to a higher fleet-wide capacity factor than currently contempla ted by the proposal, but basing that higher capacity on the average annual capacity instead of nameplate capacity.

Commenters noted that per the EPA, roughly 6 percen t of NGCC units operated at a 75 percent capacity factor or higher in 2012, and this analysi s speaks only to the number of NGCC units comprising the 6 percent and not to the capacity of these units. Commenters stated that such a distinction is important particularly because this methodology is designed on a fleet-wide basis and not designed to assume achievement of a certain capacity factor on a unit-by-unit basis - a capacity factor in excess of 75 percent at a larger base load plant may facilitate far lesser capacity factors at smaller NGCC units relied on fo r the peaking power, while still averaging a fleet-wide capacity factor of 75 percent. Commenter s stated that overall, most of the RGGI states are able to re-dispatch to lower-emitting EGUs, ser ving as a region to depict the achievability and reasonableness of the Building Block Two method ology. Commenters indicated that in the RGGI region, there are over 70 affected NGCC plants representing 25,559 MW of nameplate capacity.

Comment 10: Commenters requested that states be required to exp lore even greater dispatch targets if they seek lowered compliance targets due to the infeasibility of other building blocks.

Response 10: The EPA disagrees. In response to additional analys is and many comments, we have modified the proposal and RIA – the establishm ent of CO2 emission reduction standards is regionally based. The 111(d) final rule requires th at states develop plans that establish emission standards for affected EGUs. We are providing state s with substantial flexibility as to how they structure those plans to achieve the 111(d) require ments. The flexibility includes, for example, the choice of approaches, trading, time to develop plans, additional time before the start of the interim performance period (postponed from 2020 unt il 2022), and the ability to shift emission rate achievement between performance periods. The B uilding Blocks are not prescriptive, and states may consider local circumstances as they dev elop their plans, including system reliability, fuel diversity, other regulatory requirements and i nfrastructure. States may choose to encourage more stringent capacity factor requirements at thei r discretion. See sections V.D, VIII.A, VIII.C and VIII.G of the final rule preamble of the CPP an d Chapter 3 of the GHG Mitigation Measures TSD for the CPP Final Rule supporting the final CPP

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

Specifically, commenters recommended that, if a sta te suggests that BSER should be weakened for a state due to some particular concern with a B uilding Block, that state should be required to investigate whether an alternative building block ( e.g., the greater dispatch of NGCC) can be used to maintain a robust BSER target for that stat e.118

Comment 11: Commenters recommended the EPA select a 75% NGCC ta rget utilization rate, as this will cut GHG the most, and fastest.

Response 11: The EPA agrees that an average annual capacity fac tor of 75 percent for NGCC units is appropriate for the calculation of CO2 emi ssion performance rates. In response to additional analysis and many comments, we have modi fied the proposal and RIA – the

establishment of CO2 emission reduction standards i s regionally based. The 111(d) final rule requires that states develop plans that establish e mission standards for affected EGUs. We are providing states with substantial flexibility as to how they structure those plans to achieve the 111(d) requirements. The flexibility includes, for example, the choice of approaches, trading, time to develop plans, additional time before the s tart of the interim performance period (postponed from 2020 until 2022), and the ability t o shift emission rate achievement between performance periods. The Building Blocks are not pr escriptive, and states may consider local circumstances as they develop their plans, includin g system reliability, fuel diversity, other regulatory requirements and infrastructure. See se ctions V.D, VIII.A, VIII.C and VIII.G of the final rule preamble of the CPP and Chapter 3 of the GHG Mitigation Measures TSD for the CPP Final Rule supporting the final CPP.

Comment 12: Commenters stated that Puerto Rico will not be abl e to benefit from Building

Block 2.

Response 12: The EPA has decided not to include this provision i n the final CPP because we are not finalizing the Rule for Puerto Rico at this tim e.

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

In comments on the Tribal & Territorial supplementa l proposal, commenters stated that, while the EPA believes that existing and planned LNG impo rt capacity in Puerto Rico supports 70 percent dispatch at the territory's existing NGCC f acility, this assumption is only true for the existing EGUs in Puerto Rico, and not for any futur e NGCC facility development. Commenters stated that, based on the historical performance of the EcoElectrica EGUs, PREPA found that these units' current annual generation capacity exc eeds EPA's projected re-dispatch goal of 70% for the proposed rule in Puerto Rico, because they have been operated above 80% since 2012.

Comment 13: Commenters stated that, for consistency, the same c alculation regarding the first 55 percent of the generation should be applied to u nits that were operating in 2012 as well as

units under construction.

Response 13: EPA thanks the commenters. The final calculations include provisions to improve consistency. Please see sections V.A, and V.D of t he preamble of the CPP and Chapter 3 of the GHG Mitigation TSD supporting the final CPP.119

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

Commenters stated the Goal Computation TSD states t hat only 15 percent (the difference between the 70 percent ceiling factor and the assum ed 55 percent generation) is available for redispatch from natural gas-fired, combined-cycle com bustion turbines that are under construction because the first 55 percent of the generation is r eserved for the generation potential needed to meet the other system needs that prompted construct ion of the units. Commenters stated this same statement is correct for existing natural gas- fired, combined-cycle combustion turbines that were operating in 2012, but the EPA calculation met hodology allows for re-dispatch from a baseline of 55 percent generation up to a maximum o f 100 percent generation, which is
inconsistent.

Commenters stated, as the proposed emission guideli nes recognize, there are many available options for reducing carbon dioxide emissions from existing power plants through modifications or upgrades at these plants. Commenters said, an an alysis focused on these "onsite" measures would by necessity be expansive in scope - includin g not only significant improvements to the efficiency or "heat rate" of the plant, but also ot her emission reduction measures such as cofiring or re-powering with lower-carbon fuels; util izing renewable energy sources to provide supplemental steam heating; using available waste h eat to remove moisture from coal or switching to higher-rank coal, and implementing com bined heat and power (CHP) systems at plants near industrial facilities or district heati ng systems, among other solutions. Commenters said, for example, engineering firms have estimated that with modest modifications, coal-fired power plants can derive as much as 50% of their hea t input from natural gas. Commenters said, co-firing at this level could yield emission reduct ions of 20%, and could be combined with heat rate and other improvements to achieve even deeper reductions at a specific plant.

Comment 14: Commenters stated that the EPA has not demonstrate d that a 65 percent

utilization rate for NGCCs is achievable.

Response 14: The EPA disagrees. In response to additional analys is and many comments, we have modified the proposal and RIA – the establishm ent of CO2 emission reduction standards is regionally based. The 111(d) final rule requires th at states develop plans that establish emission standards for affected EGUs. We are providing state s with substantial flexibility as to how they structure those plans to achieve the 111(d) require ments. The flexibility includes, for example, the choice of approaches, trading, time to develop plans, additional time before the start of the interim performance period (postponed from 2020 unt il 2022), and the ability to shift emission rate achievement between performance periods. Neith er the Building Blocks nor the analyses are prescriptive, and states may consider local circums tances as they develop their plans. See V.D, VIII.A, VIII.C and VIII.G of the final rule preambl e of the CPP and Chapter 3 of the GHG Mitigation Measures TSD for the CPP Final Rule supp orting the final CPP.

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

Commenters indicated that in support of the 65 perc ent utilization rate, EPA noted that 16 percent of the NGCC plants had utilization rates of 65 percent or higher during 2012 (79 Fed.120

Reg. at 34,866). According to the commenters, none of the problems with EPA's analysis in support of a 70 percent utilization rate, which are summarized in other comments, are ameliorated by a 65 percent goal. Commenters stated that the EPA has not provided a reasonable basis for its determination that a 65 percent utili zation rate is achievable. The commenters stated that while the EPA recognizes that there are constr aints on increasing NGCC utilization rates, the EPA does not appear to have adequately considered t hese constraints or the potential enormity of their cumulative impacts. Instead, according to the commenters, the EPA concludes that the challenges can be overcome and claims that it has p rovided sufficient time within which to address any necessary expansion of infrastructure ( 79 Fed. Reg. at 34,837 and 34,862-64).
Commenters also asserted that the EPA stated that t he level of potential coal-to-gas switching associated with assuming that existing NGCC units c ould run at a utilization rate up to 70 percent will not impact natural gas or electric sys tem reliability (Id. at 34,864), and that the EPA deems that this level of re-dispatch is potentially achievable by all states. Commenters concluded that the EPA's assumptions, and resulting conclusio ns, should be amended to account for a broader set of potential system constraints and the ir cumulative impacts.

Commenters stated that the EPA has not provided a r easonable basis for its determination that a 65 percent utilization rate is achievable. Commente rs stated that, while the EPA notes that 16 percent of the NGCC plants had utilization rates of 65 percent or higher during 2012 (79 FR 34866), the EPA has not provided a reasonable basis for its determination that a 65 percent
utilization rate is achievable.

Comment 15: For Utah, commenters provided analysis of two diffe rent capacity factor assumptions, 50% and 60%, and suggested the EPA's 7 0% capacity factor assumption is

unrealistic.

Response 15: The EPA disagrees that the analysis would accuratel y reflect the provisions of the 111(d) final rule. In response to additional analys is and many comments, we have modified the proposal and RIA – the establishment of CO2 emissio n reduction standards is regionally based. The commenters’ calculations reflect the provisions of the proposal, and EPA believes that Utah can meet the final rule requirements. The 111(d) fi nal rule requires that states develop plans that

establish emission standards for affected EGUs. We are providing states with substantial flexibility as to how they structure those plans to achieve the 111(d) requirements. The flexibility includes, for example, the choice of approaches, tr ading, time to develop plans, additional time before the start of the interim performance period (postponed from 2020 until 2022), and the ability to shift emission rate achievement between performance periods. The Building Blocks are not prescriptive, and states may consider local cir cumstances as they develop their plans, including system reliability, fuel diversity, other regulatory requirements and infrastructure. See sections V.D, VIII.A, VIII.C and VIII.G of the fina l rule preamble of the CPP and Chapter 3 of the GHG Mitigation Measures TSD for the CPP Final R ule supporting the final CPP.

The following are summaries of the specific public comments under this comment:121

Commenters stated the analysis was developed to eva luate how Utah's 2030 emissions rate goal would change if EPA used more realistic assumptions about the capacity factors at which Utah's existing NGCC units could operate. Commenters descr ibed the results of their analysis: the 2030 emissions rate goal increases under each of these s cenarios and the compliance gap faced by Utah decreases; with a 60% capacity factor the 2030 goal would be 1,369 lbs/MWH instead of 1,322 lbs/MWH and the compliance gap would shrink f rom 391 lbs/MWH to 344 lbs/MWH; and with a 50% capacity factor the EPA 2030 emissions r ate goal increases to 1,416 lbs per MWH and the compliance gap falls to 297 lbs per MWH.

Commenters referred to model runs by Energy Strateg ies to evaluate four different capacity factor scenarios to determine how changes in the op eration of affected existing fossil plants impact the "compliance gap." Commenters stated that , assuming affected fossil units operate at their minimum reported capacity factors, the emissi ons rate increases by 28 lbs per MWH to 1,741 lbs/MWH and the compliance gap increases to 4 19 lbs/MWH. Commenters stated that, in the Maximum Capacity Factor case both the emissions rate and compliance gap fall; the rate decreases 75 lbs/MWH to 1,638 lbs/MWH and this has the effect of decreasing the compliance gap from 391 lbs/MWH to 316 lbs/MWH. Commenters sta ted that in the scenario where it is assumed that coal generation is re-dispatched to a NGCC operating at a 70% capacity factor, makes the second largest contribution towards compl iance; Utah's emission rate would decrease to 1,671 lbs/MWH reducing the compliance gap by 42 lbs/MWH to 349 lbs/MWH.

Comment 16: Commenters questioned whether the EPA's assumption that Washington's NGCC capacity factor can go from 23% to 40% is reasonabl e.

Response 16: The EPA disagrees. In response to additional analys is and many comments, we have modified the proposal and RIA – the establishm ent of CO2 emission reduction standards is regionally based. The 111(d) final rule requires th at states develop plans that establish emission standards for affected EGUs. We are providing state s with substantial flexibility as to how they structure those plans to achieve the 111(d) require ments. The flexibility includes, for example, the choice of approaches, trading, time to develop plans, additional time before the start of the interim performance period (postponed from 2020 unt il 2022), and the ability to shift emission rate achievement between performance periods. The B uilding Blocks are not prescriptive, and states may consider local circumstances as they dev elop their plans, including system reliability, fuel diversity, the need for ancillary services and other regulatory requirements and infrastructure. See sections V.D, VIII.A, VIII.C an d VIII.G of the final rule preamble of the CPP and Chapter 3 of the GHG Mitigation Measures TSD fo r the CPP Final Rule supporting the final

CPP.

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

Commenters stated that NGCC facilities in Washingto n are used for purposes other than baseload generation, including: 1) meeting peak loads, 2) real-time integration of variable energy resources (VERS), and 3) occasionally, to maintain system stability. Commenters stated that resources used for these types of purposes generall y have a low utilization rate - both in terms of number of hours operated and the proportion of gene rating capacity used when operated.122

Comment 17: Several commenters stated that the 70% average capa city factor for NGCCs proposed for Building Block 2 was unsupported and u nachievable for a variety of reasons, including reliability, permit limits, infrastructur e, sustainability, and need for more analysis.

Response 17: The EPA disagrees. In response to additional analys is and many comments, we have modified the proposal and RIA – the establishm ent of CO2 emission reduction standards is regionally based. The 111(d) final rule requires th at states develop plans that establish emission standards for affected EGUs. We are providing state s with substantial flexibility as to how they structure those plans to achieve the 111(d) require ments. The flexibility includes, for example, the choice of approaches, trading, time to develop plans, additional time before the start of the interim performance period (postponed from 2020 unt il 2022), and the ability to shift emission rate achievement between performance periods. Neith er the Building Blocks nor the IPM analyses are prescriptive, and states may consider local circumstances as they develop their plans, including system reliability, fuel diversity , the need for ancillary services other regulatory requirements and infrastructure. See sections V.D, VIII.A, VIII.C and VIII.G of the final rule preamble of the CPP and Chapter 3 of the GHG Mitiga tion Measures TSD for the CPP Final Rule supporting the final CPP.

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

Some of the commenters' general statements are summ arized here, while subsequent comments addressed in later in section 3.2.2 provide additio nal detail.

Some commenters expressed general concerns regardin g costs, control, growth, reliability, dispatch authority, and integration of the electric al system.

• Commenters contended that EPA assumes that utilitie s will shift generation from coal to natural gas units, and that natural gas uni ts will run at 70 percent capacity. However, according to the commenters, if these natu ral gas units were more costeffective, they would already be running at higher levels.

• Commenters argued that requiring natural gas combin ed cycle units to operate at 70 percent capacity is a goal and not an emissions standard and it increases gas emissions without consideration of reliability, cos t or ownership.

• Commenters asserted that the EPA's assumption appea rs to be based on a model and carbon price assumptions (which they opine are above those they see in current carbon trading schemes), rather than any an alysis of the technical capabilities of the plants or gas delivery system.

• Commenters stated there are events outside of an EG U-operator's control which affect an NGCC facility's annual capacity factor.123 • Commenters stated that the homogenous energy mix re sulting from such explicit preference in fuel sources could leave the grid mor e vulnerable to supply constraints and price shocks due to unforeseen prod uction and transmission disruption.

• Commenters stated that the EPA is incorrect in assu ming that many states will be able to meet peak electricity demand without operat ing their coal-fired power plants; this assumption disregards the reality that electricity is not just about generating megawatt-hours but is also about generat ing capacity and meeting electricity demand every second of every day.

• Commenters asserted that a certain amount of NGCC a vailability is needed for load-following in order to support increasing renew able energy levels.

• Commenters stated the EPA failed to adequately cons ider the non-generation benefits currently provided by coal-fired EGUs and whether they can be satisfied by other power plants if coal-fired EGUs are retire d as result of the rule, including (i) certain coal-fired EGUs may be "black start" fa cilities that are capable of restarting without any electricity input; (ii) cert ain coal-fired EGUs may provide voltage support and other grid reliability benefits ; and (iii) certain coal-fired EGUs may be deemed supercritical "must run" facilit ies by FERC and/or RTOs, which will make retirement impossible.

• Commenters indicated that the assumption that all N GCCs should run at 70% capacity factor fails to recognize the benefit of N GCCs to the electrical system in that NGCCs can operate across resource categories ( base-load, intermediate and peaking) depending on the needs of the system - thi s flexibility is lost under EPA's proposed approach.

• Commenters stated the EPA's assumptions regarding t he ability of states to require significant increases in natural gas genera tion are unrealistic and unsupported.

• Commenters stated the EPA's proposal suggests that massive re-dispatch of the entire electric generation fleet can occur without regard to ownership of the facilities. Commenters stated that power generator location is a critical factor for electric reliability but is not addressed by EPA's IPM model.

• Commenters stated that the appropriate measure for determining whether existing units can be operated at higher utilization rates f or a sustained period of time is not whether some plants, which may have historicall y run at relatively high capacity factors, ran at high utilization rates in 2012, rather, it is whether the increase in the utilization rate from one year to a nother was sufficiently large to demonstrate that the existing natural gas and elect ric transmission systems have the necessary capacity and flexibility to accommoda te large and sustained increases in natural gas-based generation.124 • Commenters stated the EPA's re-dispatch assumptions fail to properly account for the fact that recently-added NGCC facilities were c onstructed to meet projected load growth, rather than to serve as additional ava ilable capacity. Commenters stated there is little surplus capacity to reduce c oal generation when growth projections are taken into account. Commenters sugg ested the EPA use a lower targeted capacity factor (i.e., <70%) in developing block two targets to account for anticipated load growth.

• Commenters stated that the 70% target disregards FE RC-established economic, market and practical considerations that make dispa rities between unit availability and operation net-beneficial. Commenters stated tha t units are limited by interaction with other sources on the electric grid , weather, efficiency, maintenance outages, etc.

• Commenters stated that, in the case of Nevada, a tr ansition to 70% utilization of natural gas resources and shutdown or retirement of large amounts of existing base-load capacity overlooks the impacts of strande d investments, market dispatch fundamentals, energy infrastructure constr aints, system reliability, and consumer cost impacts.

• Commenters asserted that a portion of natural gas plants must be set aside to be utilized to regulate real time changes in load beca use coal plants do not have the capability to ramp quickly enough to serve this fun ction and increased generation from wind/solar plants increase the need for regula tion.

• Commenters stated the EPA's 70 percent annual capac ity factor is overly optimistic and does not consider a variety of opera tional constraints, including utilization of resources for peak load and spinning reserves, planned and unplanned outages, market drivers, and transmission constraints.

Some commenters expressed general concerns regardin g various constraints that may prevent realizing a 70 percent capacity, such as design, pe rmit limits, infrastructure, new NAAQS, peak loads, and water supply.

• Commenters asserted that, although a 70 percent cap acity factor for combined cycle plants might be technically possible, permitt ing, transmission constraints, and higher maintenance costs in the energy demand a ll affect a plant's ability to run. Commenters suggested that the EPA recalculate the state targets to assume (in their opinion) a more realistic capacity.

• Commenters stated that NGCC plants are typically de signed to operate at much lower thresholds that the proposed 70 percent capac ity factor and, according to the commenters, when such NGCC plants are operated at higher levels, they will wear out. Commenters reported that they typically d o not have air permits that allow operation at anything close to the 70 percent capacity and that they are doubtful that the natural gas storage rights and pi peline capacity currently exists for operation at the level assumed by the proposed standard.125 • Commenters stated that some units are unable to inc rease generation to any level approaching 70 percent due to technical limitations , permit limits or gas and transmission infrastructure constraints, and other NGCC units will not be able to generate sufficient amounts above 70 percent to mak e up for these lowerutilization units.

• Commenters contended that there are numerous techni cal constraints on increased
utilization of NGCC that EPA has not accounted for such as gas supply, transmission constraints, and permit limitations on operating hours.

• Commenters stated that the EPA seems to ignore that new NGCC generation must meet existing and revised NAAQS standards when it p repared baselines and its building block structure that relies so heavily on NGCC.

• Commenters stated that, without appropriate verific ation of operating permit limitations, water supply, fuel supply and transmis sion availability, it is irresponsible of EPA to simply "plug'' in a number and believe that operation at this capacity is feasible for any of those units.

• Commenters asserted that existing natural gas infra structure is unavailable and significant time will be needed to expand natural g as infrastructure.

• Commenters stated some Iowa NGCC facilities have ex isting, available natural gas supply that would allow them to operate at a 70 % capacity factor; however, there is some question whether adequate firm gas su pplies will exist for other Iowa facilities. Commenters stated transmission sys tem availability may affect whether certain NGCC plants will be able to operate at a 70% capacity factor.

• Commenters stated that NGCC units may be limited in their operations by air permit conditions and noted that at least one NGCC in Mississippi has a permit condition that limits the hours of operation for ea ch unit at the plant on a rolling twelve-month basis, which would prevent it from ope rating at Building Block 2's target capacity factor.

• Commenters stated that units are subject to contrac tual commitments which dictate operational time and may need upgrades to r un at higher capacity factors. Commenters concluded the EPA has arbitrarily and ca priciously proposed this building block, without full analysis of the abilit y to implement 70% capacity factors on NGCC units and the impact by other Build ing Blocks.

• Commenters stated that the EPA has overlooked the p urpose and nature of NGCC units in many states: to provide critical peak powe r.

• Commenters stated that it is not rational to assume without data that the technical plant capability, gas, gas transportation, gas stor age, and electric transmission capacity are all available or easily developable to double the generators' historic average performance.126

Some commenters expressed general concerns that, wh ile some NGCCs could meet a 70 percent capacity goal, not all NGCCs could meet 70 percent capacity.

• Commenters stated that, as owners of significant co mbined cycle capacity, they have never been able to economically dispatch our u nits to achieve more than a 32 percent capacity factor, regardless of fuel prices. Commenters stated that these machines were never intended, nor designed, to be a long-term, base-load resources, as EPA suggests.

• Commenters stated that not all NGCC power plants we re designed to operate at a 70 percent capacity factor and not all NGCC plants have access to natural gas supplies at all times, further limiting their poten tial generation. For states with only a few NGCC power plants, commenters stated tha t achieving an average capacity factor of 70 percent may be overly optimis tic.

• According to commenters, units were financed, desig ned, and maintained for the specific purpose of operating in cycling duty rathe r than as base-load, and many
of these units would not be able to achieve the tar get utilization rate without significant upgrades and testing to ensure that the y are technically capable of operating near full load on a continuous annual bas is. The commenters added that these units' permitted emission limits may not allo w them to operate at a 70 percent capacity factor.

• Commenters stated that, while NGCC operation at or above 70% may be possible for some existing NGCC units, EPA's assumption that this is feasible at all existing NGCC units nationwide is too broad.

• Commenters stated that each NGCC plant has a specif ic capacity factor, due to the technology used, that varies across the fleet t hat may not be amenable to a 70% capacity factor. Commenters stated the EPA shou ld tailor the rule to specific units and not apply a blanket baseline that may not properly reflect the capabilities of an individual unit.

• Commenters stated that the EPA has failed to adequa tely demonstrate that a minimum 70% capacity factor requirement has been ac hieved by any existing NGCC unit - based on a survey by the commenters of over 300 air permits for coal and NGCC units, no examples have been identifi ed of a specific requirement that establishes a minimum capacity factor from the regulated source.

• Commenters stated NGCC units vary significantly due to differences in the age of units, the varied climates where the NGCC units are located, varying designs an design criteria, operation requirements in differen t markets with different demands, different owners and operators with differ ent practices, and in intended

use.

• Commenters stated the fact that a portion of a syst em may have been able to manage increased gas-based electric production in 2 012 does not justify its use as127 a national benchmark for the future because limitat ions such as the location of each plant in the electric grid and load must be co nsidered, as these locational
limitations matter as much as unit size or technica l capabilities.

Some commenters expressed general concerns that, wh ile some NGCCs could meet a 70 percent capacity goal, it is not clear the NGCCs could sust ain 70 percent capacity long term.

• Commenters asserted that, based on the experience o f Minnesota Utilities, in operating combined-cycle plants, they believe it wo uld be impossible to maintain a 70-percent capacity factor for such plants over t he long term, which could lead to serious compliance problems and substantial degr adation of the reliability of the nation's electric system.

• Commenters stated that it is unclear if EPA conside red the feasibility of NGCC units sustaining a high capacity factor to serve as base-load units. Commenters noted that stakeholder input has shown a wide range of opinion on whether a 70 percent capacity factor is sustainable; Kentucky ut ilities voiced a range from 55- 80 percent, with maintenance downtime being a major concern.

• Commenters stated that the EPA has not demonstrate d that all state NGCC fleets will be able to sustain that rate over the long-ter m

• Commenters stated that the NERC notes that NGCC uni ts have traditionally been used for load following purposes and, while some ar e capable of operating at a high capacity factor, they are generally less well suited to serve as base-load resources than coal generation.

• Commenters stated the dynamics of wholesale power m arkets make it difficult for existing NGCC power plants to achieve and sustain a n average 70 percent capacity factor. Commenters stated that increased o utput from existing NGCCs will signal a market need for new NGCCs to provide intermediate generating capacity and these cheaper, more efficient new unit s will arise to replace generation from existing units before existing unit s can achieve an aggregate 70 percent capacity factor.

• Commenters stated there is no technical or economic evidence that these plants can sustain generation at this high level.

• Commenters stated that some of the NGCC units attai n high capacity factors only through cyclical operating patterns, rather than ov er sustained periods that can occur during high demand seasons.

• Commenters stated the 70 percent target and expecte d NGCC capacity is overly optimistic in that while individual NGCC may achiev e 70 percent capacity factors for the short terms as outlined in EPA's TSD's, it is quite unlikely that NGCC's
can maintain that level in a sustainable fashion.128

Some commenters expressed general concerns that add itional analysis is needed.

• Commenters, in agreement with EPRI's comments, asse rted that EPA should conduct detailed transmission reliability evaluatio ns as part of the reliability, economic and financial impacts analyses of the rule

.

• Commenters indicated the EPA's 70% NGCC assumption requires significantly more analysis, particularly given that EPA's own mo deling (even without respecting the practical limitations noted above) d id not dispatch the NGCC fleet above a 60% capacity factor.

• Commenters stated that the EPA's 70 percent assumpt ion substantially overstates the amount of NGCC generation that would be availab le technically or economically to offset the coal generation that the proposal will retire or force off the grid. Commenters asserted that the EPA's 2012 b aseline inventory includes
NGCC units that have been either out of service for several years or retired and the EPA acknowledges a serious gap of at least 10 p ercent between the amount of natural gas needed to sustain this assumption and t he current natural gas pipeline delivery network.

• Commenters stated the EPA's analysis included NGCC units that have been out of service for several years or retired.

Some commenters expressed general concerns regardin g costs.

• Commenters stated the EPA's modeling assumptions do not take into account the significant costs associated with natural gas later al pipeline construction and electric transmission infrastructure build out requ ired to dispatch the NGCC fleet at a 70% capacity factor.

• Commenters stated the EPA's proposed 70 percent tar get utilization rate is unreasonable because the EPA's economic impact anal ysis failed to consider state-specific employment impacts of such extensive re-dispatch.

• Commenters stated that the EPA has not taken into a ccount the cost of stranded assets which will have to be borne by rural electri c cooperative members unless relief is provided.

• Commenters stated that the EPA's assumption of econ omic dispatch at an average 70 percent rate is derived by using an arbitrary $3 0/ton CO2 price (tax) which would fundamentally convert the current electric gr id from an economic dispatch to a carbon dispatch model.

• Commenters stated the increased cost to our communi ties under Building Block 2 is estimated to be about $370 million over the peri od 2020 through 2030.
Commenters stated this increase includes the cost o f new pipeline capacity needed to provide additional gas to the facility.129 • Commenters stated that, from an economic dispatch p erspective, EPA's assumed
70% NGCC utilization rate for BSER is unrealistic a nd based on faulty assumptions and expectations.

• Commenters stated the EPA's estimate of the cost of this rule does not include costs related to pipeline construction, gas supply, transmission services, storage and prices for firm pipeline service. Commenters st ated that several billion dollars will need to be spent on new gas pipelines and stor age fields in order to adequately increase the level of firm resources tha t would be needed."

• Commenters stated that additional, costly transmiss ion infrastructure would be required for re-dispatch to be viable. Commenters e xplained that, in Alaska, the
coal-fired EGUs are located in Interior Alaska and the gas-fired EGUs are located
in Southcentral Alaska. Commenters stated these two types of EGUs are more than 300 miles apart and the existing transmission infrastructure typically operates at maximum capacity.

Comment 18: Commenters expressed concern regarding the assumed NGCC capacity factor

relative to new and older units.

Response 18: The EPA disagrees, and believes the data support th e capacity factors analyzed for the establishment of CO2 emission performance rates . The 111(d) final rule requires that states develop plans that establish emission standards for affected EGUs. We are providing states with substantial flexibility as to how they structure th ose plans to achieve the 111(d) requirements. The flexibility includes, for example, the choice o f approaches, trading, time to develop plans, additional time before the start of the interim per formance period (postponed from 2020 until 2022), and the ability to shift emission rate achie vement between performance periods. The Building Blocks are not prescriptive, and states ma y consider local circumstances as they develop their plans, including system reliability, fuel diversity, other regulatory requirements and infrastructure. The 111(d) final rule does not requ ire every individual NGCC unit to meet a CO2 emission performance rate, but rather the 75 percen t capacity factor was used in the calculations to establish a rate. See sections V.D, VIII.A, VIII .C and VIII.G of the final rule preamble of the CPP and Chapter 3 of the GHG Mitigation Measures TS D for the CPP Final Rule supporting the

final CPP.

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

Commenters stated the EPA's position conflicts with EPA's assumption that new, underconstruction, NGCC units will only perform at a 55% capacity factor (79 FR 34896). Commenters stated that this 55% capacity factor ass umption may be reasonable for these new, market-driven units, but 55% would be a completely unreasonable assumption for existing, older NGCC plants. Commenters stated the EPA's 70% capaci ty-factor assumption also conflicts with its own findings in the New-Source 111(b) Rule Prop osal, which found that small NGCC units130

that are generally designed for operation during pe ak demand will usually supply less than onethird of their potential electric output to the gri d (79 FR 1445).

Commenters stated that, while the EPA describes NGC C units as technically capable of operating in base-load roles where the average annu al availability exceeds 85% and can exceed 90% for some units (79 FR 34862), one of the two st udies the EPA cited for this basis was based on a newer specific type of NGCC unit and cited the increased availability could only be achieved after various improvements and equipment u pgrades occurred.

Commenters stated the EPA does not take into accoun t whether states with older NGCC fleets can achieve a 70% capacity factor. Commenters state d that increased usage of NGCCs could result in several negative consequences such as a d ecrease in operational life, increased O&M expenditures, and an increase in forced outages.

Comment 19: Commenters contended that the recent increase in na tural gas generation provides little justification for a state's capability to ma intain a 70 percent NGCC fleet-wide capacity.

Response 19: The EPA disagrees. The 111(d) final rule requires t hat states develop plans that

establish emission standards for affected EGUs. We are providing states with substantial flexibility as to how they structure those plans to achieve the 111(d) requirements. The flexibility includes, for example, the choice of approaches, tr ading, time to develop plans, additional time before the start of the interim performance period (postponed from 2020 until 2022), and the ability to shift emission rate achievement between performance periods. The Building Blocks are not prescriptive, and states may consider local cir cumstances as they develop their plans, including system reliability, fuel diversity, other regulatory requirements and infrastructure. The 111(d) final rule does not require every individual NGCC to meet a CO2 emission performance rate, but rather the 75 percent capacity factor was used in the calculations to establish a rate. See sections V.D, VIII.A, VIII.C and VIII.G of the fina l rule preamble of the CPP and Chapter 3 of the GHG Mitigation Measures TSD for the CPP Final R ule supporting the final CPP.

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

Commenters asserted that nationally trending increa ses in NGCC dispatch and decreases in coal generation dispatch (and, as included in another co mment, small percentages of existing NGCC units nationwide that operated at annual or seasona l capacity factors of 70 percent or higher in 2012) do not provide an independent rationale for r e-dispatch up to 70 percent of NGCC units' capacity. Rather, they appear to be ex post rationa lizations of a re-dispatch amount that EPA has otherwise failed to explain. The IPM model runs tha t EPA conducted to analyze re-dispatch costs are of no import to the Agency's initial determinat ion regarding the appropriate capacity factor. According to the commenters, the EPA must justify t he NGCC capacity factor it ultimately utilizes for each state to which that capacity fact or applies. The commenters asserted that the EPA cannot do so because state-specific considerati ons render the 70 percent capacity factor
unattainable.131

Commenters recommended that the EPA review the disp atched generation in 2012, which they believed demonstrated that even with historically l ow natural gas prices, natural gas dispatch did not approach 70% utilization; indeed, capacity fact ors for NGCC units were 60.4% in the PJM reliability region.

Commenters stated that the EPA points out that nati onwide NGCC generation increased by approximately 81 percent between 2005 and 2012 (com pared to the estimated 47 percent increase by 2020 that would be required in order to implement Building Block 2), while failing to acknowledge that this figure includes new NGCC u nits that were constructed from 2005 to 2012 and does not simply reflect increased utilizat ion of existing units, which is the centerpiece of the Building Block 2 approach (GHG Abatement Mea sures TSD at 3-11).

Commenters contended that the recent increase in na tural gas generation provides little justification for a state's capability to maintain a 70 percent NGCC fleet-wide capacity factor. Commenters stated the EPA provided no supporting da ta to justify that an entire state could, beginning in 2020, indefinitely achieve an NGCC fle et-wide average capacity factor of 70 percent. Commenters stated that in fact, during 201 2, with historically low natural gas prices and high natural gas consumption from the electricity s ector, no state obtained a 70 percent NGCC fleet-wide annual average capacity factor. Accordin g to the commenters, the EPA has misinterpreted the role of NGCCs in an integrated e lectricity system and eliminated or severely reduced their ability to reliably serve a state's e lectricity demand.

According to commenters, the EPA stated that NGCC g eneration increased by 22 percent between 2011 and 2012, supposedly demonstrating tha t existing natural gas infrastructure can accommodate rapid increases in existing NGCC utiliz ation (GHG Abatement Measures TSD at 3-9 to 3-10). However, commenters asserted that the EPA fails to note that even after this expansion - which was largely a function of histori cally low natural gas prices in 2012 due to the widespread development of hydraulic fracturing tech nology - over half of the existing NGCC units that EPA examined still operated at a capacit y factor below 50 percent, presumably due to the kinds of constraints that EPA attempts to wish away.

Commenters referred to EIA data and stated that, to achieve the proposed 70 percent capacity factor for the national fleet of existing NGCC unit s would require a 75.9 percent increase over the 2009 capacity factor (the lowest reported) and a 37 percent increase over the 2012 capacity factor (the highest reported). Commenters stated th at there is no rational way to conclude that Building Block 2 is adequately demonstrated. Commen ters referred to the EPA Goal Computation TSD and stated that not a single state had a 70 percent capacity factor for NGCC generation. Commenters stated that the highest stat e NGCC capacity factor was 63 percent for Connecticut and only 10 states had capacity factors of 50 percent or greater (Florida, Georgia and New York-51 percent, Indiana and New Hampshire- 53 percent, Ohio-55 percent, Alabama and Pennsylvania-59 percent, Virginia-60 percent an d Conneticut-63 percent). Commenters stated that the NGCC historical capacity factors de monstrate that the EPA's proposed 70 percent capacity factor is not achievable, is not demonstra ted, and is arbitrary and capricious.

Even with historically low natural gas prices for N GCC EGUs, commenters reported that Michigan only achieved an approximate average CF of 42 percent for its NGCC units in 2012. Indiana only achieved 53 percent. According to the commenters, even if one were to assume a132

continuation of low cost natural gas fuel for NGCCs , these units are typically not called upon to run as base-load plants in meeting electric supply and demand; doing so would require more frequent and costly maintenance causing extended ou tages, both forced and unforced; the price of natural gas will not remain at low-levels, due t o the volatility of the natural gas market.

Commenters stated the EPA incorrectly claims that i ts proposal to re-dispatch coal generation to NGCC generation builds on a trend already underway in the power sector of relying more on natural gas and less on coal (79 FR 34863). The com menters stated the EPA fails to recognize that market-caused shifts between coal and gas gene ration are temporary. Commenters noted that, when natural gas delivered prices to electric utilities fell to their recent lows in 2012 (April 2012 @ $3.12 MM/Btu), coal and natural gas generate d roughly the same amount of electricity (Coal-96.3 TWh vs. Gas 94.8TWh) nationwide; however , less than one year later in February 2013, with natural gas prices at $4.30/MMBtu, coal generation increased by almost 30 percent (123.8TWh), while natural gas generation decreased by almost 16% (79.9TWh). Commenters stated that natural gas prices are a temporary cycl ical factor, while coal-fired plants can run at higher or lower capacity factors depending upon ove rall demand and the relative price of coal and natural gas.

Commenters stated that the EPA policies-such as MAT S and the proposed CPP rule force the retirement of coal base load power plants and are t herefore a permanent structural barrier to assuring the electric grid remains diverse enough t o minimize both reliability crises and higher and more volatile prices that reverberate throughou t the economy. Commenters further stated it is not correct for EPA to claim that its proposal m erely builds on a preexisting trend; rather, EPA itself is the cause of a massive shift of coal gene ration to gas and of the consequences that will ensue. The commenters cited a 2008 DOE report which stated that "policies that encourage the use of natural gas to substitute for coal in power generation could very well lead to spectacular price increases for households and industry." The c ommenters also referred to a study performed by the Duke University Nicholas School of Environme nt and provided the following additional
information.

Commenters asserted that the EPA's view that the un precedented size of coal EGU retirements are a product of natural gas prices and not the Age ncy's policies is also directly refuted by the Duke study which stated that "most of the planned [ coal plant] shutdowns are more a response to the stricter regulations than to low natural gas pr ices." According to the commenters, without the MATS rule, only 9 percent of the current coal capac ity was economically threatened when natural gas prices dropped to their lowest in 2012. The commenters contended that coal plants would again become the dominant least-cost generati on option should the ratio of average natural gas to coal prices (NG2CP) rise to 1.8. In fact, the commenters reported that the NG2CP is predicted to rise back up toward 2 by 2020. In t he absence of EPA rules, the commenters
believed this would result in > 85% of the current coal fleet capacity once again having a lower COE than the cheapest natural gas plant. In Februar y 2012, the month before the study was published, the commenters reported that the price o f coal for electricity generation was $2.41/MMBtu and the price for natural gas was $3.72 /MMBtu, for a NG2CP ratio of 1.4. According to the commenters, at a ratio of 1.8, the price of natural gas would be at $4.28/MMBtu. The commenters further stated that the 1.8 NG2CP ratio has been exceeded for 19 of the 21 months between November 2012 and July 2014. In February 2014, according to the commenters, the cost of natural gas delivered to el ectric utilities reached $7.01/MMBtu as133

compared to coal prices of $2.33/MMBtu, for a ratio of 3.03. In July 2014, the commenters reported that the ratio fell back to 2.01. Accordin g to the commenters, the Duke study also found that, with EPA regulations, natural gas prices to u tilities can increase to more than four times the coal price (NG2CP of 4.3) and remain competitive wi th coal plants. In other words, the commenters asserted, the EPA's finalized MATS regul ations have made natural gas plant dispatch much less sensitive to the rise in natural gas prices.

Commenters asserted that since many NGCC units have never operated at a 70% capacity factor, there is no historical evidence they can operate as base load. Commenters suggested that many older units may be incapable of doing so.

Comment 20: Some commenters disagreed with the EPA's assumption that each state's entire fleet of existing NGCC units can match the operatio nal level of the top 10 percent of units. These commenters made some or all of the following points :

Response 20: The EPA disagrees with the interpretation of the ru le. The 111(d) final rule requires that states develop plans that establish e mission standards for affected EGUs. We are providing states with substantial flexibility as to how they structure those plans to achieve the 111(d) requirements. The flexibility includes, for example, the choice of approaches, trading, time to develop plans, additional time before the s tart of the interim performance period (postponed from 2020 until 2022), and the ability t o shift emission rate achievement between performance periods. The Building Blocks are not pr escriptive, and states may consider local circumstances as they develop their plans, includin g system reliability, fuel diversity, the need for ancillary services other regulatory requirement s and infrastructure. The 111(d) final rule does not require every individual NGCC unit to meet a CO 2 emission performance rate, but rather the 75 percent capacity factor was used in the calculat ions to establish a rate. See sections V.D, VIII.A, VIII.C and VIII.G of the final rule preambl e of the CPP and Chapter 3 of the GHG Mitigation Measures TSD for the CPP Final Rule supp orting the final CPP.

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

Individual units have different capabilities.

• The EPA did not undertake any assessment of the dif ferences between high- and low-capacity factor NGCC units that may have led a small subset of those units to operate above a 70 percent capacity factor in 2012. The Agency acknowledged that units operating above 70 percent on an annual basis were "largely dispatched to provide base load power," and that units operati ng above 70 percent on a seasonal basis typically "were idled or operated at lower capacity factors" during periods of lower demand. But EPA did not examine wh ether the NGCC units providing base load power have different characteri stics from the other existing NGCC units that are expected to provide generation for re-dispatch, or whether units that were idled during periods of relatively low demand did so because of economic, technical, or regulatory constraints on t heir operations.134 • The EPA assumed that all NGCC units are identical, which is plainly
unreasonable.

• The EPA fails to recognize that NGCCs are built to fulfill specific needs within the electric system. In some cases, NGCCs operate a s base load resources; in others, they operate as non-base load resources - s uch as load following, midmerit or even peaking resources, playing a critical role in providing essential ancillary services to balancing areas.

• Different NGCC plants may operate different equipme nt and service different demand profiles and when EPA assumes all existing p lants can achieve its best system standard, the agency conflates technical cap ability with operational feasibility.

• The 70% capacity factor is an arbitrary number sele cted based on the historic operation of a small percentage of NGCC units and j ustified with qualitative criteria that offer nothing to credibly conclude th at the 70% determination is technically, economically, or legally feasible.

• According to the commenters, EPA's process for sele cting the 70% capacity factor gives no regard to important considerations such as the availability of adequate transmission capacity to allow increased N GCC utilization to offset the operations of other fossil fuel-fired facilities lo cated in the same state; the availability of adequate and reliable sources of ga s supply; existing unit conditions; outage scheduling; or the lack of regul atory authority or mechanisms necessary to establish and enforce such utilization requirements.

• Commenters stated that the EPA's own modeling of th e proposed rule confirms
that there are technical and/or economic constraint s to running all NGCC units at a 70% capacity factor as the nationwide average cap acity factors for NGCC units were 50 and 56% for the two Option 1 scenarios mode led by EPA.

• Despite the EPA's assumption that all NGCC units c urrently in operation were designed to achieve utilization rates between 85 an d 95 percent (79 Fed. Reg. at 34,863), NGCCs that have been designed to operate a s intermediate or peaking units may not be technically able to increase their utilization to 70 percent for sustained periods of time.

• In order to demonstrate that a standard is achievab le, the EPA must "establish that the test data relied on by the agency are represent ative of potential industry-wide performance, given the range of variables that affe ct the achievability of the
standard." Sierra Club v. Costle , 657 F.2d 298, 377 (D.C. Cir. 1981). This determination cannot be based on "mere speculation or conjecture." Lignite Energy Council v. EPA , 198 F.3d 930, 934 (D.C. Cir. 1999) (per curiam).

• Many of these high-utilization units are likely not representative of the source category, given that the EPA excluded a number of t hem from its calculations of135 each state's existing NGCC capacity in the Goal Com putation TSD. Compare 2012 NGCC Spreadsheet (including, inter alia, Marti nez Refining units in assessment of achievable NGCC capacity factor); wit h Goal Computation TSD, App. 7 (excluding, inter alia, Martinez Refining un its from California's existing NGCC capacity).

• Commenters stated that, because the EPA did not con duct any analysis to understand why a small number of units in 2012 oper ated at a high capacity factor while the large majority did not, EPA's conclusion that all NGCC units can operate at a 70 percent capacity factor is arbitrar y.

• Commenters offered several reasons why certain unit s may not be able to operate in a baseload mode all year: all NGCC plants have o perating permits that limit emissions, and these permits may limit the number o f hours these facilities may operate, particularly during the summer ozone seaso n; a utility may build an NGCC unit specifically to operate in an intermediat e mode because it already has other baseload resources; and utilities build diffe rent types of facilities in different locations to serve discreet purposes and these faci lities cannot be operated in a different fashion to serve a different purpose with out undermining their ability to serve their original purpose. Commenters stated tha t, for instance, Basin Electric Power Cooperative designed the Deer Creek NGCC faci lity to operate a little less than half of the time, not 70%, in order to integra te Basin's substantial and growing portfolio of wind energy, which is abundant in this part of the nation. Commenters stated Deer Creek needs to have the capa bility to dispatch up when the wind suddenly does not blow, and need to be abl e to dispatch down when the wind picks up; operating at a high capacity factor, 70%, would not allow the kind of ramping that is essential to Deer Creek's purpos e.

The 90% operating at lower rates should be addresse d.

• The EPA's selection of 70% as a reasonable capacity factor for NGCC units as BSER is arbitrary and capricious because the EPA on ly considered the result of 10% of the NGCC fleet operating at a 70% capacity f actor and not the factors that caused these units to operate at higher rates than the remaining 90% of the NGCC
units.

• Given the small fraction of units that have achieve d consistent, or even intermittent, operation at 70% of capacity, the NGC C capacity target set in Building Block 2 is completely arbitrary and the Pr oposed Rule establishes a 70% NGCC capacity target that is grossly inflated and p ractically infeasible.

• Commenters stated the EPA's rulemaking data on the operation of NGCC plants conflicts with its presumption that all units can r each a 70% capacity factor.
Commenters referenced the GHG Abatement Measures TS D and stated (1) the EPA identified only slightly more than 10% of NGCC units operating in 2012 had a capacity factor of 70%; (2) even during peak time s, the vast majority of NGCC units failed to meet the 70% capacity factor (only 19% of NGCCs in the winter of136 2011/2012 and 20% in the summer of 2012 reached thi s capacity factor); and (3) only 6% of NGCC units operated at a 75% capacity fa ctor, or higher, in 2012 and only 16% of units operated at 65% of higher.

• Commenters concluded that one out of ten units achi eving a 70% capacity factor is not convincing evidence that all units can reach this capacity factor.

2012 is not representative.

• The EPA has incorrectly assumed the operation stati stics of 50 NGCC plants during a year (2012) with historically low natural gas prices are achievable indefinitely for the remaining 400 NGCC plants. The EPA ignored the fact that 89 percent of the NGCC plants analyzed did not achieve a 70 percent capacity factor during optimal conditions, that is, historically lo w natural gas prices.

• The EPA has failed to establish that the 10 percen t of existing NGCC units operating at 70 percent capacity factor or higher a re representative of the remainder of NGCC units in the source category. Th e fact that only 10 percent of the NGCC units that operated in 2012, a year of exc eptionally low natural gas prices, did so at a 70 percent capacity factor is m ore indicative of the inability of all NGCC units to operate at that level than the op posite.

• It is unreasonable to assume (79 FR 34863) that bec ause natural gas consumption increased by 20% in 2012, a record low market price period, the system is now capable of maintaining 100% of the NGCC units opera ting at 70%, when in the same year (as the 20% increase in natural gas usage occurred) only 10% of the NGCCs operated at 70%.

• The EPA does not provide any information showing th at any of the units that operated at a 70 percent capacity factor in 2012 di d so in previous years, yet EPA assumes that these and other units can operate at t hat level indefinitely into the future. Presumably, if a significant number of NGCC units had operated at 70 percent capacity factors over longer periods of tim e, EPA would have cited that
fact.

• Commenters stated the EPA inaccurately assumes that because 10% of the nation's NGCC units operated at greater than 70% ca pacity in 2012 that the rest of the NGCC fleet can be dispatched at this same level every year. Commenters stated that, given that natural gas prices were at historical lows and the summer load demands at all-time highs that year, it is mor e valid to say that 2012 does not represent a NGCC capacity factor that can be achiev ed on a long-term basis. Commenters stated the EPA can only conclude that NG CCs operated at a 45.8% capacity factor during a single year that experienc ed an unusually high level of NGCC operation due to unique circumstances.

• Commenters disagreed with the use of 2012 as the ba seline year in the EPA's goal calculation because 2012 was the year of lowest coa l generation utilization rate in137 Arizona in the past 10 years and is not representat ive of an electric utility system under full demand load. Commenters stated that, no t only is 10 percent of the industry an insufficient sample size, the use of on ly one year of data is also inadequate. Another commenters stated that, because the EPA relies on the performance of a relatively small portion of the NG CC fleet over a 1-year period, therefore, EPA's own data indicate that what is pro posed has not occurred, even within a small portion of the fleet, over the long term.

The EPA has not demonstrated year-round capability to operate at 70%.

• The fact that some NGCC units operated at a 70 perc ent capacity factor in certain seasons is not representative of how these units co uld operate year-round. Units that are able to reduce load or shutdown during non -peak seasons are better able to prepare for the peak seasons when higher operati ng levels are needed than units that do not have that opportunity. Accordingly, EPA cannot simply assume that seasonal performance is a fair benchmark of continu ous, year-round performance.

• Commenters stated that, to assume that, because som e units of the NGCC fleet operated at 70% of capacity in limited operation, t herefore the same units are capable of running at 70% for much longer periods o f time is foolhardy. Commenters stated that, based on common usa ge in the electric industry, this clearly indicates that those units operating a t 70% or above are doing so during peak periods. Commenters stated that when a unit is designed for peaking or load-following at a capacity factor below 70%, t he transmission interconnection and transmission agreements reflect that capacity and, likewise, if a unit was constructed to run at 70% of capacity fo r winter or summer peak periods, that also would have been reflected in tra nsmission wheeling agreements or interconnection agreements.

70 % is unreasonable, given the market forces.

• The market forces that actually determined NGCC di spatch in 2012 do not appear to agree with EPA's assessment of economic r easonableness for high NGCC dispatch, since even at the historically low n atural gas price levels in 2012, only 10% of the NGCC units ran at the 70% capacity factor that EPA claims is economically reasonable.

Need to evaluate all units, system-wide.

• The EPA states that it is reasonable for the existi ng NGCC fleet to achieve average utilization rates of 70 percent because a s ignificant number of NGCC units achieved capacity factors between 50 and 80 p ercent during the winter and summer seasons of 2012 (79 Fed. Reg. at 34,857). Th is conclusion is not based on sound data analysis and is predicated on a misunder standing of the electric system. Neither the existing natural gas nor the ex isting electric systems are as flexible as the EPA implied. In 2012, not a single state ran its NGCC fleet at an average capacity factor of more than 61 percent. Th is demonstrates the138 importance of analyzing the performance of individu al plants in the context of the whole system. It also reinforces the idea that, eve n though one plant may achieve a certain utilization rate at one point in time, ot her plants within the same system may not be able to do so, and system-wide constrain ts may become particularly acute when, on average, all units are expected to a chieve that utilization rate. The appropriate measure for determining whether existin g units can operate at higher utilization rates for a sustained period of time is not whether some plants ran at high utilization rates in 2012; rather, it is wheth er the increase in the utilization rate from one year to another was sufficiently larg e to demonstrate that the existing natural gas and electric transmission syst ems have the necessary capacity and flexibility to accommodate large and sustained increases in natural gas-based generation.

• Commenters stated that an analysis based on the sam e data used by the EPA shows that only a fraction of those plants cited by EPA as operating at high capacity factors in fact had experienced a signific ant increase in their utilization rates (citing Appendix D to the comments). These pa rticular units, therefore, already operated in a system that was designed to a ccommodate their high capacity factors, so EPA's analysis does not provid e sufficient justification to find that the entire natural gas pipeline and electric t ransmission systems can accommodate large increases in natural gas usage.

• Commenters stated the EPA's assumption that the NGC C fleet could rise to 70% capacity is highly unlikely, given that only 20% of NGCC units were able to achieve 70% capacity for one season and only 10% ha ve ever run at 70% capacity for a year. Commenters stated that, to extrapolate from this that the entire fleet can achieve 70% is unrealistic, and to base one qua rter of major energy policy on such an assumption is reckless and gives no conside ration to the critical issue of grid reliability.

Comment 21: Commenters stated that the CPP goals may not be ach ievable due to the lack of

in-state NGCC or lack of demand for in-state NGCC a t 70% of nameplate capacity year-round and provided state-specific information.

Response 21: The EPA disagrees with the interpretation of the 11 1(d) final rule. In response to additional analysis and many comments, we have modi fied the proposal and RIA – the

establishment of CO2 emission reduction standards i s regionally based. The 111(d) final rule requires that states develop plans that establish e mission standards for affected EGUs. We are providing states with substantial flexibility as to how they structure those plans to achieve the 111(d) requirements. The flexibility includes, for example, the choice of approaches, trading, time to develop plans, additional time before the s tart of the interim performance period (postponed from 2020 until 2022), and the ability t o shift emission rate achievement between performance periods. The Building Blocks are not pr escriptive, and states may consider local circumstances as they develop their plans, includin g system reliability, fuel diversity, the need139

for ancillary services other regulatory requirement s and infrastructure. The 111(d) final rule does not require every individual NGCC to meet a CO2 emi ssion performance rate, but rather the 75 percent capacity factor was used in the calculation s to establish a rate. See sections V.D, VIII.A, VIII.C and VIII.G of the final rule preamble of the CPP and Chapter 3 of the GHG Mitigation Measures TSD for the CPP Final Rule supporting the final CPP.

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

Commenters stated there are no opportunities in Wes t Virginia to increase the dispatch of NGCC, given absence of NGCC units. Commenters state d that, because there are no NGCC
units in existence or under construction and there are no oil- or gas-fired steam EGUs in existence or under construction in West Virginia, t herefore, no Building Block 2 CO2 reductions are possible in West Virginia. Commenters stated th at all affected EGUs within the state are existing coal-fired steam EGUs, or simple cycle nat ural gas-fired peaker units that are not defined as affected sources under the proposed rule

.

Commenters stated that, since North Dakota does not have any gas-fired plants, they cannot redispatch. Commenters added that in South Dakota the re is one coal and one gas plant which are separate entities and not members of the same regio nal transmission organizations and that redispatching one for the other is simply impractical . Commenters stated this impacts North Dakota because both plants are billed on integrated system costs, which means that North Dakota customers get power from the coal plant in South Da kota and are charged for it in their rates.

Commenters stated that, as a small public power who lesale electric generation and transmission provider, Platte River's resource portfolio does no t include NGCC and, consequently, Platte River and many similarly situated public power prov iders will be reliant on the availability and willingness of other generation providers with exis ting NGCC to accommodate re-dispatch needs. Commenters stated this re-dispatch reliance creates a compliance vulnerability and rate uncertainty which is not tenable and will likely re sult in costly NGCC overbuild.

Commenters stated that, in New York, there may not be sufficient demand or load to be served at certain times of the year for NGCC units in New Yor k to operate at 70% of nameplate capacity year-round, which is anticipated by the application of this building block to New York. Commenters provided Table 2, Capacity Analysis, sho wing New York State's monthly NGCC load compared to 70% of its monthly nameplate capac ity, and noted there were eight months in which total fossil load is less than 70% of NGCC ge neration capacity. Commenters stated that in those eight months, fully re-dispatching all oil/ga s and coal generation to NGCC would leave the NGCC units operating at less than 70% of load; in M arch 2012, for example, 74 % of fossil generation was from NGCC, yet it only represented u p to 38% of EPA's nameplate capacity.
Commenters also noted that Table 2 demonstrates tha t total fossil load in each of the four months from June to September exceeds 70% of EPA's NGCC ca pacity; in those four months alone, redispatching coal and oil/gas steam generation to NG CC will leave a total of 6.55 million MWh of non-NGCC fossil generation, even in the absence of reliability rules and constraints. Commenters concluded that, even ignoring the reliab ility rules and transmission limitations, the only way to re-dispatch existing coal and oil/gas g eneration fully to NGCC would be to meet electricity load currently met by oil/gas and coal in the summer months with underutilized natural gas capacity the other eight months of the year. Commenters stated, however, that the140

EPA's application of this building block assumes th at 99.3% of the state's oil/gas and coal generation can be re- dispatched to natural gas and that 99.8% of the State's fossil electricity load can be met by natural gas.

Commenters stated that, since Missouri River Energy Services has no existing NGCC resources, the application of building Block 2 is impossible. Commenters stated that Block 2 of the proposed rule is based on the flawed assumption tha t utilities and states may meet the targets by re-dispatching existing NGCC to off-set coal. Comme nters stated the proposed rule makes its calculations and resulting emission reduction goals based on the assumption that utilities owning and/or operating an affected EGU would have suffici ent NGCC capacity to offset its emissions
from coal-fired facilities in the same state. Comme nters stated that the owners of the affected
EGUs are not the owners of available NGCC units. C ommenters stated that, while MRES is a co-owner of LRS, located near Wheatland, Wyoming, M RES does not own any NGCC in Wyoming to offset its emissions or otherwise decrea se the run-time of LRS. Commenters stated that, not only does MRES not own any NGCC in Wyomin g, it does not own or operate any NGCC, which puts MRES at an immediate disadvantage as it cannot look to Block 2 for decreasing emissions, particularly in 2020 when 80% of reductions are to be achieved, or in meeting the proposed milestones of the glide path. Commenters stated that MRES (a relatively small municipal entity) provides a classic example of a utility that owns only one coal resource and no NGCC; further, in the state of Wyoming, ther e are 10 coal-fired power plants that are affected units and only one 95 MW NGCC plant.

Commenters stated Building Block 2 does not apply a s proposed, since there are currently no natural gas combined cycle units subject to the pro posed rule operating in Kansas.

Comment 22: Commenters objected to the use of a single capacity factor goal for several reasons, such as many NGCC units were not designed for cycling duty, significant upgrades would be needed, and unit-specific limitations; som e commenters suggested use of a 3-year

average.

Response 22: The EPA disagrees with the interpretation of the 11 1(d) final rule. The 111(d) final rule requires that states develop plans that establish emission standards for affected EGUs. We are providing states with substantial flexibilit y as to how they structure those plans to achieve the 111(d) requirements. The flexibility in cludes, for example, the choice of approaches, trading, time to develop plans, additional time bef ore the start of the interim performance period (postponed from 2020 until 2022), and the ability t o shift emission rate achievement between performance periods. The Building Blocks are not pr escriptive, and states may consider local circumstances as they develop their plans, includin g system reliability, fuel diversity, other regulatory requirements and infrastructure. The 111 (d) final rule does not require every individual NGCC to meet a CO2 emission performance rate, but rather the 75 percent capacity

factor was used in the calculations to establish a rate. See sections V.D, VIII.A, VIII.C and VIII.G of the final rule preamble of the CPP and Ch apter 3 of the GHG Mitigation Measures TSD for the CPP Final Rule supporting the final CPP

.141

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

Individual units have different capabilities.

Commenters stated that, although certain plants may have the ability to achieve a 70% capacity factor, others do not. Commenters stated NGCC units are designed and sited to meet certain needs of a utility; some are designed to serve inte rmediate load and others are designed as peaking units. Commenters stated these varying purp oses reflect how a utility integrates its various generating resources to provide a reliable and stable source of electricity.

Commenters requested that the BSER guidance regardi ng NGCC capacity factors not exceed historic highs experienced on a state specific basi s. Commenters stated that, in Michigan's case, this is no greater than a 42% capacity factor; comm enters estimated that this revision would add 137 lbs CO2 per MWh to the proposed Michigan standa rd. Commenters stated that, if in 2012, an ideal year for NGCC dispatch, Michigan failed to reach higher than 42% then it is not reasonable to expect that Michigan's system would s upport the proposed average dispatch rate of 70% when gas prices have since increased and are pr ojected to slowly increase for the
foreseeable future.

Commenters stated that unit-specific factors unique ly influence the potential amount of increased utilization that may be achievable by an individual unit. Commenters questioned why the EPA gave no consideration to these unit-specific variab les, stating that the Agency has previously acknowledged and analyzed such differences in suppo rt of the Section 111(b) proposal (listing such variables and citing the Combustion Turbine St andard TSD pp. 1-4). Commenters noted that this EPA study identified a number of differen ces among NGCC units commissioned from 2000 to 2010, and added that these differences beco me even more pervasive when considered across the entire fleet, which encompasses units co mmissioned from 1949 through 2014. According to the commenters, these units represent a wide spectrum of process designs, business models, regulatory requirements and operating condi tions that collectively and uniquely influence the potential future performance of each individual unit. Commenters listed the following factors that contribute to these differen ces: variations between combustion turbine manufacturers and suppliers; variations in the vint age model combustion turbine employed; options for duel-firing natural gas, oil, or other gases in the combustion turbine; HRSG and steam turbine design differences; unit designs that integrate other, non-combustion-turbine
related steam sources into the HRSG and steam turbi ne design; differences in equipment redundancy to support increased utilization; differ ences in the winterization of equipment to enable cold weather operations; differences in the condition of process equipment to support
increased utilization.

Commenters also stated that the EPA ignores the fac t that some existing NGCC units simply may not have been designed and constructed for the purpose of operating at higher capacity factors, supporting this contention with example la nguage from the air permits for two NGCC facilities in Arkansas (which indicates that the un its are intended for intermediate or peak load conditions) and historical data from the units (whi ch shows that they both have operated at very low capacity factors - as they were designed and in tended to operate - for various technical and economic reasons). Commenters stated that it is iro nic that the EPA did acknowledge that certain existing and future NGCC units may be designed for the purpose of operating at lower capacity142

factors in the proposed 111(b) standards for new so urces (citing 79 Fed. Reg. 1445 and 1459).
Commenters went on to state that for those units th at are not designed to readily increase utilization or that may not have historically opera ted at higher capacity factors, EPA references in the proposed CPP a 2011 paper to suggest that in creased operation across the NGCC fleet is feasible: "...a four-pronged approach for achieving higher availability and reliability is outlined: (1) robust design utilizing the field data gathered during scheduled outages; (2) efficient scheduled outage management with emphasis on qualit y; (3) proactive intervention with remote monitoring technology and (4) improved design and u pgrades for longer parts life". Commenters asserted that the EPA provides no evaluation to ass ess whether this "approach for achieving higher availability and reliability" has been or ev en could be implemented across the entire NGCC fleet, and that the EPA fails to examine how a ny of the aforementioned unit-specific criteria may lessen the potential for existing unit s to increase operations in the future. Commenters noted that the EPA did recognize and acc ount for some of these factors in the 111(b) proposal for new sources by proposing separa te standards for two subcategories of combustion turbines based on the size of the unit, reproducing the EPA's rationale at 79 Fed. Reg. 1486-1487.

Commenters concluded that the EPA has not demonstra ted that it is feasible to establish a single capacity factor goal that can adequately account fo r and address unit-specific factors that affect the potential for increased utilization, whether th at capacity factor is set at 65% or 70%. Commenters asserted that aside from deferring to th e lowest common denominator capacity factor that could potentially be achieved by an ind ividual unit, it is not possible to determine a single goal that could be achieved by all units, an d that given the inherent differences that determine a unit's potential for increased utilizat ion, the EPA should abandon any attempt to apply a single capacity factor to all existing NGCC units.

Commenters stated that many NGCC units were not des igned and constructed for baseload operations and would require significant evaluation and upgrades to enable them to operate continuously at a 70% or greater capacity factor. C ommenters cited a November 2014 Energy Ventures Analysis and stated that many NGCC units w ere not constructed for base load operations and could require significant evaluation and upgrades to enable them to operate continuously at a 70 percent or greater capacity fa ctor on an annual basis. Commenters cited UARG comments (Section XV.B) and stated that some u nits were financed, designed, and maintained for the specific purpose of operating in cycling duty rather than as base load and, thus, many of these units would not be able to achi eve the target utilization rate without significant upgrades and testing to ensure that the y are physically capable of operating near full
load on a continuous annual basis.

Commenters stated the EPA failed to consider the un it-specific circumstances of NGCC units, such as what and how states have permitted them to operate and whether or not they are warranted to run at higher capacity factors. Commen ters stated the EPA failed to give adequate consideration to potential infrastructure challenge s from significantly increasing NGCC
utilization.

Commenters stated the EPA's assumptions regarding c apability of the existing NGCC fleet fail to consider the unit by unit variations of the fleet. Commenters stated that, while in some parts of the country certain NGCC plants achieve a capacity factor close to the 70 percent capacity factor143

used by EPA, many existing NGCC units in the Midwes t are considered intermediate resources with much lower capacity factors. Commenters stated that achieving this much higher capacity factor requires significant capital investment; for Hoosier Energy's Holland Energy Facility, this investment is estimated to be $60 million. Commente rs stated that, along with an increase in capital expenditures, costly maintenance intervals, and the resulting outage times, will become more frequent based on higher run hours and more fr equent maintenance outages will impede the potential capacity factors of the units.

Commenters stated that the four-point rationale the EPA used to justify the Building Block 2 conclusion that a 70 percent capacity factor is ach ievable and adequately demonstrated is flawed because the EPA confuses unit-level NGCC capabiliti es with the capabilities of state-wide or
nation-wide NGCC fleets.

Determine capacity on a state-by-state basis.

Commenters suggested capacity should be determined on a state-by-stated basis.

Commenters stated that issues with grid boundaries that run between jurisdictions can also pose problems. Commenters stated that, for example, incr easing the amount a natural gas plant runs in one part of a state under one jurisdiction may not be compatible with lowering the amount a coal plant runs in another jurisdiction (a different bal ancing authority, RTO, or even grid). Commenters suggested the EPA reconsider its assumpt ion that all states will be able to achieve a NGCC capacity factor average of 70% and take into c onsideration the particular circumstances of each state (i.e., natural gas pipeline capacity, NGCC power plant design, total state generating capacity, and peak electricity demand) when setting each state's Building Block #2 target.

Commenters recommended a utilization rate lower tha n 70% for NGCC units. Commenters stated the appropriate rate should be determined on a state-by-state basis that takes into account the type of turbines in use and restrictions on the ir hours of operation, the adequacy of the state's transmission grid, and the availability of firm nat ural gas service to allow for increased operations at the NGCC units. Commenters stated the EPA designed this building block without considering the availability of infrastructure (bot h with respect to natural gas supplies and electric transmission), operational constraints bas ed on criteria pollutant emissions, or the type of technology used in the existing NGCC fleet to deter mine whether that level of re-dispatch is possible for a state. Commenters stated that LPPC m embers report that their states have existing NGCC units with restrictions on operations in order to attain ozone standards.
Commenters stated that NGCC units that utilize aero derivative-design combustion turbines (instead of heavier-duty, industrial class designs) are not capable of operating at a 70% capacity factor and that several LPPC members report that th eir states have existing NGCC units of this
type.

Commenters stated that, at a minimum, the EPA shoul d set a NGCC capacity factor for building block 2 on a state-by-state basis using a three-yea r average. Commenters stated the EPA should develop building block 2 based on the NGCC capacity factor that has already been achieved by the NGCCs in each state. Commenters suggested, as a more supportable approach, using the historic average of the three years of highest NGCC capacity factors for each state. Commenters stated that using this average more fully accounts for variable conditions in fuel supply, pricing,144

NGCC maintenance cycles and interaction with other generation types that were not considered by EPA in setting the 70% capacity factor. Commente rs stated that EPA should then test the viability of the resulting three-year average capac ity factor by considering the worst-case conditions that may occur in each state. Commenters stated these conditions, should, at a minimum, account for peak natural gas use by all se ctors (residential, commercial, vehicle, etc.), natural gas transmission and storage constraints, a nd peak electric reliability needs. Commenters suggested that any capacity factor also be evaluate d for offsetting interactions with other building blocks. Commenters stated this approach wo uld ensure each state-specific capacity factor could support system demand over the long-te rm, including periods of extreme demand (e.g., polar vortex events). Commenters stated that , if the EPA maintains the approach of applying a single capacity factor to all NGCCs on a national basis, then this capacity factor
should be based on what is achievable in the most c onstrained state (i.e., the state with the lowest historic 3-year average capacity factor). Commenter s explained that this is because the limit set
under BSER must be achievable across all states and sources so that no state can be put at a disadvantage by the regulation.

Commenters stated that, although their NGCC facilit y does have the technical potential to reach a 70 percent CF other limiting factors could exist that are not in Empire's control such as regional transmission constraints and natural gas commodity and transportation availability. Commenters stated that previous, localized volume achievements cannot constitute the baseline for assessing the feasibility of sustained, system-wide performan ce improvements. Commenters stated that in EPA's Regulatory Impacts Analysis (RIA) the conclus ion is made that the NGCC fleet will only reach CF of 50-57 percent, not the 70 percent utili zation rate that is indicated as achievable.
Commenters asserted the states should be allowed to demonstrate the level of increased NGCC
utilization that is feasible for the individual sta te.

Commenters stated that rather than prescribe the am ount of NGCC dispatch based on generic information as done in Building Block 2, the EPA sh ould defer to the states in determining the degree of NGCC re-dispatch that is feasible, taking into consideration state-specific variables, including plant ownership considerations, air permi t limitations, remaining useful life, electric transmission capacity, load pockets, gas availabili ty, location and actual capacity of the NGCCs (including climatic and altitude considerations), c ommercial limitations, contractual restrictions, pipeline capacity, transmission capacity, actual he at rates, and other issues. Commenters said that states are in a much better position than EPA to de termine maximum dispatch capability of the units in their footprint and should be permitted to adjust their targets accordingly after submitting evidence regarding the degree of re-dispatch that i s feasible. Commenters stated that the EPA's technical analysis of whether and how such a large scale re-dispatch from coal to natural gas can occur is incomplete. Commenters suggested that the states must determine whether existing NGCC EGU capacity can, in fact, supplant existing c oal-fired EGUs taking into account numerous factors, including, transmission constrain ts, gas supply limitations, the remaining useful life of the source, continued reliability of electric service, contractual obligations of existing coal-fired and NGCC EGUs' owners, cost to ratepayers, location, actual capacity of existing NGCCs, environmental constraints (such as permit limits due to proximity to nonattainment areas), national security risks, and mar ket limitations.

Need to consider the maintenance outages and the eq uipment availability factor.145

Commenters expressed concern that there will be per iods when the NGCC units will be off-line for scheduled maintenance outages, as well as insta nces of forced outages of unpredictable duration. Commenters stated that, while the data de monstrate that it is feasible for Smith 4 and 5, and Buck to operate at capacity factors of 70%, the y cannot operate exclusively in this manner. Commenters stated, for example, the equivalent avai lability factors (EAF) for North Carolina's operating NGCC units for calendar year 2013 25 rang ed from 87.88% to 93.29%, meaning that on average, during calendar-year 2013, the NGCC uni ts were unavailable for approximately 1 to 1.5 months. Commenters explained EAF is the amount of time that a generating plant is able to produce electricity (adjusted for periods of partia l capacity availability) over a certain time period, divided by the total amount of time in the period; EAF is different from capacity factor which is a measure of actual electricity production over a given amount of time. CF always will be less than EAF for the same period. Commenters st ated that, as the NGCC units age, they likely will be subject to even more scheduled maint enance and forced outage conditions, driving their EAF, and thus capacity factor, lower. Comment ers also noted the historical price of natural gas relative to coal has played a significant role in the utilization of both Smith units and Buck; they have been dispatched as baseload units because of the recent historically low price of natural gas ($0.03-$0.04/kWh) combined with their e xcellent heat rates (~7,000 Btu/kWh).

Commenters stated that, because NGCCs are complex m echanical systems that malfunction even under the best of readiness and preventive maintena nce programs, the EPA must consider both unit availability and the increased potential for o utage with additional wear and tear on the existing fleet of NGCCs prior to developing policy targets.

Need to consider the location of each plant.

Commenters stated the EPA overestimated and over-si mplified the potential for re-dispatch.
Commenters stated that limitations such as the loca tion of each plant in the electric grid and plant position vis-a-vis nodes and load must be considere d. Commenters stated these locational
limitations matter as much as unit size or technica l capabilities. Commenters stated, for example, some NGCC units that theoretically could run at hig her capacity factors will necessarily be hindered by transmission constraints and, for coal- based generation to be able to be replaced by increased production from existing NGCCs, the natur al gas units would have to be located in proximity to the coal plant. Commenters stated the EPA should not assume that it makes sense for EPEC or our region to simply "turn up" these un its, as (I) that large of a block of power doesn't meet their minimum load profile and (2) it could result in selling that power below generation costs.

Commenters stated the EPA's analysis does not suppo rt the achievability of increasing NGCC utilization to 70 percent, based on their review of EPEC's two existing NGCC plants located at the Newman Power Plant in El Paso, Texas. Commenter s stated both NGCC units are "two-onones," that is, two simple cycle natural gas turbin es of about 70 MW each, on a single steam turbine, for an overall power block of between 230 and 280 MW. Commenters stated that one has the flexibility to operate solely in simple cyc le mode in the off-peak, winter months, both have the ability to operate using one of the two ga s turbines depending on demand, and both have operating capacity factors that range from 45 to 60%. Commenters stated the > 200 MW block is at times too large to manage the changes i n load, and the stated flexibility is crucial to economic dispatch. Commenters stated that it would not be appropriate to increase their capacity146

factors to 70 percent since their system dispatches these NGCC either in simple or combined cycle mode depending on daily variations (i.e., coo l evenings and hot afternoons typical of our desert climate) and/or seasonal changes (turn off C C in wintertime). Commenters stated that EPEC is unique in its location at the southwest cor ner of WECC, and in satisfying reliability criteria including managing frequency, regulating v oltage, and meeting our reserve obligation. Commenters stated that, depending on various circum stances, NGCC is not optimal/economic dispatch. Commenters stated that, because these uni ts are relatively large (e.g., 270 MW), in the wintertime, or at nighttime, they are turned off to match demand.

Permit condition with a 70% capacity requirement is not demonstrated.

Commenters alleged that the EPA has failed to adequ ately demonstrate that a minimum 70% capacity factor requirement has been achieved by an y existing NGCC unit. Commenters stated that based on commenters’ survey of over 300 air pe rmits for coal and NGCC units, no examples have been identified of a specific requirement that establishes a minimum capacity factor from the regulated source. Commenters asserted that the EPA does not identify a single permit or regulatory obligation for an existing NGCC unit tha t establishes a requirement that the source achieve a specific capacity factor, let alone a 70% capacity factor. Commenters indicated that while certain units have operated at capacity facto rs at or above a 70% capacity factor because they were economical and otherwise available to run , this in no way adequately demonstrates that a minimum 70% capacity factor threshold could be manifested into a permit condition for any or all units that could be sustainably achievab le across the range of operating, outage, and market conditions experienced over the life of a un it.

Comment 23: Commenters disagreed with the EPA's use of a nation al average capacity factor to claim that a 70 percent annual capacity factor is a n achievable goal.

Response 23: The EPA disagrees with the interpretation that the 111(d) requires every NGCC unit to average a 70 percent average annual capacit y factor. The 111(d) final rule requires that states develop plans that establish emission standa rds for affected EGUs. We are providing states with substantial flexibility as to how they structu re those plans to achieve the 111(d) requirements. The flexibility includes, for example , the choice of approaches, trading, time to develop plans, additional time before the start of the interim performance period (postponed from 2020 until 2022), and the ability to shift emission rate achievement between performance periods. The Building Blocks are not prescriptive, and states may consider local circumstances as they develop their plans, including system reliabil ity, fuel diversity, other regulatory requirements and infrastructure. The 111(d) final r ule does not require every individual NGCC to meet a CO2 emission performance rate, but rather th e 75 percent capacity factor was used in the calculations to establish a rate. See sections V.D, VIII.A, VIII.C and VIII.G of the final rule preamble of the CPP and Chapter 3 of the GHG Mitiga tion Measures TSD for the CPP Final Rule supporting the final CPP.

The following are summaries of the specific public comments under this comment:147

Preamble and TSD capacities differ.

According to commenters, the EPA stated that the na tionwide NGCC capacity factor during peak hours of the day averages 11 percentage points high er than the overall annual average, and the Agency suggested that the current system is able to support national average capacity factors "in the mid to high 50's for NGCC for peak" (i.e., 11 p ercentage points higher than the 2012 national average capacity factor of 45.8 percent) . Commente rs asserted that the EPA did not explain why it believes it is reasonable to expect that the cur rent system can accommodate an additional 10- 15 percentage points in order to reach a 70 percent average capacity factor over all hours of the day.

Commenters stated that the EPA is confused concerni ng its entire justification for Building Block 2 in that the Agency cites different values f or this analysis in the preamble than in the GHG Abatement Measures TSD. According to the commen ters, in the preamble the EPA claims that national average capacity factors are "60 perc ent or higher" during peak hours, and that these values are "15 to 20 percentage points above their average utilization rates" (79 Fed. Reg. at 34,863), but in the GHG Abatement Measures TSD that national average capacity factors are "approximately 50%" during peak hours, and that the se values are "approximately 11% above the average capacity factor". The commenters stated that the EPA does not explain this discrepancy, but the values in the TSD appear to ma tch the EIA sources EPA cites in both the preamble and the TSD, so the commenters assume that the values in the TSD govern.

Need unit-specific analysis due to multiple potenti al constraints.

Commenters stated the assumption that NGCC units ca n consistently achieve a 70% capacity factor requires evidence that has not been demonstr ated by the EPA or any other entity. Commenters stated that SMEPA owns a significant amo unt of NGCC capacity, but has never economically achieved more than a 32% capacity fact or and that was in 2012, when natural gas prices were at a 10 year low. Commenters stated thi s is due to a number of factors, including forced outages, planned outages, and economics. Com menters stated that, to reach a 70% capacity factor in 2012, would have required SMEPA to dispatch generating units outside of economical dispatch. Commenters stated there are se veral NGCC units in Mississippi that are mothballed or have never dispatched due to transmis sion or other limitations. Commenters stated the EPA should investigate each NGCC plant to verif y what it can reliably perform in terms of output, then fashion its rule for Mississippi.

Commenters objected to the EPA's use of a national average NGCC utilization rate as the basis for its conclusion that natural gas plants can meet the 70% utilization rate. Commenters stated that using a national average ignores regional diff erences in both existing and potential new infrastructure. Commenters stated that, since not a ll states or regions have a 60% NGCC utilization rate during constraints or otherwise, t he EPA's conclusion appears to incorrectly
assume that in all instances the infrastructure exi sts to allow natural gas plants to meet the 70%
utilization rate.

Commenters stated that, in some areas, NGCCs with t he technical ability to meet a 70% capacity factor already are being utilized to a high degree. Commenters noted that, while the EPA quoted a 2012 average NGCC utilization rate of 35% across the United States in the Proposed Rule,148

Commenters stated that in January through October 2 014, for Entergy units, the average NGCC capacity factor was 57.7%, and the average coal pla nt capacity factor was 71.1%. Commenters stated this demonstrates that, for these units, the national average does not apply. Commenters stated that two problems arise in this situation fr om EPA's reliance on Building Block 2: (1) there may be less delta in current and future (up t o 70%) capacity factor that should be factored into Building Block 2 and (2) if an NGCC unit alrea dy is being used at a high-capacity factor, such as for load following or even baseload generat ion, the unit's flexibility to take on additional generation responsibilities within the system likel y is limited.

Need to account for seasonal and regional differenc es.

Commenters stated the EPA's assumption that coal fi red generation can be re-dispatched to NGCC up to a 70% capacity factor fails to account f or season and regional differences in dispatch of natural gas. Commenters stated that the EPA's assumption for reaching the capacity factor is based on a simplistic view of excess NGCC capacity that assesses an annualized capacity factor rather than seasonal load demands. Commenters stated that the EPA needs to conduct a more robust evaluation of available capac ity at existing NGCC EGU's to allow for
seasonal variations in load demands. Commenters sta ted that Nevada has considerable installed NGCC generating capacity (over 5 GW) located in sou thern Nevada and, during summer months load demands in these areas may be double that of w inter. Commenters stated that, although there may be the appearance of excess NGCC capacity on an annual basis, it will likely not be available during the summer to make up for lost coa l generation. Commenters stated that, because of the limited generation in northern Nevad a, it is likely that there will be periods (particularly in the summer months) that even with the NGCC capacity increases in southern Nevada, the electricity demand industrial areas in northern Nevada will outstrip available supply. Commenters stated that achieving such a dramatic sh ift in generation and transmission of power would disrupt the operation of the electric grid, p articularly in northern Nevada where most NvMA members operate.

Commenters stated that, on an average annual basis it might seem possible that natural gas-fired plants could replace coal-fired generation; however , a more granular look shows that they will not be able to do so during peak load months. Comme nters provided a Chart showing the operating history of two combined cycle plants used by Avista to serve load in 2012. Commenters stated that, while the average capacity factor for the two plants was approximately fifty percent in 2012, to achieve this level, both operated well above seventy percent in four of the 12 months. Commenters stated that, because thes e months which coincided with peak load levels, these plants were necessary to ensure syste m reliability and were not surplus to the system and able to stand in for other plants; i.e., they w ould not be available to replace reduced coalfired output during peak load periods. Commenters s tated that, although these plants are just two in the United States fleet, many or most will have similar operating profiles and not be available as envisioned by EPA in the proposed rule. Commente rs stated that, because this pattern is indicative of conditions in the Pacific Northwest, forcing additional dispatch to natural gas during the months of currently-low dispatch can onl y lead to increased carbon emissions, not to mention difficulties in transmission capacity, a pr oblem already experienced with increased regional wind generation in the spring.

Capacity targets should be based on state-specific information.149

Commenters stated the EPA should tailor targets for natural gas based on the actual in-state capacity factor to reflect the true capacity factor in the state. Commenters stated the average capacity factor (45%) used by EPA for purposes of s etting South Carolina's emissions reduction target over-estimates the ability of South Carolina utilities to increase the capacity factor at existing NGCC units currently on their system. Comm enters stated the four NGCC units controlled by South Carolina utilities actually per formed at an average capacity factor of 65% in 2012. Commenters stated that, if South Carolina cou ld demonstrate that the capacity factor (45%) used by the EPA to establish South Carolina's emission reduction goal overestimates our state's utilities' ability to increase the capacity factor at existing NGCC units currently on their system, then the EPA should amend the capacity fact or to reflect the true capacity factor in South Carolina. Commenters stated that, for example, a 55 0 MW natural gas combined-cycle (NGCC) with Duct Firing plant, (does not include Heating S team output to Industrial Customer of approximately 95 MWs), owned by EPHOS Energy (forme rly Columbia Energy), and operated by LSP, located in South Carolina, operated at less than a 1% capacity factor in 2012. Commenters requested the EPA provide an explanation for how it determined the available capacity factors of natural gas units in South Caro lina.

Commenters stated it is not appropriate to apply na tion-wide averages on capacity factor to Florida NGCCs. Commenters objected to the Proposal' s presumption that under construction NGCC are only planned to be operated at 55% capacit y factor, which allows the Proposal to push existing generation to these new units (http:/ /ampd.epa.gov/ampd/). Commenters stated the justification that new NGCC only operate at 55% cap acity factor under business as usual is based on a nation-wide review of the typical capacity fac tor from all NGCC that began operating within the last 5 years. Commenters provided a tabl e which presents those new NGCC (initial operation within 5 years of 2012) with data in EPA' s proposed rule docket that can be applied to
the unit level. Commenters stated this table shows the weighted average demonstrated capacity factor for the most recent NGCC in Florida is 63% ( weighted by NGCC nameplate capacity). Commenters stated this suggests that there is littl e, if any planned capacity at these units that will be available for re-dispatching coal and oil steam generation, even if other system constraints are not present. Commenters stated that, because the 90 th percentile existing NGCC in Florida operates at 65% capacity factor, at most there is 2 % availability for re-dispatching. Commenters stated that, while the EPA acknowledges that pipeli ne capacity is essentially capped more by peak demand than total inflow and outflow capacity, even with this acknowledgement, the EPA still claims sufficient pipeline capacity based on inflow and outflow. Commenters stated the EPA analyzes peak hours, but only for the annual averag e peak hours across the entire nation. Commenters stated this is not a "peak" with which w ould define a capacity constraint of a pipeline. Commenters stated that, if EPA's assessme nt were correct, there would not have been curtailment as recently as 2014. Commenters added t hat since Florida's two gas pipelines have little to no access to storage, Florida is more sus ceptible to peak demand challenges than other areas of the country.

Comment 24: Commenters described its exploration of the hypothe sis that the amount of existing NGCC re-dispatch contemplated by the state goal calculation methodology in building block 2 and in the EPA's compliance modeling analys is is not limited by constraints in air permits limiting the number of hours per year that existing NGCC units can run.150

Response 24: The EPA agrees in general. The 111(d) final rule r equires that states develop plans

that establish emission standards for affected EGUs . We are providing states with substantial flexibility as to how they structure those plans to achieve the 111(d) requirements. The flexibility includes, for example, the choice of approaches, tr ading, time to develop plans, additional time before the start of the interim performance period (postponed from 2020 until 2022), and the ability to shift emission rate achievement between performance periods. The Building Blocks are not prescriptive, and states may consider local cir cumstances as they develop their plans, including system reliability, fuel diversity, permi tting, or other regulatory requirements. The 111(d) final rule does not require every individual NGCC to meet a CO2 emission performance rate, but rather the 75 percent capacity factor was used in the calculations to establish a rate. See sections V.D, VIII.A, VIII.C and VIII.G of the fina l rule preamble of the CPP and Chapter 3 of the GHG Mitigation Measures TSD for the CPP Final R ule supporting the final CPP.

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

Commenters investigated whether NGCC units located in ozone nonattainment areas may have taken run restrictions or tonnage limitations in or der to limit their emissions of NOx and/or to achieve "synthetic minor" status in order to avoid major source permitting requirements and Title V fees. The commenters examined a sample of 18 NGCC operating permits in ozone nonattainment areas in Arizona, Arkansas, Colorado, Georgia, Ohio and Texas, and found that of those 18 permits, only two contained permit restric tions that might constrain its availability to run for re-dispatch at below an 70 percent annual u tilization factor and installation of NOx
controls would allow both of them to run at utiliza tion factor greater than 70 percent. The
commenters concluded that the examination of availa ble permit "headroom" in underutilized NGCC units strongly indicates that these units' air permits do not contain restrictions that would create a barrier to the level of natural gas re-dis patch EPA has assumed in building block 2 or in its compliance modeling.

Comment 25: Some commenters stated that the EPA should account for permit limits that may affect the achievable capacity factor.

Response 25: The EPA disagrees. The 111(d) final rule requires t hat states develop plans that

establish emission standards for affected EGUs. We are providing states with substantial flexibility as to how they structure those plans to achieve the 111(d) requirements. The flexibility includes, for example, the choice of approaches, tr ading, time to develop plans, additional time before the start of the interim performance period (postponed from 2020 until 2022), and the ability to shift emission rate achievement between performance periods. The Building Blocks are not prescriptive, and states may consider local cir cumstances as they develop their plans, including system reliability, fuel diversity, permi tting and other regulatory requirements. The 111(d) final rule does not require every individual NGCC to meet a CO2 emission performance rate, but rather the 75 percent capacity factor was used in the calculations to establish a rate. See sections V.D, VIII.A, VIII.C and VIII.G of the fina l rule preamble of the CPP and Chapter 3 of the GHG Mitigation Measures TSD for the CPP Final R ule supporting the final CPP.151

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

Commenters stated the Proposed Rule overstates the achievable capacity factor and the megawatts of NGCC capacity for Building Block 2 by failing to consider NGCC permit limitations. Commenters stated that increasing capa city to 70% would, in many cases, require units to undergo re-permitting by state regulators, a process which can take years. Commenters recommended that reforming and streamlining the per mitting process for utility facilities could improve the possibility of at least reaching the fi nal 2030 goal. Commenters stated that the EPA's NGCC re-dispatch analysis should account for NGCC p ermit limitations on operating hours, total emissions and incremental consumption, as wel l as operation limitations driven by ozone
nonattainment concerns. Commenters stated that the EPA failed to acknowledge that some of these units may have permit restrictions that limit the emissions, amount of fuel, or hours of operation, making 70% utilization a legal impossibi lity. Commenters stated there may be operational constraints that would limit the capaci ty factor of existing NGCC units due to air permit requirements that were written to cap emissi ons of NOx or carbon monoxide in ozone
nonattainment areas.

Commenters gave the following examples of constrain ing permit limitations:

• EPA assumed that Afton Generating Station in New Me xico could operate at a 70 percent capacity based on the total capacity of the facility including the duct burner. However, the Afton permit only authorizes o peration of the duct burner for 1,920 hours per year, or less than 22 percent o f the time. The generating capability of the unrestricted portion of the facil ity (i.e., without the duct burner) is 337,260 MWhr short of EPA's expectation for Afto n. For the duct burner to make up that difference, based on the 60 MW capacit y of the burner indicated in the Afton permit, the burner must operate for at le ast 5,621 hours, which is nearly three times the level that the Afton permit authori zes. Conversely, if the duct burner operated for the hours the permit authorizes , the unrestricted portion of the facility would be required to operate at a 81 perce nt capacity factor. In the state of Michigan, where EPA ramps up existing NGCC capacity to 70 percent in the Building Block 2 goal setting methodology, the Jack son Michigan Facility (649 MW) currently operates under a Title V permit that contains enforceable restrictions sufficient to limit operation under a 70 percent capacity factor. The Title V permit for this facility contains hourly an d 12-month rolling NOx emission limits, such that high capacity factors (u tilization rates) would result in
annual NOx emissions above their annual limits. Con sumers Energy, which has a contract to purchase the facility, undertook an int ernal analysis and examined the 2012 high utilization period (May to August), concl uding the capacity factor for the entire plant would be limited to 49 percent.

• In Colorado, Brush 1-3 unit is limited by its air permits to 37% annual capacity factor, Brush 4 is limited to 18 % annual capacity factor, and Arapahoe is limited to 30% annual capacity factor.152 • Commenters stated that many existing NGCC units, su ch as Tri-State Generation
and Transmission Association's J.M. Shafer Generati ng Station (272 MW) and Arkansas Electric Cooperative Corporation's (AECC) Harry L. Oswald (548 MW) Generating Station and Thomas B. Fitzhugh Generatin g Station (165 MW) facilities, have operating permit mass emission lim its and/or fuel usage limits, effectively capping their maximum possible operatio ns below a 70% capacity
factor.

• Commenters stated that many NGCC units in Southern California are prohibited from increasing their capacity by both state and fe deral environmental rules and policies. Commenters stated that, because units loc ated in the South Coast Air Quality Management District (SCAQMD) must obtain an d surrender Regional Clean Air Incentives Market (RECLAIM) credits to co ver all of their nitrogen oxides emissions, consequently, these units may be prevented from increasing their capacity factor significantly due to the limi ted amount of RECLAIM credits available. Commenters noted that the SCAQMD recentl y proposed an additional
reduction in RECLAIM credits that could further res trict NGCC units in the air district from increasing their utilization to repla ce lost coal-fired generation. Commenters stated that the EPA should individually evaluate NGCC EGUs to determine if they are located in areas that will li mit their operation, and account for this when establishing goals for states.

• In addition to local electrical grid constraints su ch as transmission, local environmental regulations may already be in place t hat would conflict with increased operation at NGCC units, Commenters state d that, for example, system owners in the Houston-Galveston-Brazoria (HGB) eigh t-hour ozone nonattainment area whose system is comprised mostly or entirely of NGCC units, may not have sufficient operational flexibility und er their system cap to operate at the 70% capacity that EPA assumes. In reality, many existing NGCC units face constraints that will prevent them from increasing their utilization to a 70 percent capacity factor. Some units may be located in areas that are designated as in nonattainment for a NAAQS, and as a result would likel y have operating permits imposing mass limits on carbon monoxide ("CO") or N Ox emissions that would effectively establish a cap on those units' operati ons. Marchetti Report at 26.

• Commenters stated that increasing NGCC generating c apacity in the West could lead to conflicts with ozone attainment plans and u nit-specific run-time limitations that are contained in many NGCC operati ng permits. Commenters
stated that units in ozone non-attainment areas thr oughout California and neighboring states, and units with permit-level run -time restrictions will likely be unable to increase utilization to levels approachin g 70%. Commenters stated that,
even if NGCC units are able to increase their utili zation in these areas without violating environmental laws and regulations, the i ncrease in generation could exacerbate ozone or particulate matter problems in some non-attainment areas. Commenters noted that studies by WECC and others co uld reveal additional constraints related to water or drought impacts in the West, or the need for significant additional pipeline and transmission ca pacity. The EPA should153 individually evaluate NGCC EGUs to determine if the y are located in areas that will limit their operation, and account for this wh en establishing goals for states.

• Commenters stated that increasing NGCC generating c apacity in the West could lead to conflicts with ozone attainment plans and u nit-specific run-time limitations that are contained in NGCC permits. Com menters stated the EPA should identify how to address these broader and st ate-specific constraints in developing and testing its assumptions about re-dis patch to NGCC, and revise Building Block 2 accordingly. Commenters noted that EGUs located in the South Coast Air Basin are subject to SCAQMD's NOx RECLAIM program, and SCAQMD is in the process of further reducing the NO x emission credit
allocations from affected sources. Commenters state d that, depending on how the reductions are allocated, the capacity factors of E GUs in the SCAQMD may be specifically limited.

• Commenters stated the EPA must ensure that block tw o targets do not interfere with the ability of Utah to protect its air sheds a nd address existing and future air quality regulations. Commenters stated the EPA fail s to properly account for the efficiency penalties caused by NGCC emission reduci ng technologies; for example, some of Utah's NGCC plants include selecti ve catalytic reduction (SCR) for NOx emissions control, which can further reduce plant efficiency.

• Commenters stated that since NSR permitting may lim it a unit's operation, the EPA estimate of re-dispatch to certain facilities i s greatly overestimated. Commenters stated that, unless NGCC facilities are already permitted at 70% capacity or more, re- dispatching could cause a fac ility's increased usage to trigger new source review (NSR), making this option either infeasible or very costly. Commenters noted that, for example, Afton Generatin g Station is permitted to operate only 1,920 hours per year with its duct bur ner, yet EPA assumed full nameplate capacity using duct burners to determine the amount of re-dispatch to this facility under Building Block 2. Commenters st ated that, for this assumption to be a possibility, the facility would need to und ergo NSR permitting in order to fully utilize the duct burners and that NSR permitt ing would require the evaluation of additional impacts to the air shed, a dditional emission controls which lower the unit's efficiency, and increased op erating costs.

• Commenters stated the EPA's assumption that existin g NGCC units can be operated at a 70 percent capacity factor ignores pe rmitting restrictions and pipeline capacity that will limit the operation of certain Colorado NGCC units.

• Commenters stated that restrictions in a generating facility's air permit can affect that same unit's capacity factor. Such restrictions include limitations on emissions and/or fuel usage. Commenters stated that, while th ere are environmental controls that could be installed to increase the capacity fa ctor, those costs would be additive to the all of the other compliance costs a ssociated with the proposed Rule. Commenters noted that AECC's Oswald plant is an NGCC plant that is limited by a NOx emissions cap in its air permit an d if each unit is operated at its154 average hourly NOx emission rate, the facility woul d be limited to a maximum annual capacity factor of about 60%. Commenters sta ted that AECC's Thomas B. Fitzhugh Generating Station's air permit lists a na tural gas usage limit of 9.626 billion cubic feet based on a twelve-month rolling average which limits the plant to a maximum annual capacity factor of about 63%.

• Commenters suggested that EPA should evaluate exist ing permit limits or determine how existing requirements may limit the f easibility of NGCC units to
achieve increased utilization rates. Commenters sta ted that a variety of air permit requirements are in place that provide operational flexibility or that restrict operations, which may significantly impact the amou nt of potential re-dispatch that may be available for certain units. Commenters provided an example permit condition from an NGCC facility in Rhode Island whi ch describes various conditions where natural gas shall be deemed unavai lable in which case the permittee is allowed to utilize fuel oil, with sulf ur content of 0.05 percent or less by weight, as replacement fuel. Commenters also pro vided several general examples, including NGCC units that are permitted t o combust fuel oil and natural gas; to co-fire other fuels with natural ga s (oil, landfill gas, coal gas, etc.); with conditions that limit natural gas use, which e ffectively limits the potential capacity factor that is achievable; to operate in s imple-cycle or combined cycle mode; and to operate the steam turbine with steam t hat is comingled from sources that are separate from the HRSG.

• Commenters stated that, because existing permit con ditions do not allow some units to sufficiently increase operation, the 70 pe rcent target is likely not achievable for the category as a whole. Commenters explained that permit
conditions at J.M. Shafer would limit it to an annu al capacity factor less than 55 percent and Rifle would be limited to an annual cap acity factor less than 25 percent. Commenters stated that, in practice, these facilities' capacity factors would likely be much lower since J.M. Shafer and Ri fle are subject to other limits in their Title V permits on annual emissions, as we ll as other permit limits on water discharge and operational constraints such as natural gas pipeline capacity. Commenters stated that, although the EPA did not ad dress this issue in the Proposal, the same barriers likely exist for many o ther NGCC units included in the Agency's analysis, meaning that the 70 percent re-dispatch target is likely not achievable for the category as a whole.

Commenters stated the EPA should not presume that a ll NGCC units in any given state can achieve the Block 2 targets due to (1) air permit l imits that restrict them from operating, lack of gas infrastructure, or lack of firm gas supply. Com menters noted that Colorado NGCC Plant Brush 1-3 is limited by its air permits to 37% annu al capacity factor.

Commenters noted that NOx emissions from all fossil fuel generation are regulated as precursors to ozone and fine particulate matter (PM2.5) under the NAAQS program and the level of stringency of NOx emission limits may depend on whe ther the generation is located in an
attainment area or a nonattainment area. Commenters stated there are at least two large NGCC155

units located in ozone nonattainment areas in Color ado that have fuel throughput limits that would restrict re-dispatch.

Commenters stated that, under the current air permi t, the Holland facility could not make a target of 70 percent capacity factor without triggering NS R. Commenters stated that Holland's Net Maximum Capacity as reported contains a significant portion of duct burner MW hours which are limited by the air permit to 1500 hours per yea r. Commenters stated this limitation roughly equates to a maximum of 55 percent capacity factor for the Holland facility. Commenters stated the permit cannot be modified to remove the 1500 ho ur limitation without significantly lowering the NOx limit and may require a CO catalyst as well as compliance with the most recent greenhouse gas BACT.

Commenters reported that, in many instances, the ai r permits they have for their natural gascombined cycle plants are limited to a 20-percent c apacity. The commenters asserted that, although a 70 percent capacity factor for combined cycle plants may be technically possible, permitting, transmission constraints and higher mai ntenance costs in the energy demand all affect the plants ability to run.

Commenters stated the EPA's determination that NGCC s can be utilized at 70% falls far short of
the case-law standard that BSER be "feasible" and " produce the improved performance necessary to meet the standard." Commenters stated the Agency makes no mention of how the national average can be ramped up from 46% in 2012 to 70% when many facilities are neither designed nor permitted to operate at such a high le vel. Commenters stated that many NGCCs are located in densely populated residential areas and are permitted to operate at such a high level only during periods of peak demand. Commenters stat ed that requiring states to meet a goal premised on these entities overcoming permitting re strictions based on public safety and reliability concerns is not "reasonably reliable" o r "reasonably efficient." Commenters stated that, in states such as Illinois, where the respect ive 2012 utilization rates were 26% and 27%, such a dramatic increase will most likely not occur and will not therefore "produce the improved performance necessary to achieve the goal."

Comment 26: Commenters stated the EPA did not consider that new NGCC generation must meet existing and revised NAAQS.

Response 26: The EPA disagree that analysis of the 111(d) final rule did not consider this. The 111(d) final rule requires that states develop plan s that establish emission standards for affected EGUs. We are providing states with substantial flex ibility as to how they structure those plans to achieve the 111(d) requirements. The flexibility in cludes, for example, the choice of approaches, trading, time to develop plans, additional time bef ore the start of the interim performance period (postponed from 2020 until 2022), and the ability t o shift emission rate achievement between performance periods. The Building Blocks are not pr escriptive, and states may consider local circumstances as they develop their plans, includin g system reliability, fuel diversity, NAAQS, and other regulatory requirements. The 111(d) final rule does not require every individual NGCC to meet a CO2 emission performance rate, but rather the 75 percent capacity factor was used in

the calculations to establish a rate. See sections V.D, VIII.A, VIII.C and VIII.G of the final rule156

preamble of the CPP and Chapter 3 of the GHG Mitiga tion Measures TSD for the CPP Final Rule supporting the final CPP.

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

Commenters expressed concern that EPA's just announ ced proposed revision to the ozone NAAQS may preclude increased utilization of existin g NGCC units.

Commenters pointed out that existing NGCC units are usually licensed to operate at full load continuously; however, a significant change in ozon e standards could result in a request to conduct additional Air Dispersion Modeling to addre ss the higher NOx resulting from related operational changes such as ramping. Commenters ind icated that it is difficult to anticipate the impact of a revised ozone standard on existing coal or natural-gas fired units without running air dispersion modeling for each location, and that res ults will vary depending on topography and proximity to other sources such as factories and ro ads. Commenters asserted that the EPA did not appear to take into account possible increases in N Ox emissions that might occur. Commenters stated that the Proposed Rule's compliance timeline for meeting the interim and final goals does not provide the utility sector or states with suffi cient time to go through all of the steps required to conduct the new Air Dispersion Modeling runs nee ded to verify attainment of existing NAAQS. Commenters indicated that the EPA apparently presumes that all or most existing NGCC units that would need to be re-dispatched to a higher capacity factor to meet building block 2 would immediately pass the Air Dispersion M odeling tests. Commenters stated that the Agency didn't take into account the impact of compl ying with revised NAAQS under a redispatch scenario. Commenters added that the EPA di d not consider the time needed to acquire revised Prevention of Significant Deterioration (PS D) permits for existing units when it set the interim and final compliance dates in the Proposed Rule. Commenters stated that had EPA done so, it would have realized that more time will like ly be needed to achieve the reduction goals the agency set for each state.

Commenters also stated that the EPA finalized a new NAAQS for nitrogen dioxide (NO2) that set a 1-hour standard for ambient NO2 at 100 parts per billion. Commenters indicated that NGCCs can comply with this standard, but because ba ckground ambient NO2 levels will be determined by monitors placed near highways, there is a concern that they will be found in noncompliance because the monitors cannot separate the NGCC unit emissions from the emissions
attributable to motor vehicles. Commenters warned t hat this could result in urban areas falling into nonattainment - if an existing NGCC unit is si ted in a newly designated NOx nonattainment area, emission offsets and/or use of some sort of c ontrol equipment not currently envisioned, or a higher stack, may be required. Commenters asserted that those costs or possible ozone precursor limitations of replacing existing coal plants with new NGCC units are not considered in the Proposal. Commenters added that the EPA's state pla n requirements do not give states adequate time to conduct PSD determinations using Dispersion Modeling since the state plans will presume that any existing coal plant with co-firing , or any gas plant needing any PSD modeling approval, would be completed before 2020.

Commenters expressed concern that the extent of pow er generation to re-dispatch to NGCCs in Maricopa County would increase emissions in our exi sting nonattainment areas and make achieving and maintaining existing and new, more st ringent NAAQS even more difficult.157

Comment 27: Commenters expressed concern that certain actions t o achieve the CPP goals may trigger NSR.

Response 27: The EPA disagrees. The Rule does not require states to take particular measures and provides flexibility, including trading and mor e time, to states to consider reliability and local circumstances, such as other environmental is sues and permits. The Building Block 2 provision is used to estimate an average annual cap acity factor for the purpose of establishing CO2 emission performance rates, and the state need not implement requirements that decrease grid stability or trigger NSR. Please see sections V.D, V.A, VIII.C, and VIII.G, of the final rule preamble of the CPP and Chapter 3 of the GHG Mitiga tion Measures TSD supporting the final

CPP.

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

Commenters expressed concern that the change in ope ration to a higher capacity could invite NSR enforcement. Commenters stated that, in some ca ses, removing certain permit restrictions may trigger NSR review. Commenters stated this rule should not contemplate actions that may trigger NSR.

Commenters suggested the EPA should consider elimin ating the PSD/BACT permitting requirement for certain existing NG units, at least in the short-term, to aid in the near term
transition envisioned in BB #2. Commenters stated t hat eliminating the PSD analyses for repermitting of natural gas peaker units like CWLP's Interstate turbine, a simple cycle natural gas (NG) unit, would facilitate greater dispatch of nat ural gas. Commenters stated that the increase in NGCC units on which building block #2 is based, at least in the short-term, is exceedingly optimistic. Commenters stated the EPA should consid er eliminating the PSD/BACT permitting requirement for existing NG units like CWLP's, at l east in the short-term, until such time as NGCC units, and the concomitant transportation netw ork necessary, reach the expected increase
the EPA has set for Illinois in the GHG Rule. Comme nters stated CWLP's Interstate turbine is currently not an affected unit under the GHG Rule b ecause of low utilization, a peaker unit as defined at 40 CFR 72.2 and it is permitted as a syn thetic minor source, in this case meaning it has permit conditions which limit it's potential to emit (PTE) to less than major source levels for NOx, CO, PM/PM10, VOM and/or SO2. Commenters stated that during last winter's polar vortex CWLP's natural gas supplier advised that it had no NG to run the unit and, even if natural gas were more abundant, CWLP's use of its Interstat e natural gas turbine would be limited by rule and permit. Commenters stated that, in the abs ence of any permit conditions, Interstate would be above major source levels and, thus, remov ing the operational limit would require a Best Available Control Technology (BACT) analyses f or each pollutant (which may include CO2, as well) required as part of the Prevention of Significant Deterioration (PSD) permit process. Commenters stated CWLP would need to contr act for air modeling to demonstrate that the increase in emission for each pollutant would n ot impact the national ambient air quality standards (NAAQS) and noted a PSD permit can take m any months if not years to be issued, and may contain stipulations on new emission rates and possibly new control devices, too.158

Comment 28: Commenters stated the EPA must consider oil-firing backup.

Response 28: The Rule does not require states to take particular measures and provides flexibility, including trading and more time, to st ates to consider reliability and local circumstances, such as backup fuel. The Building Bl ock 2 provision is used to estimate an average annual capacity factor for the purpose of e stablishing CO2 emission performance rates, and the state need not implement requirements that decrease grid stability. Please see sections V.D, V.A, VIII.C, and VIII.G, of the final rule pre amble of the CPP and Chapter 3 of the GHG Mitigation Measures TSD supporting the final CPP.

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

Commenters stated that use of a 2012 baseline where little, if any, oil firing was used, as there was not a pipeline interruption, does not fully cap ture a very possible future reality where many of the NGCC's utilize oil firing. Commenters stated the EPA must consider this planned possibility. Commenters stated that most units in F lorida have oil backup capabilities, and are permitted as such, due to Florida's unique energy p rofile, which is currently entirely dependent on only 2 natural gas pipelines bringing gas into t he state. Commenters noted that Florida has no coal mines, no significant oil refineries, and no s ignificant gas production; all fuels are imported. Commenters stated that pipeline interruptions must be accommodated in the power sector design and this is often considered as contingency plannin g should a natural disaster strike the state,
such as a hurricane. Commenters stated that station s are designed and already permitted to accommodate this back-up fuel. EPA must accommodate a back-up scenario in this rule when it so heavily relies on NGCC for justification.

Comment 29: Commenters expressed concern that the re-dispatch o f NGCC in Building Block 2 will eliminate NGCC as a source for providing neces sary flexibility to the electric system, including the ability to support renewable energy.

Response 29: The EPA disagrees. The 111(d) final rule requires t hat states develop plans that

establish emission standards for affected EGUs. We are providing states with substantial flexibility as to how they structure those plans to achieve the 111(d) requirements. The flexibility includes, for example, the choice of approaches, tr ading, time to develop plans, additional time before the start of the interim performance period (postponed from 2020 until 2022), and the ability to shift emission rate achievement between performance periods. The Building Blocks are not prescriptive, and states may consider local cir cumstances as they develop their plans, including system reliability, fuel diversity, other regulatory requirements and infrastructure. The 111(d) final rule does not require every individual NGCC to meet a CO2 emission performance rate, but rather the 75 percent capacity factor was used in the calculations to establish a rate. See sections V.D, VIII.A, VIII.C and VIII.G of the fina l rule preamble of the CPP and Chapter 3 of the GHG Mitigation Measures TSD for the CPP Final R ule supporting the final CPP.

The following are summaries of the specific public comments under this comment:159

NGCC needed to support renewable energy.

Commenters stated that, to avoid undermining integr ation of renewable energy resources, EPA should not include re-dispatch as part of the goal- setting methodology.

Commenters stated that the EPA's re-dispatch analys is must further consider the need for NGCC availability to support existing renewable energy a nd the renewable energy the Proposed Rule urges be constructed. Commenters indicated that NGC C units are, and will continue to be, needed to operate for peaking and intermediate load following to support intermittent renewable generation (79 Fed. Reg. at 34,862-63). According t o the commenters, gas-fired power plants are best suited to support variable RE given their quic k start-up times and high ramping capabilities. Commenters asserted that by failing to consider tha t much of the NGCC generation the EPA presumes available for re-dispatch is or must be co mmitted to supporting existing renewable energy or the renewable energy EPA presumes will be constructed under the Proposed Rule, the EPA has significantly overestimated available NGCC capacity.

Commenters recommended that, when determining the l evel of emission reduction that is achievable by NGCC re-dispatch, the EPA needs to co nsider the effect of changes in load following resources. Commenters stated that, under the CPP existing NGCC units will shift from load-following to baseload resources, however, the need for load-following resources will not be
eliminated as a result of the rule. Commenters stat ed the need for load-following resources will likely increase due to the rise in renewable penetr ation assumed in Building Block 3. Commenters stated that, if NGCCs become baseload re sources, their intermediate and loadfollowing role will likely be taken up by a combina tion of coal units operating at reduced loads and/or simple cycle peaking units operating at incr eased capacity factors. Commenters stated that both of these actions will likely result in higher emission rates at those load-following units than those of the existing NGCCs currently serving these functions.

Commenters stated the EPA did not consider the purp ose of CPGS (renewable energy backup) and incorrectly assumes that it can be preferential ly re-dispatched. Commenters stated the preferential re-dispatch of power from the CPGS is unrealistic and outside of EPA's jurisdictional authority. Commenters stated that th e intended operation of CPGS is to operate as a peaking unit with base-load capability to further enable renewable generation (wind, solar, and other renewable resources). Commenters stated that, while the EPA erroneously assumes redispatch of up to 70% does not result in additional costs to the operators or rate payers, in fact, there would be additional costs associated with hig her fuel rates for the NGCC turbines, increased maintenance cost, and costs for equipment that may no longer be necessary if CPGS is re-purposed.

Commenters stated that, while its NGCC facility in South Dakota, Deer Creek Station, can be ramped up to provide replacement power when wind re sources are down, if it were required to operate at a high utilization level, it would no lo nger have the available capacity to perform that function. Commenters stated that, in that situation the transmission operator would have to back
down Deer Creek Station so as not to overload the t ransmission system, which would be a major obstacle to Deer Creek Station achieving a 70% util ization rate.160

Commenters stated that building block two is incons istent with EPA's proposed block three, which is predicated on increased deployment of low- carbon generation. Commenters stated that, while the Proposed Rule assumes that South Carolina could obtain as much as 10% of its total in-state generation from variable RE resources such as wind and solar, the integration of this amount of wind and solar generation would require s ufficient quantities of dispatchable power to balance the intermittent supply of energy from RE. Commenters stated, however, the dispatchable balancing power is principally provide d by lower-capacity factor gas units, including NGCC units. Commenters stated that, if al l NGCC units are deployed at relatively high annual capacity factors, as block two assumes, thes e units will be unable to provide the necessary balancing services for the operation of the intermi ttent types of RE. Commenters concluded that blocks two and three thus place mutually incompatib le expectations upon gas generation units,
and EPA's failure to address these tensions is arbi trary and capricious.

Commenters stated the Proposed Rule's drive to incr ease natural gas consumption would have a negative effect on the expansion of renewable energ y. Commenters noted the EPA finds that, in light of low natural gas prices, market forces alon e may already lead investors to choose to build new NGCC units, rather than new renewable resources and stated the Proposed Rule's Block 2 exacerbates this market effect by rewarding, as BSE R, the increased utilization of natural forces to favor natural gas power generation. Commenters s tated it will be that much more difficult for RE and EE to retain their current respective share of energy production and avoidance of energy use, much less increase it. Commenters stated the E PA must revise the Proposed Rule so that it incentivizes RE and EE, not natural gas.

NGCC needed for balancing and regulation.

Commenters stated that dispatching at such a high c apacity factor will eliminate NGCC as a source for providing this flexibility. Commenters s tated that many RE options have to be balanced with quick response generation to account for periods when the RE source is not available as a result of changing weather patterns. Commenters stated that eliminating NGCC units from balancing and regulation due to the re-d ispatching of NGCC units to the equivalent of base load level capacity factors, forces this flexi bility to be provided from less economical resources at best, or worse could result in turning power off to Mississippians' homes and
businesses.

Commenters stated that it is quite important that N GCC units generally not be pushed to operate at a utilization beyond 70 percent. Commenters stat ed the ability of NGCC units, and other gas fired turbines, to vary their output is a necessary technical factor enabling the increased use of intermittent renewable generators (IRG), generally referred to as renewable energy (RE) in the EPA texts. Commenters stated that increasing expect ations for utilization reduces the average power margin available for NGCC units to compensate for changes in minute-by-minute and hour-to-hour IRG output.

Commenters stated that requiring the existing NGCC fleet to meet base load demand and respond to renewable power supply fluctuations leav es very little flexibility and reserve capacity to ensure a reliable electrical supply for the citi zens of Georgia.161

Commenters stated that most of the NGCC plants that provide electricity in Minnesota were built for flexibility, either to provide power during pea k periods of demand or to offset the intermittent production by wind generators. Commenters stated th at, if those plants are instead used as baseload plants, the ability to provide peaking pow er or to chase wind could be lost.

Analysis needed to avoid several issues.

Commenters stated that, in the West North Central r egion where wind is the predominant source of renewable energy, those wind units are backed up by the existing NGCC plants. Commenters stated it will require overbuilding of NGCC to ensu re that adequate capacity is dedicated to support renewable energy.

Commenters suggested the EPA should re-evaluate the impact of re-dispatch in Minnesota on operating variability and ramping due to the utiliz ation of highly intermittent renewable resources of solar, wind and biomass per preferenti al market dispatch and Minnesota law. Commenters stated that many of the natural gas EGUs in Minnesota were sited and built in locations that required grid support for the extens ive intermittent renewable generation. Commenters stated the Proposed Rule calls on these units to forgo their designed purpose and operate as baseload generation, contrary to the nee ds of the local electric grid. Commenters stated the failure on the part of the Proposed Rule to understand this fact will have serious consequences on the reliability of the electric sys tem for our member communities.

Commenters expressed concern that the EPA's analysi s did not address whether there will be sufficient other generation units available to hand le load-following duties that are currently handled by NGCCs assuming many NGCCs shift to base- load generation. Commenters stated that, while the current PJM generation portfolio re lies on nuclear and coal-fired generation for base-load with NGCC generation as a load-following resource, the EPA's BB2 proposal envisions NGCC facilities transitioning into more o f a base-load role with coal-fired generation assuming more of supplemental supply function. Comm enters stated their concern that today's coal-fired generation plants were not designed for and may not be up to the task of a "role
reversal" with NGCCs.

Commenters expressed concern that certain issues wi ll need to be addressed with careful modeling and planning. Commenters noted the followi ng issues:

Even with today's historically moderate to low natu ral gas pricing, not all NGCCs can compete in all markets based on bidding into competitive ma rkets. Commenters noted that the EPA proposes that states will fix this situation by for cibly adjusting dispatch order. In many regions there still exists excess capacity largely owing to lack of demand attributed to being not fully recovered to pre-recession levels. With much of the NGCC capacity being IPP or merchant, we see preferential dispatch for the regulated resourc es thus leaving merchant plants as peakers. Assuming states follow the EPA's suggestion of tilt ing the market to an environmental dispatch, this will likely cause some increase in the price o f electricity. A few units may be located in
areas where the demand is insufficient to reach the se proposed capacity needs. Providing backup for renewable power intermittency will most likely be covered by simple cycle units that can quickly enter the market and unless they exceed 219 ,000 MWHrs of operation will remain exempt from regulation. This may put further strain on the natural gas delivery system.162

Otherwise, logically, backup power will come from a portion of the existing coal fleet that has been reduced in capacity factor in favor of natural gas combined cycles. However with careful modeling and planning, even at a 70% capacity facto r, there can be adequate head room for NGCCs to still provide significant backup to renewa bles depending on demand.

Flexible capacity margin

Commenters stated the EPA must ensure grid operator s have adequate flexible generating capacity to respond to the range of daily grid-leve l fluctuations as well as firming capacity to enable increased renewables penetration. Commenters stated that, in recent years, with historically low natural gas prices and the high ef ficiency of NGCC, the NGCC generation assets have become cost competitive with coal facilities a nd have provided increasing levels of baseload generation. Commenters noted that, as rene wable assets increasingly penetrate the grid, flexible capacity margin will also increase in impo rtance. Commenters stated that, based on current technology, grid operators will use a combi nation of NGCC and high efficiency, highly flexible simple cycle gas turbine technologies to b ackstop renewables. Commenters stated that grid-balancing resources should be flexible, reliab le, dispatchable, efficient, low-carbon emitting,
and cost-effective. Commenters stated the EPA must factor grid-balancing when determining a target dispatch rate for NGCC. Commenters noted tha t, as states produce more electricity from renewable resources they will increasingly face dif ficulties posed by variable generation and relatively quick power fluctuations. Commenters sta ted it is essential the EPA recognize and account for necessary capacity margins when establi shing the re-dispatch target. Commenters suggested the various balancing authorities should identify the level of flexible capacity they require, and their future capacity needs. Commenter s noted that a variety of balancing authorities, such as Independent System Operators ( ISOs) and Regional Transmission Organizations (RTOs) have evaluated necessary capac ity margins and identified the need for increased flexible generating assets. Commenters st ated the CAISO net load chart highlights the future importance of flexible generation requiremen ts in response to increased renewable generation.

Emissions impacted re-dispatch.

Commenters stated that, even in California, where B uilding Block 2 plays a minor role in setting the state's goal, there are some specific constrain ts that may impact the performance of NGCC units. Commenters stated that, while California is working towards meeting the most aggressive renewable portfolio standard in the country, the si gnificant amount of additional intermittent renewable generation that the California Utilities are procuring could require NGCCs to cycle more often, and may affect their output and related emissions.

Commenters indicated that because NGCCs are used to support RE, they are operated at lower capacity and are subject to frequent cycling and st artups, resulting in variable emissions.
Commenters indicated that such units will not resul t in as much emission reduction as the EPA projects in BB2.

Commenters stated that, if NGCC plants become inter mediate load resources, the load-following and cycling role will likely be taken up by a combi nation of less efficient coal units operating at reduced loads and/or simple cycle peaking units ope rating at increased capacity factors.163

Commenters stated the use of coal units in this cap acity at low loads will practically eliminate any heat rate improvements made at those units beca use heat rate degrades at lower loads and with cyclical operations. Commenters stated that si mple cycle peaking units, many of which are permitted as minor sources, may not be able to incr ease their operations to meet demand because of permit limitations.

Commenters stated that many of these plants were bu ilt for flexibility of generation sources within a region and, if they are instead base-loade d, the change would deprive the region of the very flexibility for which the units were built. Co mmenters stated that taking away that flexibility could force the cycling of less flexibl e plants, at great cost to their reliability and at significant financial cost to the region, and could force the curtailment of emission-free variable generation because of the lack of available flexibl e firming resources. Commenters suggested that EPA recognize that utilities and regions rely on a diverse portfolio of generation resources to provide different services to the grid and that req uiring all NGCC plants to operate at 70% of capacity puts that critical diversity in substantia l peril. Commenters stated this demonstrates the impracticability and downright hazard of trying to define the best system for operating a complex integrated portfolio of resources for the sole purp ose of regulating a single pollutant while ignoring the broad range of other economic, policy, environmental and technical factors that have gone into the design and operation of that sys tem to date.

Comment 30: Commenters stated that, by focusing its achievabili ty analysis for Building Block 2 on average annual capacity factors, the EPA faile d to adequately consider periods of peak

demand.

Response 30: The EPA disagrees that we did not consider peak dem and. The 111(d) final rule requires that states develop plans that establish e mission standards for affected EGUs. We are providing states with substantial flexibility as to how they structure those plans to achieve the 111(d) requirements. The flexibility includes, for example, the choice of approaches, trading, time to develop plans, additional time before the s tart of the interim performance period (postponed from 2020 until 2022), and the ability t o shift emission rate achievement between performance periods. The Building Blocks are not pr escriptive, and states may consider local circumstances as they develop their plans, includin g system reliability, fuel diversity, the need for load following, system balancing, other regulat ory requirements and infrastructure. The 111(d) final rule does not require every individual NGCC to meet a CO2 emission performance rate, but rather the 75 percent capacity factor was used in the calculations to establish a rate. See sections V.D, VIII.A, VIII.C and VIII.G of the fina l rule preamble of the CPP and Chapter 3 of the GHG Mitigation Measures TSD for the CPP Final R ule supporting the final CPP. GHG Mitigation Measures TSD for the CPP.

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

Some commenters stated that this is further complic ated by states in which there are significant amounts of merchant gas generation. Some commenters provided state-specific comments.164

Peak demand leaves no available NGCC generation.

Commenters indicated that in meeting peak demand, m any states have all their existing NGCC resources in use, along with all other resources, l eaving no available NGCC generation available to replace existing coal and oil and gas (O/G) stea m generation during these periods.

Commenters asserted that, if EPA ramps the capacity up to 70 percent for their natural gascombined cycle plants, their plants would not be av ailable to serve as backup for intermittent renewable resources that do not generate electricit y when the sun is not shining or the wind is not blowing.

Commenters stated the EPA's re-dispatching approach removes approximately 3,800 megawatts (MW) of coal and OG steam generating capacity from Arizona's power system, all of which is currently used to meet peak demand. Commenters stat ed the mandates for Arizona are burdensome, compliance is likely impossible, and th e natural gas capacity in the state is not sufficient to provide air conditioning in the summe r months.

Commenters stated that continued displacement of co al and nuclear baseload resources by historically peaking units, such as NGCC, will resu lt in a shortage of capacity during peak periods, threatening future reliability.

Units with interruptible contracts may not support increased operation.

Commenters stated many units operate with interrupt ible contracts for gas supply that may not support increased operation during peak demand peri ods, particularly in the winter when units compete with home heating for available supplies of natural gas.

Commenters stated that interruptible service would not provide the assurance that sufficient natural gas would reliably be available on a contin uous basis to meet the proposed NGCC generation levels, particularly in peak periods. Co mmenters stated that the availability of firm transportation capacity requires not only adequate natural gas supplies, but also adequately sized pipeline facilities to deliver the increased amount s of natural gas needed to supply increased NGCC generation at the points of use. Commenters st ated that, to provide balancing services, which adjusts any imbalances between gas delivered for a customer and what the customer actually uses, pipelines must have storage (or comp arable excess) capacity capability to allow for the necessary adjustments in a timely fashion. Comm enters stated that, currently many NGCC units, which primarily serve as peaking units, do n ot have firm transportation and balancing services, but rely instead upon interruptible natur al gas transportation service, which, as the name implies, can be interrupted under various scenarios . Commenters stated that, even if utilities attempt to obtain firm transportation and balancing services from pipelines, neither service would necessarily be readily available as the capac ity on many pipelines is already fully
subscribed. Commenters stated a switch from interru ptible to firm service would also increase a utility's costs because rates for firm service incl ude a reservation charge that is fixed regardless of usage along with a usage charge for gas actually transported, while the rate for interruptible service is a volumetric charge tied to usage. Comme nters stated it is unlikely that a utility would recover amounts paid for reservation charges in the organized RTO energy markets.

Need to consider peak loads when calculating the go als.165

Commenters argued that, if EPA insists on including NGCC re-dispatch in Minnesota's CPP target, EPA must consider the measures and costs th at would be incurred to replace the intermittent renewable resource reliability, peak p ower generation resource service electric and natural gas transmission support that the NGCC unit s currently provide in addition to what EPA has recognized will be needed to bolster infrastruc ture to support EPA's 70% target set for existing NGCC units, annual capacity factor. Commen ters reported that early action taken by Minnesota regulatory authorities through their inte grated resource planning (IRP) process already optimizes generation resources to serve Min nesota electricity customers, giving balanced consideration to customer need, economics over the long term, fuel supplies costs and risks, socioeconomic impacts and managing risks and enviro nmental stewardship, including CO2
emission environmental externalities. Commenters as serted that Minnesota's energy mix of dispatchable capacity from Minnesota's existing coa l and NGCC units is necessary to preserve grid integrity and customer service reliability and that Minnesota's IRP measures better serve
EPA's intent of its CPP than EPA's one-size-fits al l" Building Block 2 target, but artificial, dispatch level for existing NGCC.

Commenters stated the EPA needs to verify that the actual NGCC capacity used in the goal calculations is sufficient for when peak loads occu r.

Commenters indicated that the EPA's analysis focuse d on compliance with an annual limit, and not on maintaining reliability during "peak hours" when it is most critical to maintain natural gas supplies and the electric transmission system.

Commenters stated that many gas units in Texas are designed to operate during times of peak load, given the large presence of nuclear, renewabl e, and coal-fired base-load generation that currently exists in the state. Commenters stated th is is one of the reasons that the average capacity factor for NGCC units in the state is in t he 40-50% range. Commenters stated these units were not contemplated to be operated as base- load units exceeding a 70% capacity factor, and there is no evidence that these units can perfo rm at this level consistently and over the long time periods envisioned by EPA.

Need to consider extreme weather.

Commenters stated that, to the extent that displaci ng coal-fired units with NGCC units causes the former to adopt a reduced or nonexistent operating profile, Building Block 2 could leave utilities without the tools to respond to extreme weather con ditions in the future. Commenters stated that extreme weather often causes significant increases in electricity demand at the same time natural gas supplies face unanticipated constraints and not ed that, during the early 2014 cold spell known as the "polar vortex," the vast majority of c oal-fired EGUs that were slated for retirement because of EPA's MATS Rule were operating at full c apacity to provide critical electricity supplies to residential customers.

Commenters stated that future cold weather periods will likely have a greater potential for curtailment on pipeline systems, as NGCC generation replaces coal-fired generation that was available in 2014, but is subsequently retired or r educed to comply with CO2 and other EPA
emissions limits.166

Commenters referenced a NERC report and stated that , if NGCC units increase their capacity factors to 70 percent, electric reliability on a lo cal or regional basis could be compromised. Commenters stated NGCC units provide an important b alancing function that allows utilities to incorporate large amounts of variable renewable res ources; unless utilities and system managers reserve a sufficient amount of spare NGCC capacity, it could be difficult to keep the grid operating during periods of high electric demand an d low RE production. Commenters referenced a NERC report and stated that, if NGCC u tilization were to increase to the levels that the EPA assumes, the system could become even more vulnerable to periodic blackouts or curtailments during high-demand, low-variable-suppl y scenarios. Commenters referenced another NERC report and stated that, increased reli ance on natural gas could lead to periodic weather- or natural disaster-related reliability is sues similar to the prolonged shutdown of natural gas facilities in the East, Midwest, and Southwest during severe cold snaps in previous winters.

Averaging flexibility is inadequate to account for peak demand.

Commenters stated the EPA should consider alternati ve calculation methods that account for peak demand. Commenters cited the GHG Abatement Mea sures TSD at 3-15 and stated it is unclear how EPA thinks averaging flexibility could overcome the constraints imposed by peak demand, unless the agency believes that coal and NG CC generation could switch roles, with NGCC providing base load and coal operating only wh en needed to satisfy peak load. Commenters referenced a NERC report and stated tha t operating coal generation to serve peak demand is not technically feasible. Commenters stat ed that, if that scenario were feasible, then the ability to average coal emissions over a year c ould provide partial assistance in meeting the BB2 goal, although it would not enable Arizona or t he 11 other states where BB2 results in zero coal generation after re-dispatch, to meet the BB2 goal; those states would still need to offset the reductions assumed from the application of BB2 with reductions from other building blocks or
from non-BSER measures. Commenters stated that it i s untrue that peak demand will constrain only a limited percentage of the state-wide NGCC fl eet. Commenters referred to Appendix 3 of their comments and stated that, in the absence of c oal generation, existing NGCC generation in Arizona will be substantially inadequate to meet pe ak demand in Arizona during the summer months, even if operating at nearly 100 percent cap acity. Commenters stated that the annual average capacity factor for the state's NGCC fleet does not provide an adequate picture of the potential for re-dispatch.

Merchant gas

Commenters stated that this is further complicated by states in which there are significant amounts of merchant gas generation, which are used to meet peak demand not only in their home states, but also in neighboring states and stated t hat it is inaccurate for the EPA to assume that all merchant generating capacity will be available to d isplace coal-fired generation from within a particular state. Commenters concluded that utiliti es cannot rely on merchant generation to meet long-term demand requirements during peak summer mo nths in lieu of generation from existing
coal-fired units.

Commenters stated the EPA application of Building B lock 2 fails to consider existing commercial arrangements for merchant NGCC capacity and assumes the capacity can be used by load serving utilities within Arizona to displace t hose utilities' coal fired generation even though167

those utilities do not own or have any long-term ri ghts to the capacity and energy from the
merchant NGCC units. Commenters stated the EPA fail s to recognize that while large amounts of merchant owned generation are located in Arizona , much of the NGCC generation is delivered to California. Commenters stated that, in Arizona, this represents approximately 50 percent of the NGCC capacity in 2012 that the EPA assumed woul d be available for use by Arizona utilities to serve load within the state (2012 EIA 860 data).

Commenters stated the EPA should remove any merchan t NGCC units from Building Block 2 in the calculation of the state goal. Commenters state d that merchant NGCC units create several problematic issues for the State to resolve in deve loping its implementation plan: Should the merchant unit be allocated a carbon intensity above its 2012 baseline? How would that be determined? Can the merchant unit achieve a 70% cap acity given the gas pipeline constraints?
Where should the offsets occur? Can the merchant un it owner offset with its coal-fired assets, if any, in other states? Should other in-state utiliti es be forced to purchase the merchant unit NGCC generation at a potential premium cost compared to its owned and potentially lower cost assets that would have to be idled? How should the utility commission treat the utility-owned assets that would be stranded by the offset?

Commenters explained that, while NGCC units owned b y utilities in South Carolina actually operated at 64% during the year and a merchant unit in Gaffney operated at 82%, a large merchant unit in Gaston known as Calpine or Columbi a Energy operated at less than 1% during 2012 due to a lack of demand for its electric outpu t. Commenters stated Building Block 2 of the proposal would have this merchant NGCC unit be run at 70% capacity with a resulting offset in coal-fired generation. Commenters stated that, sinc e the merchant unit owner does not have coalfired generation in its South Carolina portfolio, t here is no opportunity for the owner to offset its generation within the State in the manner contempla ted by EPA.

Commenters stated that it is not valid to assume th at merchant capacity is available under a 111(d) program for re-dispatch to solely serve Ariz ona load. Commenters stated that more than 5,000 MW (53%) of the existing NGCC capacity in Ari zona is owned by independent power producers, and not by the load-serving utilities in the state. Commenters stated that, while Arizona's load serving entities currently purchase some of the energy from these generators under long- and short-term purchase agreements, the re is no ability by the load serving entities, the state, or EPA to force merchant generators to c ontinue these sales in the future. Commenters stated that a neighboring state could purchase the output of the merchant Arizona NGCC units at any time and reduce capacity available for Arizona re-dispatch. Commenters stated SRP and other Arizona utilities will need to compete for na tural gas supply for NGCC generation with shippers from California, New Mexico, and Texas. Co mmenters stated that recent increases in exports to Mexico raise additional concerns as to t he feasibility of securing adequate natural gas supply in the near term.

Commenters stated that, given the uncertainty in av ailability of merchant resources to serve Arizona load, utilities will need to construct new NGCC plants to ensure adequate system reliability during peak demand periods if existing coal and OG steam must be curtailed or retired under the 111(d) program. Commenters stated that ne w infrastructure will be needed to operate existing NGCC at the higher capacity factors assume d by EPA. Commenters stated that the two pipelines that provide service to SRP's gas plants have limited excess capacity available and are168

nearly fully subscribed in the winter months. Comme nters stated that, if SRP were to operate its existing NGCC at a 70% capacity factor in the winte r months, SRP would need an additional 160,000 decatherms (dth) per day of natural gas fro m the pipeline system. Commenters stated that existing winter capacity available for contrac ting currently ranges between 0 to 50,000 dth per day, far less than required by SRP.

State-specific comments

Nevada

Commenters stated that, in assuming 70% capacity fa ctor, the EPA failed to take into consideration actual capacity factors for affected EGUs as they are currently operating, as well as location, infrastructure availability, reserve marg in requirements, and other factors adding complexity to the analysis. Commenters stated the N evada Agencies evaluated the existing natural gas-fired EGUs capacity factors and existin g infrastructure, and concluded that redispatching even 50% (the amount the USEPA determin ed would be necessary to take Nevada's coal-fired facilities offline) would be a significa nt challenge. Commenters stated that, even assuming that the EGUs could operate at a 100% capa city factor, the existing natural gas-fired combined cycle EGUs in northern Nevada are already operating at peak for 494 hours in the
summer and autumn months and would not be available to displace existing coal-fired EGUs. Commenters stated that, if we were to assume that e xisting NGCC EGUs could operate at a 70% capacity factor, the number of hours where re-dispa tch could not be met rises to 2,300 hours, or more than 26% of the time. Commenters stated that, while the EPA's analysis assumes there is excess capacity throughout the year, it is not avai lable throughout the year.

Commenters stated that, while NV Energy maintains a number of gas fired combined cycle turbines and boilers which play a critical role in meeting a portion of Nevada's season-specific peak, not all of these units are designed for re-di spatch to a 70% annual capacity factor. Commenters stated the older gas fired units are mai ntained and used solely for peaking and short term reliability needs because they typically have a higher heat rate, perform at lower efficiencies, and are higher in cost, when compared to a modern combined cycle plant.

Commenters stated that the Nevada Agencies express concern about "a large re-dispatch from coal to natural gas," and asserted that this is an issue which is unlikely to materialize given the multiple strategies available to Nevada to comply w ith the Rule. Commenters stated that their internal analysis, which was shared with the Agenc ies, suggests that a modest re-dispatch may be needed in the early years to comply with the int erim goal but that would largely be overtaken by growth in energy efficiency and renewable energy over time. Commenters stated that, as a result, the need for major new pipelines and other infrastructure would be unlikely, counterintuitive since we are transitioning to high er levels of renewables, and a bad investment in the long run.

Commenters stated that most gas-fueled generation i n Nevada is already fully subscribed during times of peak demand. Commenters stated that, while EPA's assessment that natural gas usage is increasing and NGCC units have achieved capacity fa ctors between 50% and 80% during winter and summer seasons may be valid, it does not necess arily take into consideration the ability of those units to run at such a level at an annual cap acity factor, nor does the assessment address the169

availability of natural gas in all seasons or locat ions. Commenters stated the capacity factor of NV Energy's NGCC fleet exceeds 70% during the summe r peak in combination with a coal fleet capacity exceeding 55% over that same time period. Commenters stated that, in summer of 2012, NV Energy's generating resources included over 1,00 0 MW of coal capacity and over 3,700 MW of natural gas combined cycle capacity. Commenters stated that, in order to shift the power generated by the coal fleet to the NGCC fleet durin g peak season, the NGCC fleet would need to operate near an average 90% net capacity factor for at least an entire month and, this clearly indicates that there are hours of the day that the NGCC fleet would be forced to run at 100%, which is not a viable operating scenario due to the need to maintain compliance with Federal Energy Regulatory Commission (FERC) reliability sta ndards. Commenters stated this level of operation during a summer season that already exper iences frequent "do not touch" reliability mandates is not appropriate or sustainable. Comment ers stated it is not reasonable to assume a complete displacement of the baseload coal which me ets the first increment of demand on a year round basis, including the doubled summer peak load

.

New Hampshire

Commenters stated that natural gas combined cycle p lants in New Hampshire have been unable to perform to expectations during peak heating dema nd periods in recent winters. Commenters stated that, while natural gas generation peaked in the month of July at roughly 70 percent capacity, during the January 2013 cold snap natural gas use for heating purposes interfered with the natural gas supply available to EGU's for power generation and the monthly capacity factor was only about 35 percent. Commenters stated this s equence of events consistently repeats itself in winter months and demonstrated that, while NGCC generation can periodically reach 70 percent of its nameplate capacity in New Hampshire, it is not sustainable over the course of an entire year, especially during the winter months wh en EGU's are competing for natural gas supply with other customers that have contracts for heating purposes.

Arizona

Commenters expressed concerns regarding the impact of the CPP in Arizona.

Commenters expressed concern that the proposed re-d ispatch to Maricopa County NGCCs may consume peaking capacity that is currently necessar y to meet summertime demand as well as consume electric system growth capacity more rapidl y that infrastructure planning can meet.

Commenters noted that the EPA suggested that the st ate's utilities could just operate coal-fired generation during peak demand periods, but stated t his is not a viable option. Commenters indicated that the coal-fired power plants in Arizo na are large, complex units not designed and engineered to sit idle for extended periods of time and cycle. Comment stated that such practices would challenge reliable operation of the units and the staffing and maintenance to support such a scenario would not be economically justifiable. C ommenters suggested that when calculating Arizona's emission goal, portions of coal and gas s team cannot be re-dispatched to NGCC and must be factored into the carbon rate goal. Comment ers stated that, for most years, the average summer demand is more than twice the average demand for the remainder of the year. Commenters provided Figure 1, which shows that on A ugust 7th, hour 16, 2012, Arizona NGCCs were generating 8,455 MW (net) and the coal a nd gas steam units were generating 4,098170

MW (net). Commenters stated that, in order to re-di spatch all coal and gas steam with NGCC generation as assumed by the EPA, the NGCCs would h ave to be operating at 12,553 MW (8,455 MW + 4,098 MW); however, the maximum capacit y assuming all units are fully available, however, is only 9,305 MW. Commenters pr ovided Figure 2, which shows the results of this analysis for the month of August (744 hours ) and also shows the maximum possible generation of the NGCCs during the summer months (1 00% capacity factor). Commenters stated that nearly half of the time during August 2012 the demand that would normally be provided by coal and gas steam-fired generation exceeds the cap acity of all NGCC in Arizona. Commenters stated the same phenomenon occurs during the months of May through October and, as a result, if all coal units were retired as modeled by the EP A, Arizona could face serious reliability issues in a significant number of hours throughout the yea r. Commenters also provided Table 2, which shows that nearly 800 hours throughout the year 201 2 could not meet the NGCC re-dispatch requirement envisioned by the EPA.

Commenters expressed concern that the EPA's assumpt ions regarding application of Building Block 2 within Arizona do not recognize the need to meet peak demand, and do not recognize the constraints inherent in making such a wholesale shift in the state's current energy infrastructure. Commenters stated that, given the E PA's calculated capacity factor for the NGCC fleet in Arizona of 53%, NGCC generation would enti rely displace coal and OG steam generation. Commenters objected to what they descri be as the EPA's assumption (at least with regard to Arizona goals) that reductions related to Building Block 2 are easy to achieve and a company would, in effect, flip a switch in 2020 tha t turns off its coal units and turns on its gas
units.

Commenters stated the EPA's application of Building Block 2 to establish Arizona's emissions rate goals suggests the agency does not recognize a utility's obligation to meet peak demand.
Commenters stated that utilities must ensure that s ufficient resources are available to meet peak demand, not just annual average demand. Commenters stated that Arizona cannot solely rely on existing NGCC capacity to meet peak demand because those facilities are already being fully utilized in certain hours of the year to serve regi onal loads. Commenters stated that, currently, coal and OG steam plants provide vital capacity dur ing summer months that ensures system reliability during periods of peak demand. Commente rs stated the EPA's calculation does not account for the much higher demand for electricity in Arizona in the summer than in the winter.
Commenters stated that an NGCC resource could easil y run at a 90% capacity factor during the peak summer hours, but have an annual capacity fact or around 30%. Commenters provided Figure 7-3, 2012 SRP Retail Firm Load Profile, and stated the peak electricity demand can be more than twice as high as base demand in the off-p eak months. Commenters added that, while forecasted values trend well with actual values, ut ilities still cannot predict exactly when the highest peak will occur and how high that peak will be. Commenters provided three figures to
illustrate their concern.

• Commenters provided Figure 7-4, Resources Needed by SRP to Meet Peak Demand on August 8, 2012, and stated that, during t his hour, all available generation resources, including coal and OG steam p lants, were being utilized at full capacity to meet that peak demand. Commenters added that, even with all SRP system resources being utilized at full capacit y, SRP still had to purchase electricity on the open market to meet peak demand and Federally-required171 reserve requirements. Commenters stated it is clear that without coal and OG steam resources, SRP would not have been able to me et the peak electricity demand without purchasing a significant amount of e lectricity from the short-term market in addition to what is already being purchas ed, which is a costly and risky endeavor, assuming that such power is even availabl e.

• Commenters stated that, while Figure 7-4 shows a si ngle peak hour, Figure 7-5, Potential Re-dispatch of SRP Generation Resources, provides an annual look at how SRP's generation resources would fall short if SRP were required to replace all existing coal and OG steam generation with NGCC generation. Commenters stated that, even assuming a 100% NGCC capacity fac tor on an hourly basis, which equates to 84% on an annual average basis, Fi gure 7-5 demonstrates SRP still would experience significant shortages in gen eration for several months in the summer. Commenters noted this lack of generatio n would be further aggravated if out-of-state coal resources also are eliminated due to compliance with the Proposed Rule.

• Commenters provided Figure 7-6, Merchant NGCC Plant Utilization in Arizona, and stated that the merchant plants in Arizona ofte n already operate at full or nearly full output during summer peak months to mee t demand, even with the existing coal-fired generation in operation. Commen ters concluded that the Arizona utilities cannot rely on merchant generatio n in long-term planning to meet system demand requirements during peak summer demand periods. Commenters added that regional peak demands have be en increasing and are projected to continue to increase.

Commenters stated that, while the EPA seems to sugg est that a utility whose coal-fired generation capacity is displaced by Building Block 2 could simply buy replacement power from other generating sources (79 FR 34887), at least in Arizona it does not appear that this would be possible. Commenters stated the projected depth and liquidity of the energy market in the southwestern United States is probably not sufficie nt to implement Building Block 2, nor is
sufficient transmission infrastructure available to move the energy to where it is needed from the NGCC units that suddenly find themselves supplying power to meet far-away demand that was formerly served by coal-fired EGUs. Commenters stat ed that, to the extent that NGCC capacity is not already accounted for by out-of-state demand , the Arizona-based utilities with ownership or rights in these units will likely use their righ ts to that unused NGCC capacity in order to replace their own displaced coal-fired generation-m aking replacement generation exceedingly difficult to find for an entity like Tri-State, whi ch has no other generating resources in the area of Springerville. Commenters stated that, in any event , the transmission system in Arizona and surrounding areas likely could not accommodate the large deliveries to Tri-State at the Springerville bus that would be necessary to replac e the loss of Springerville Unit 3.

Commenters provided the following analysis by the S alt River Project (SRP) as an example which, according to the commenters, illustrates the various faults in EPA's methodology for Building Block 2.172 • On August 8, 2012, SRP reached a peak hourly load o f 6,663 MW, in which all of its generation resources (including coal and O/G st eam units) were being utilized at full capacity. Even then, SRP was forced to purc hase power to meet its peak demand and its mandated reserve requirement. With c oal and O/G steam units prohibited from operating for purposes of meeting t he state's CO2 emission goal, as EPA's Interim and Final Goals for Arizona requir e, SRP would have been unable to meet its peak electricity demand without purchasing very substantial additional amounts of electricity on the short-term market. Even if such electricity were available on the market, it would have been ex traordinarily costly. The EPA failed to include such costs in its Regulatory Impa ct Analysis. This highlights another important factor that EPA failed to conside r: the 5,000 MW of merchant
NGCC located in Arizona. The state's various load s erving entities purchase electricity from merchant generators on either long - or short-term agreements, but
have no control over how the merchant units are dis patched. SRP found that all merchant plants in Arizona operate at or nearly at full output during the peak months not only to meet the demand in Arizona, but also in neighboring states such as California, Nevada, and New Mexico. Consequ ently, Arizona utilities cannot rely on merchant generation to meet long-ter m demand requirements during peak summer months, and both coal and O/G st eam capacity provide a
vital resource to meet demand and ensure reliabilit y. SRP also points out several factors that can complicate the construction of add itional NGCC capacity: (1) lengthy timelines in siting and permitting new ener gy infrastructure, which can take up to 10 years or more if it is on the 48% of Arizona that is federal lands; (2) the regulatory complexities of siting a new energy facility in non-attainment areas, which would require emission offsets; and (3 ) recent modeling has indicated that if all existing Arizona coal capacit y is retired in 2020 it would affect both the reliability and load serving capabi lity of the state's transmission
system.

Comment 31: Commenters suggested that duct burner firing should not be considered in assessment of NGCC capacity.

Response 31: The EPA disagrees. Duct burners are a component of NGCC capacity and is

included in the calculations. The EPA has modified the definition of capacity in the calculations from nameplate capacity to net capability and belie ves that measure should better capture the units’ ability to produce power on a sustainable ba sis. See sections V.D, VIII.A, VIII.C and VIII.G of the final rule preamble of the CPP and Ch apter 3 of the GHG Mitigation Measures TSD for the CPP Final Rule supporting the final CPP

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

Commenters did not agree that the CO2 emission rate of the re-dispatched NGCC units will be equal to their 2012 emission rate due to duct firin g. Commenters noted that all Wisconsin NGCC units have duct-fired peaking capacity that general ly comprises at least 10-20 percent of the total capacity of the units. Commenters stated the duct-f ired capacity has a significantly higher173

incremental heat rate and emission rate than the un fired capacity, so the duct-fired capacity has historically been operated fairly infrequently. Com menters stated that, in order to achieve a capacity factor of 70 percent, additional duct firi ng will likely be required at some units. Commenters recommended that, when determining the a ppropriate emission rate to use for redispatched NGCCs in calculating state goals, EPA co nsider the fact that re-dispatched NGCCs operating under the assumptions in Building Block 2 will likely operate with increased duct firing - thus at a higher emission rate - than they did in 2012.

Commenters stated that duct burner firing should no t be considered in assessment of NGCC capacity within the context of displacing coal gene ration on an annual basis. Commenters explained that duct burner power augmentation mode from a design standpoint is intended to be temporary - the heat added does elevate power throu ghput, but the point of heat addition in the thermodynamic cycle does not derive maximum thermal efficacy. Commenters indicated that continual duty with duct burner firing is therefore rare and may not be economic. Commenters
added that the use of duct burners can induce therm al stress in a unit's heat recovery steam generator (HRSG) and this accelerated component wea r is incurred only in exchange for premium power prices. Consequently, Commenters beli eved that duct burners should be considered temporary operating modes and the increm ental power derived should not be considered in any discussion of either gross or net capacity that can displace coal on an annual basis. Commenters stated that the additional power output and compromise in heat rate induced by duct burner firing can be significant, and gave the example of Oglethorpe Power's Thomas. A. Smith facility which has approximately 240 MW of du ct burner capacity that is included in Georgia's NGCC capacity used by the EPA in the Buil ding Block 2 calculation. Commenters indicated that the generating capacity for this one facility was therefore overstated by over 20% by including the duct burner capacity, and that the heat rate for these duct burners is approximately 2,000 Btu/kWh higher than the net hea t rate for this facility operating at steady state conditions. According to the commenters, the desire by an owner to retain duct burner augmentation as a temporary mode is due to both a c ompromise in heat rate and the deferred cost
of induced thermal stresses to the HRSG.

Commenters stated that, while NGCCs are equipped wi th duct-firing to achieve the necessary heat input for high capacity utilization, typically , NGCCs are not operated at these higher levels because the duct-firing is less efficient than norm al operation and it increases NOx emissions, which is particularly important in meeting NOx emis sion limitations in non-attainment areas. Commenters suggested that some potential ways that may help address this issue are either restricting the use of NGCC capacity below levels t riggering duct-firing or accounting for these impacts by setting less stringent targets.

Commenters stated the EPA could also consider simpl y excluding NGCC units located in nonattainment areas or, alternately, assuming addition al costs for installing NOx control equipment.

Commenters stated that duct burners and the increme ntal power derived should not be considered in any discussion of the use of either n ameplate or summer net generation to displace annual coal generation. Commenters stated that, sin ce 2002, most new state-of-the-art NGCC units were constructed with duct burners for power augmentation. Commenters stated that duct burner usage can induce thermal stress in the heat recovery steam generator (HRSG); typically, this accelerated component wear is incurred only in exchange for premium power prices.174

Commenters stated the additional power output but c ompromised heat rate induced by duct burner firing can be significant; e.g., by includin g the duct burner capacity, the generating capacity for one facility was overstated by more th an 20%. Commenters stated the heat rate for these duct burners is approximately 2,000 Btu/kWh h igher than the net heat rate for the TASF when operating without duct burner firing. Commente rs stated that duct burners have different operating characteristics than a NGCC and should no t be considered in assessing the ability of existing NGCC capacity to displace coal generation.

Commenters stated the EPA did not distinguish betwe en size of NGCC, industrial frame designs vs. aero-derivatives, or those facilities with supp lemental duct firing for heat recovery steam generators. Commenters stated that duct burners can make a significant impact on nameplate capacity (with which EPA heavily relies in determin ing re-dispatching), yet if not used in 2012, the impacts on poorer heat rate would not be captur ed in the emissions data. Commenters stated this is especially true for situations similar to w hat exists at Arvah B Hopkins. Commenters stated that, when the station repowered, the City u tilized the existing steam turbine; the steam turbine's generating capacity is greater than 50% o f the combined cycle unit's total capacity, and, the steam turbine generator can no longer reach the 259.2 MW capacity listed in eGRID and utilized by EPA (current capacity is 140 MW). Comme nters stated that, in order to reach a 70% capacity factor for the combined cycle unit's total generating capacity a significant amount of duct firing would be needed. Commenters stated the EPA must consider the impact of requiring duct burning to reach a 70% capacity factor for sta te goals and adjust the required CO2 emissions rate or the nameplate capacity accordingl y.

Comment 32: Commenters stated the EPA fails to consider a speci fic category of natural gas electric generating facility “regulating units.”

Response 32: The EPA disagrees. The EPA has not ignored the role of simple cycle CT units in contributing to regulation. Many different types o f units contribute to regulation. These units are not precluded from contributing system regulati on under the rule. However, they are not affected units, so they are not directly subject to this rule. See sections V.D, VIII.A, VIII.C and VIII.G of the final rule preamble of the CPP.

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

Commenters stated regulating plants, like many peak electric generating facilities, typically use rapid start and high ramp rate simple cycle combust ion turbines. Commenters stated that, unlike a peaking unit, a regulating unit must be able to s tart and change load quickly because of variations in non-dispatchable renewal energy gener ated in moderate-sized electrical balancing authority areas. Commenters stated that, because la rge-scale wind generation is nondispatchable, it is very difficult for a regulating unit to predict when it may need to operate to balance drops in wind generation. In response to th is variability, Commenters stated a regulating unit may be required to operate in hot standby, rea dy to respond in minutes to a drastic drop in renewable generation. Commenters stated the heat ra te achieved while operating a combustion turbine in hot standby results in a disproportionat ely large output efficiency-based emission rate of CO2. Commenters stated that NorthWestern Energy' s Dave Gates Generating Station, a state-175

of-the-art regulating facility in Montana construct ed in 2011, recently disclosed that it would not meet the currently proposed efficiency-based emissi on rate of 1,100 lb CO2/MW-hr. Commenters stated a utility is legally bound by the North American Electric Reliability Corporation (NERC) to balance generation with deman d at all times; therefore, a regulating unit may operate at a higher capacity factor than a typi cal peaking unit. Commenters expressed concern that the EPA's proposed 33 percent capacity factor to exclude peaking units from the NSPS may not be sufficient to also exclude regulati ng units. Commenters stated that even the 40 percent capacity factor considered in the NSPS may not provide the flexibility for a regulating unit to fulfill its legally defined mission. Commen ters stated the proposed rule as written ignores this type of facility and may prevent future regula ting units from being constructed, directly in opposition to the Obama Administration's Blueprint for a Secure Energy Future and to many
states' Renewable Portfolio Standards.

Comment 33: Commenters did not agree with the Proposal's treatm ent of CHP and/or retiring

NGCC units.

Response 33: The 111(d) final rule does not include all CHP unit s in the goal calculation. CHP units are included where these are primarily involv ed in delivery of generation to the bulk power grid because EPA has concluded that that component of their power can have its capacity factor shifted along with other generating units. The fin al rule has been changed from the proposal to use net capacity rather than nameplate, which will correspond more closely to the ability of these units to supply power. Also, the final rule does n ot include useful thermal output in the goal calculation but does permit it to be used for compl iance. See sections V.D, VIII.A, VIII.C and VIII.G of the final rule preamble of the CPP and Ch apter 3 of the GHG Mitigation Measures TSD for the CPP Final Rule supporting the final CPP

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

CHP may not be dispatchable.

Commenters requested that the EPA ensure that the E mission Guideline does not inadvertently reduce the use of CHP by exempting facilities that utilize efficient CHP from being affected EGUs. The commenters explained that EPA presumes a state can and should re-dispatch from steam generating units (including those using CHP) to existing natural gas combined cycle facilities, even if those facilities do not use CHP . However, according to the commenters CHP is often installed for the host's industrial process a nd is not a dispatchable resource like an EGU.
The commenters asserted that reduction of electric output at an affective EGU with CHP will more likely result in fossil fuel combustion at bot h the facility and at the NGCC facility, and
therefore increase emissions overall. In conclusion , the commenters requested that Building Block 2 not assume re-dispatch from CHP to NGCC and that EPA not consider efficient CHP facilities affected EGUs to begin with.

Commenters stated the EPA improperly included combi ned heat and power (CHP) units in its Building Block 2 goal calculation, mistakenly assum ing that CHP units can re-dispatch to higher capacity factors in the same manner that non-CHP NG CC units can. Commenters stated this is in176

error, as CHP dispatch largely depends on the needs of adjacent facilities, not the needs of the grid. Commenters stated EPA's assumption that CHP u nits can re-dispatch to 70 percent is unreasonable, and CHP units should not be included in Florida's goal calculation. Commenters suggested the EPA recalculate Florida's goal exclud ing all CHP units from the calculation. If, however, EPA chooses to include CHP units in Florid a's goal calculation, commenters stated it must do so according to the same applicability crit eria that EPA establishes under the proposed new source rule, which provides different applicabi lity criteria that the existing-source proposals
for CHP units.

Commenters stated that the EPA inappropriately incl udes non-dispatchable combined heat and power (CHP) units in its calculation of the potenti al for re-dispatch. According to the commenters, these resources should not be included, as the grid operator cannot direct their operations to meet demand. Commenters stated that t he EPA included in its analysis industrial non-dispatchable CHP plants which, in 2012, account ed for almost a third of the NGCCs over 25 MW and approximately 15 percent of the total electr ic generation analyzed by EPA. (Commenters noted that unless these units sell more than one-third of their potential output to the grid, they are not affected units, making their inc lusion in EPA's analysis particularly inappropriate.) Commenters stated their operation i s completely different from that of a power plant exclusively dedicated to serving load and the needs of the grid in the following ways: CHP plants tend to have much higher capacity factors th an EGUs, their electric output is directly related to their on-site industrial activity and he at (or steam) production, they do not respond to the demands of the grid and many CHP plants use muc h of the electricity they produce for their own needs and cannot be dispatched like power secto r plants. According to the commenters, more than half (34 out of 64) of the plants that EP A identifies as having utilization rates of 70 percent or more were, in fact, CHP plants (Id.). Co mmenters asserted that these CHP plants cannot be taken into account when assessing the pot ential for increased utilization of the existing NGCC fleet, and that their inclusion in EPA's goal computation methodology results in an overestimate of the potential for re-dispatch. Comm enters concluded that the re-dispatch portions of the state targets must be recalculated according ly.

CHP are not representative of NGCC capacity

.
Commenters stated that, while the EPA did not provi de the plant names of the 50 NGCCs that operated above a 70 percent capacity factor in 2012 , it appears CHP plants were included in EPA's 50 plant analysis. Commenters stated that, be cause CHP plants primarily generate based on the needs of adjacent customers, their operation s are not representative or indicative of typical NGCC capacity factors. Commenters stated that, thro ugh operating an integrated system, Southern Company is uniquely aware of the important role NGCCs play in maintaining reliability and suggest EPA reassess its dataset fo cusing only on non-CHP NGCCs and sustained
state-wide achievements.

Commenters requested the EPA correct the error of t he inclusion of combined heat and power (CHP) facilities in the CPP's analysis of existing NGCC capacity factors. Commenters stated existing CHP facilities have been specifically desi gned to operate in a symbiotic relationship with other partners; often either a municipality or industrial process. Commenters stated each CHP system is constructed to meet the needs of an i ndividual building or facility, and not to respond to the grid's electric demand as a primary driver. Commenters stated CHP system design177

is customized based on the location, size, and ener gy requirements of the site, which are often a fixed temperature, pressure and volume of steam. Co mmenters stated the steam demand is frequently constant, but not necessarily a high vol ume demand. Commenters stated variations in designed steam output could have significant impact on the receiving entity because the CHP unit is optimized for steam production per the cont ractual relationship. Commenters stated that NGCC units without CHP are optimized for their comb ined steam cycle to generate electricity. Commenters stated the decision to design and operat e a CHP facility indicates a fundamentally
different business model than that of a traditional NGCC unit supplying electricity to the centralized grid.

Redispatch of CHP may increase emissions.

Commenters stated the EPA has inappropriately assum ed that the re-dispatch of any coal, oil, or gas steam generating unit to existing NGCC will red uce the net emissions of the electric system. Commenters stated this assumption is not valid for those affected EGUs that are CHP units. Commenters stated that, unlike for typical utility EGUs, the dispatch for many CHP facilities that sell electricity to the utility distribution system is governed by the Public Utility Regulatory Policies Act of 1978; these CHP facilities are qual ifying facilities (QF), and utilities have a legal obligation to take power from QFs at specified rate s. Commenters stated that, because fuel combustion is generally needed to produce steam for industrial or other purposes at a constant, defined rate, incremental re-dispatch of particular CHP units is generally not possible; therefore, these facilities are not subject to typical dispatc h decision-making. Commenters stated that highly efficient steam CHP systems may have emissio n rates lower than NGCC units that are not part of CHP systems. Commenters referenced EPA's TS D materials and stated that, in New York, the 2012 emission rate for the Astoria Energy , non-CHP NGCC facility was 1634 lbs. CO2/MWh, whereas the Syracuse Energy coal-fired CHP unit had an emission rate of 1251 lbs. CO2/MWh.5 Commenters stated that re-dispatching fro m the steam generating CHP unit to the
non-CHP NGCC unit would result in an increase in Ne w York's electric sector emission rate, rather than a decrease. Commenters stated that, for many CHP facilities, a reduction in electric generation will not reduce the facility's emissions . Commenters stated this is particularly true for those units that primarily combust fossil fuel to p roduce useful steam-such as for industrial or district heating purposes. Commenters stated that, in such a case, reduction in electric generation
will result in the same or similar amounts of fossi l fuel combustion, and therefore CO2 emissions, to produce that useful steam; however, i nstead of using the steam to also generate electricity-with no or little net emissions-a separ ate NGCC facility will be required to burn additional gas to make up for the re-dispatched ele ctricity. Commenters stated this re-dispatch
will result in more fuel combustion and CO2 emissio ns than efficiently using the fossil fuel at the CHP unit for both electricity and steam.

Commenters stated the inappropriateness of EPA's go al calculation methodology is made clear by considering how the Clean Power Plan treats stea m generating CHP units when applying building block 2. Commenters stated that the EPA fi rst calculates a facility's electric output from EIA data; then the EPA calculates the emissions ass ociated with this electric output by assuming that those emissions constitute the same proportion of total emissions as the proportion of the unit's electric output to total output. That is, co mmenters stated, if a CHP facility had 20 percent electric output, its emissions associated with elec tric output is assumed to be 20 percent of the
unit's total emissions. Commenters stated this calc ulation is based on an incorrect assumption:178

there is no reason to believe that if a CHP unit de creased its electric generation, the unit's total emissions would decrease by the same proportion. Co mmenters stated that decreasing a unit's electric generation may not change the unit's emiss ions at all.

Need to adjust calculation to credit CHP.

Commenters suggested the EPA does not credit CHP pr operly in the proposal because, by dividing the CO2 emissions by the gigawatt hours ge nerated, there is no accommodation for the use of waste heat by CHP, which leads to an incorre ct lowering of the ratio used in the calculation. Commenters suggested there should be a n adjustment either by the addition of CO2
in the numerator or a reduction in the denominator to credit CHP. Commenters stated the use of CHP directly offsets CO2 from otherwise operating c ombustion sources and should be credited
in this rule.

Commenters urged the EPA to calculate Building Bloc k 2 as the re-dispatch from only non-CHP steam generating units to existing NGCC facilities. Commenters stated that, while the EPA reduces the electric generation and corresponding e missions of coal, oil, and gas steam generating CHP units and replaces that electric gen eration with existing NGCC generation as part of Building Block 2, EPA continues to include the useful thermal output and associated CO2 emissions for these same CHP units in state goals. Commenters stated that, in effect, for many units, EPA has reduced electric generation to zero- transforming these units from CHP units into units that supply only thermal output. Commenters s tated that, although the EPA continues to treat these units as affected EGUs, including emiss ions and output from these units in state goal calculations, the inclusion of these units' emissio ns and thermal output make little conceptual sense for a rule purporting to regulate EGUs and no t industrial boilers. Commenters stated the EPA should not suggest to states that promoting re- dispatch from efficient CHP to non-CHP NGCC power plants is good policy. The commenters co ntended that, in many cases such redispatch will result in wasted useful steam, excess ive fossil fuel combustion, increased emissions, and higher costs.

Commenters stated the improper use of net energy in stead of actual electric generation incorrectly reduced Michigan's baseline by almost 2 0% and must be corrected. Commenters stated that, for the CPP analysis of Michigan, EPA identified four CHP facilities; three of which are NGCC units. Commenters stated Michigan had 5,00 8 MWs of installed NGCC units in 2012, of which 2,593 MWs (or 52%) were associated with a CHP process. Commenters stated that, because the percentage of MWs that operate as a CHP unit is so high, the state's net energy output is substantially higher than the actual elec tric generation. Commenters stated that, had EPA remained consistent with the NSPS proposal and not quantified a useful thermal output adjustment, Michigan's NGCC emissions intensity wou ld be an estimated 998 lbs/MWh13; which given the accuracy of estimations should be 1 ,000 lbs/MWh (consistent with EPA's proposed standard for large, new NGCC units). Comme nters stated that, in Michigan, this inconsistency has significant effects. Commenters s tated that, when establishing the 2012 emissions inventory, EPA quantified the UTO from th e existing CHP facilities, and then proceeded to calculate a net energy output from all existing NGCC units; the EPA then calculated the state's NGCC emission rate by taking the reported carbon dioxide emissions, in tons, and dividing by the net energy output, expres sed in MWhs. Commenters stated this resulted in an incorrectly proposed NGCC emissions rate of 8 10 lbs/MWh18 rather than a realistic and179

accurate standard of 1,000 lbs/MWh equivalent to ne w NGCC units. Commenters requested the EPA assume all existing NGCC units have a standard of 1,000 lbs of CO2 per MWh, the same emission intensity ratings as new units would have under the new unit proposal. Commenters estimated that this revision would add 59 lbs CO2 p er MWh to the proposed Michigan standard.

Commenters stated that, because EPA is proposing a regulatory scheme addressing GHG emissions from existing fossil fueled electric gene ration units, it is appropriate to only consider those production impacts. Commenters stated this en sures regulatory consistency with previous regulatory programs as EPA recently embraced this v ery concept in the proposed Standards of
Performance for Greenhouse Gas Emissions From New S tationary Sources: Electric Utility Generating Units. Commenters stated that, in that p roposal, the EPA states "In today's action, we propose that if CHP facilities meet the general app licability criteria they should be subject to the same requirements as electric-only generators. ..." and the EPA further states: "... under this approach, all combustion turbine units that meet su ch applicability requirements ... would be subject to the standard of performance for CO2 emis sions. That standard would be: (i) during periods when certain conditions (noted below) are m et, 1,000 or 1,100 lb CO/MWh Commenters stated that, in the example above, the EPA properly excluded any inclusion of low pressure steam utilization when considering CHP applicabilit y. Commenters stated the EPA proposed to treat CHP units under a CAA Section 111 requirement as only the electric generator, and not as a steam producer. Commenters stated the EPA's proposa l did not include any CHP adjustment, instead EPA decided to regulate a CHP unit as only a NGCC electric generator. Commenters stated that, applying consistent reasoning in this proposal for existing units is prudent and EPA should exclude any mathematical adjustment for Usef ul Thermal Output (UTO) when establishing statewide emissions intensity for NGCC units.

Commenters asserted that the EPA should exclude CHP facilities from the Building Block 2 calculations for NGCC. Commenters stated that major differences exist between the purpose, design, fuel flexibility and operating philosophy o f CHP facilities and NGCC units such that CHP facilities that meet the definition of a 111(d) affected source should considered separately in the building block calculations. Commenters indi cated that the EPA acknowledges and discusses these distinguishing characteristics thor ough a website and support documents
associated the "EPA Combined Heat and Power Partner ship." Commenters further quoted the EPA's "CHP Project Development Handbook" as saying : "Whether CHP can be economically beneficial at any particular site depends on a host of site-specific characteristics such as the energy consumption profiles of the facility, the re lative prices of fuel and retail electricity, and the costs of installing and maintaining the CHP equ ipment." Commenters highlighted the differences in how CHP facilities operate by includ ing the permit condition for one CHP facility in Connecticut, which discusses significantly diffe rent options for operation the unit as follows: "General Electric turbine (EU1-Permit No. 213-0029) and two Nebraska boilers (EU2-Permit No. 213-0031 and EU3-Permit No. 213-0032) burn natu ral gas and No. 2 fuel oil. The turbine and the boilers can be operated by themselves or un der the following combinations: turbine and the equivalent of one boiler, two boilers without t he turbine."

Commenters asserted that the EPA's treatment of CHP facilities creates an artificially low CO2 emission rate for the facility that leads to an ina ccurate baseline NGCC emission rate that is biased low and that has not been adequately demonst rated. Commenters stated that this results in overly stringent state emission rate goal. Commente rs explained this assertion as follows:180 • "Co-generation units are capable of providing both electric energy output and useful thermal output (UTO). For CHP facilities sub ject to the proposed rule, EPA calculates CO2 emissions and energy output (in MWh) associated with the useful thermal output that is not used for electricity pro duction. EPA then adds only the UTO related energy output to the electric output to calculate a revised baseline NGCC emission rate for the facility. The UTO relate d CO2 emissions are not
used to calculate the revised baseline NGCC emissio n rate, but instead are added into the "Other Emissions" component of the buildin g block two methodology."

Commenters illustrated this concern using the EPA g oal calculations for Arkansas where the agency identifies seven NGCC facilities in the stat e, one of which is a CHP unit (Pine Bluff) where energy output and CO2 emissions associated wi th useful thermal output were calculated. Commenters provided the following explanation:

• "The impact of EPA's methodology for considering UT O energy output is significant as it reduces Pine Bluff's emission rat e by 47% from 1,132 lb./MWh to 602 lb./MWh - a rate that is not remotely close to have been demonstrated by any NGCC unit. In turn, the average NGCC CO2 emission r ate for Arkansas is reduced by 8% from 896 lb./MWh to 827 lb./MWh. None of the other six NGCC units had annual CO2 emission rates less than or eq ual to 827 lb./MW, and none would ever be expected to achieve a rate of 602 lb. /MWh. The absurdity of the 602 lb./MWh value becomes apparent after review of any number of EPA databases, studies, and reports that have evaluated NGCC CO2 emission rates, which indicates that even the most optimistic of CO 2 emission rates are much higher (hundreds of lb./MWh higher) than the 602 lb ./MWh rate calculated for
Pine Bluff."

Retiring NGCC plants should be excluded.

Commenters stated that the EPA has not accounted ap propriately for retiring NGCC units. Commenters believe that if plants under constructio n are included in the goal-setting calculations, then it is also appropriate in some i nstances to exclude plants that were scheduled to
be retired between 2012 and 2014. Commenters said t hat, given the large number of possible NGCC retirements suggested by the age of the natura l gas-based fleet, the EPA's failure to
account for future unit closures while simultaneous ly including under construction units potentially overestimates the size of the NGCC flee t, as new NGCCs could be replacing older units scheduled to be retired. According to the com menters, this "double counting" could result in inflated projections of the magnitude of emissio ns avoided and, consequently, unachievable state-specific goals.

Commenters suggested the EPA recognize actions bein g taken by utilities within the interim period to comply with other CAA programs, such as r egional haze, that result in the cessation of coal-firing at affected units. Commenters stated th at, if owners of these coal-fired units have
made a commitment either to shut down or convert to natural gas before the date of the final rule,
it would be unreasonable to include them for re-dis patch under Building Block 2 prior to their
committed shutdown or conversion date.181

Commenters stated that, in establishing the state g oals, the EPA needs to take into account any existing, enforceable agreements between the states and affected facilities located in their states. Commenters stated that it should be unnecessary for a state to establish a goal or plans to achieve a goal that grows out of emissions from an affected facility that is already scheduled to close prior to the first interim compliance period in 202 2. Commenters also stated that, if the facility is scheduled to convert to an NGCC power station only, it should be tracked in the state goals as if all the NGCC units are operational, if that is thei r scheduled installation before 2022.

Comment 34: Commenters suggested the EPA establish an exemption for EGUs that burn over 75 percent coal refuse on an annual basis".

Response 34: The EPA has determined that coal refuse facilities are covered units under the 111(d) final rule. See sections V.D, VIII.A, VIII.C and VIII.G of the final rule preamble of the CPP and Chapter 3 of the GHG Mitigation Measures TS D for the CPP Final Rule supporting the

final CPP. See Preamble Sections IV and V for the EPA’s response to this comment.

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

Commenters referred to a PADEP Section 11(d) white paper, previously sent to the EPA, and stated there are multiple environmental benefits of remediating coal refuse piles, including that it is essentially carbon neutral. Commenters stated th is approach would encourage the reclamation of the coal refuse piles as the coal refuse plants would be operated consistent with Building
Block 3.

Commenters stated that the proposed "carbon" based dispatch block will require certain states to displace electrical production from higher carbon f uels such as coal refuse in an economically damaging disproportional fashion. Commenters stated that, based on recent operation of coal refuse plants in a deregulated market (PJM), the co al refuse plants would not be economically viable at the low capacity factors envisioned under the EPA's plan for coal fired EGUs.

Comment 35: Commenters suggested allowing for exceptions due to emergency situations such

as extreme weather.

Response 35: See section VIII.G of the final rule preamble of th e CPP for EPA’s response to

this comment.

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

Commenters stated that any legal building block usi ng natural gas should be sufficiently flexible to excuse compliance during times of significant ca pacity constraints or other emergencies, such as during the January 2014 polar vortex, Hurricane Sandy in 2012 or Hurricane Katrina in 2005.
Commenters stated that failure to account for these practical implications will put citizens at182

great risk as utilities are forced to weigh environ mental compliance with electric reliability and customer well-being.

Commenters noted the shortage of natural gas in the winter of 2014 caused some of the generation to re-dispatch back to coal. Commenters stated that, as the entire country (including utilities, industrial, commercial, and residential) moves toward using natural gas for both heat and electricity, these shortages could become more frequent and longer, making it very difficult to maintain 70% load year round. Commenters suggest ed that the rule include a provision for natural gas curtailment much like the National Emis sion Standards for Hazardous Air Pollutants (ICI Boiler MACT SD and Area Source Boiler GACT 6J)

.

Comment 36: Commenters recommended changes to the EPA's Buildin g Block 2 calculation regarding oil/gas steam units, timing, and the pres ervation of a minimum level of coal steam

MWhs.

Response 36: The EPA disagrees with the interpretation of the ru le. We believe we considered these system issues and provided states flexibility to address them. In response to additional analysis and many comments, we have modified the pr oposal and RIA – the establishment of CO2 emission reduction standards is regionally base d and the start of the interim performance period has been postponed for two years. The 111(d) final rule requires that states develop plans

that establish emission standards for affected EGUs . We are providing states with substantial flexibility as to how they structure those plans to achieve the 111(d) requirements. The flexibility includes, for example, the choice of approaches, tr ading, time to develop plans, additional time before the start of the interim performance period (postponed from 2020 until 2022), and the ability to shift emission rate achievement between performance periods. The Building Blocks are not prescriptive, and states may consider local cir cumstances as they develop their plans, including system reliability, fuel diversity, the n eed for “ancillary services” and other regulatory requirements. EPA does not believe that achievement of the final rule requirements will result in over-construction of new generation. See sections V .D, VIII.A, VIII.C and VIII.G of the final rule preamble of the CPP and Chapter 3 of the GHG M itigation Measures TSD for the CPP Final Rule supporting the final CPP.

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

Commenters recommended the following suite of adjus tments to EPA's Building Block 2 calculation and stated they would not support adopt ing one or two and not the other(s). Commenters stated that, while it is impo rtant that the EPA maintain the interim targets
to ensure that states achieve emission reductions a cross the compliance period and not delay emission reduction programs to the latter half of t he decade, it is important to establish more of a "glide path" from where states are today to the fin al goals in 2030. Commenters specifically recommended the following suite of adjustments:

“First, we recommend that, in developing the propos ed state targets, EPA assume a ramping to a 70 percent NGCC fleet capacity factor in order to p rovide states with additional flexibility to make sure the infrastructure necessary to support t his level of utilization is in place or to increase the use of other compliance strategies. Second, we recommend that 2012 generation from183

affected oil/gas steam units be excluded from the g oal computation since oil/gas steam units serve a different segment of the dispatch curve and are often used as a backup to coal and natural gas baseload generating facilities, as opposed to a replacement for those facilities. Third, we
recommend that EPA retain 10% to 12% of coal steam MWhs in the state goal computation.”

Commenters stated that, in terms of the ramp rate, Clean Energy Group members are concerned that EPA's proposed methodology for calculating the NGCC contribution to the interim goals would reduce the flexibility EPA intended to provid e. Commenters stated that, in contrast to the two other building blocks, coal plant efficiency im provement and increased utilization of NGCC capacity have no impact on annual rates between 202 0 and 2029 because the goal computation formula raises efficiency levels of coal plants and utilization of NGCC facilities to their final target levels in 2020. Commenters stated that, beca use Building Blocks 1 and 2 account for over 40 percent of the total proposed reduction under th e rule, front loading the emission rate trajectory causes the rates used to calculate the i nterim goals to be sharply lower in 2020 than the 2012 baseline, with little change thereafter betwee n 2020 and 2029; e.g., the proposed annual rate trajectories for Arizona and Minnesota suggest that over 80 percent of the rate reductions
would be reflected in the calculated 2020 emission rate. Commenters stated that, on average, across all states, two-thirds of all proposed reduc tions are reflected in the calculated 2020 emission rate, with the remainder spread over the p eriod 2020-2029.

Commenters recommended that EPA assign to each stat e a specific annual increase that is calculated based on the difference between 70 perce nt and the state's actual average annual NGCC capacity factor in 2012. Commenters noted that , in 2012, natural gas prices were relatively low, so NGCC utilization rates were rela tively high. Commenters stated the EPA could take a range of approaches to introducing NGCC to t he goal setting equation. To be consistent with the proposed approaches to renewable energy an d energy efficiency, Commenters stated the EPA could start increasing NGCC from 2012 levels in 2017 to the 70 percent target in 2029; alternatively, the EPA could consider reaching the 70 percent level in 2025. Commenters expected that EPA would arrive at a ramping rate th at considers the potential permitting and system constraints described above.

Commenters stated that the other two changes they r ecommended to Building Block 2 are similar in terms of justification and implementation. Comm enters stated that oil/gas steam units serve a different segment of the dispatch curve and are oft en used as a backup to coal and natural gas baseload generating facilities. Commenters stated t hat, in 2012, NGCC capacity factors increased significantly and coal steam utilization rates decl ined; however, the average utilization of natural gas and oil steam units was virtually unchanged bet ween 2011 and 2012, demonstrating that utilization rates of oil/gas steam units do not cor relate with NGCC capacity factors.

Commenters stated that, according to EPA's eGrid da tabase, fossil steam units with capacity factors of 40 percent or less accounted for 12.3 pe rcent of total fossil steam MWhs in 2012. Based on this analysis, commenters recommended that EPA preserve at least 10 percent to 12 percent of coal steam generation in calculating the state goals. Commenters stated these lower capacity factor units tend to be used for peak dema nd periods and to maintain grid stability and, as a result, they should not be included in the re- dispatch analysis. Commenters stated that, to implement these changes, EPA could treat affected 2 012 oil/gas steam MWhs and a minimum
share of affected 2012 coal steam MWhs like it does "Other Generation" in the re-dispatch184

analysis, meaning not subject to NGCC re-dispatch. Commenters stated the sources responsible for this generation would continue to be affected s ources subject to the standard. Commenters stated that, by excluding this generation from the NGCC re-dispatch, EPA would avoid situations where the re-dispatch would assume elimi nation of 100 percent of boiler steam MWhs in the state goal computation. Commenters noted tha t, under EPA's proposed approach (Option 1), there are 12 states where all coal and oil/gas boiler steam generation is assumed eliminated from the goal computation. Commenters stated the pr oposed change would preserve an element of fuel diversity that we believe is important to c apture in the goal computation.

Preserving a percentage of coal-fired steam generat ion.

Commenters stated the EPA must preserve 10% to 12% of in-state, coal-fired steam generation in the state goal computation to ensure reliability . Commenters stated that some level of fuel diversity is necessary, especially if we expect to see more severe weather patterns due to climate change. Similar to the coal units, commenters state d that the preservation of oil/gas steam units is necessary for reliability based on their historical usage to support the system during periods of high demand. Commenters supported CEG's position fo r exclusion of 2012 generation from oil/gas steam units from Building Block 2.

Commenters agreed with EPA's assessment that signif icant reductions in CO2 emissions are available through the re-dispatch of cleaner NGCC u nits as seen in the northeast with lower natural gas prices. Commenters referred to an attac hed CEG comment letter and stated the EPA must take into consideration the manner and timing for these reductions. Commenters stated the EPA's modeling of Building Block 2 results in the c omplete elimination of fossil fuel-fired steam EGUs in 12 states. Commenters stated that capacity factors from coal- and oil/gas-fired EGUs in certain parts of the country have dropped significa ntly over recent years and, New England has become increasingly dependent on natural gas-fired power since many coal plants have shut down in the region. Commenters stated this shift in generation resources has led to reliability challenges to the region and, in response ISO-NE cr eated the Strategic Planning Initiative (SPI) in 2010 to address issues arising from being highly reliant on natural gas especially in this highly natural gas delivery constrained area. Commenters s tated the importance of baseload and intermediate load generation fuel diversity for rel iability purposes was observed in January and February of 2014, when the area experienced extreme ly cold weather and the demands for natural gas could not be met for both power product ion and home heating. Commenters stated that both coal- and oil-fired generation were neede d during the cold snap due to a lack of delivery capability to natural gas-fired EGUs. Comm enters noted this concern was specifically
identified in the North American Electric Reliabili ty Corporation's ("NERC") Initial Reliability
Review of the CPP in which NERC identifies that the implementation of the proposal will create a greater reliance on natural gas-fired generation which requires pipeline expansion to meet demand, especially during the peak winter heating s eason. Commenters stated that, based on their experience in this area, the EPA must preserv e 10% to 12% of in-state, coal-fired steam generation in the state goal computation to ensure reliability.

Commenters stated PSEG operates two facilities with oil/gas steam units which serve a different segment of the dispatch curve and are usually opera ted during summer peak load periods as a backup to the baseload and intermediate load units. Commenters referred to CEG's comments and stated that nationwide oil/gas steam units have maintained consistent capacity factors around185

10%. Commenters stated that the preservation of the se units is necessary for reliability based on their historical usage to support the system during periods of high demand.

Comment 37: Commenters suggested the EPA revise its state goal calculations to ensure that natural gas simple-cycle and/or steam boiler units are not included as part of the existing NGCC capacity.

Response 37: Simple cycle combustion turbines are not included i n state goals, and may not be used to adjust a rate. In response to additional an alysis and many comments, we have modified the proposal and RIA – the establishment of CO2 emi ssion reduction standards is regionally based. The 111(d) final rule requires that states d evelop plans that establish emission standards for affected EGUs. We are providing states with sub stantial flexibility as to how they structure those plans to achieve the 111(d) requirements. The flexibility includes, for example, the choice of approaches, trading, time to develop plans, addi tional time before the start of the interim performance period (postponed from 2020 until 2022) , and the ability to shift emission rate achievement between performance periods. The Buildi ng Blocks are not prescriptive, and states may consider local circumstances as they develop th eir plans, including system reliability, fuel diversity, the need for ancillary services other re gulatory requirements and infrastructure. EPA

does not believe that achievement of the final rule requirements will result in over-construction of new generation. See sections V.D, VIII.A, VIII.C and VIII.G of the final rule preamble of the CPP and Chapter 3 of the GHG Mitigation Measures TS D for the CPP Final Rule supporting the

final CPP.

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

Commenters supported the Agency's decision not to i nclude simple cycle units in calculating goals, as these are typically much smaller, operate for short periods to meet peak demand, and are unlikely to have much impact on industry-wide e mission rates from gas-fired EGU's. Commenters stated that their analysis found that on ly 18 of a total of 583 gas-fired EGU's had heat rates that exceeded 250 MMBtu/hour and a 5-yea r average gross generation greater than 240,000 MW-hr, which are the criteria EPA used to i dentify gas-fired units included in its proposal.

Commenters stated the EPA should not include CTs th at operate above 30% capacity in its calculations for Building Block 2. Commenters state d that, unlike NGCC units, CTs do not have firm contracts for natural gas, thus rendering them more sensitive to natural gas supply and capacity constraints. Commenters stated that, if na tural gas is unavailable, CTs resort to burning fuel oil, which is considerably more expensive, is less efficient, and emits more pollutants. Commenters stated that including CT units in the re -dispatch under Building Block 2 would undermine the reduced emissions goal EPA promotes i n the Proposed Rule. Commenters stated that, since existing CT units were designed as peak ing units, no data are available evaluating the ability of CT units to operate at 70% capacity, thu s, it is not possible to know whether such operations are even technically feasible over an ex tended period of time.186

Commenters asserted that the EPA must revise its st ate goal calculations to ensure that natural gas simple-cycle and steam boiler units are not inc luded as part of the existing NGCC capacity. Commenters provided a table said to give examples o f this issue. Commenters stated that the EPA designed building block 2 to apply to existing NGCC units that are within the regulated source categories, but in the goal calculations for some states, the EPA incorrectly included natural gas simple-cycle and gas steam units as par t of the existing NGCC capacity.

Commenters stated that conversion to simple cycle c ombustion turbines should simply not be allowed in the state goals calculation or the state plans.

Comment 38: Commenters supported the creditable conversion of simple cycle units to NGCC.

Response 38: Simple cycle units are not included in affected uni ts under this rule, so this conversion would not qualify. See sections V.A and V.D of the final rule preamble of the CPP and Chapter 3 of the GHG Mitigation Measures TSD fo r the CPP Final Rule supporting the final

CPP.

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

Commenters stated that there are numerous opportuni ties for existing simple cycle generating facilities to be converted to combined cycle and th e EPA should clarify that these types of projects are creditable in state plans. Commenters stated that converting these units has multiple benefits and should be encouraged and incentivized under the proposal. Commenters stated that, not only would utilization of such converted units take advantage of existing infrastructure (similar to underutilized NGCC units), such convers ion would take an existing less efficient, higher emitting simple cycle plant typically used f or peaking capacity and utilize it as a far more efficient, lower emitting combined cycle facility, thereby helping states meet their CPP targets. Commenters stated that, as a general matter, LS Pow er would expect heat rates on converted combined cycle plants to improve by 25-30%.

Commenters stated that, while EPA is considering th e extent to which new projects should be incorporated into the CPP, it is important to consi der converted units as presenting additional and more near-term opportunities than greenfield projec ts. Commenters stated that, in order to properly incentivize the conversion of simple cycle units, the CPP should specifically allow
states to claim credit for the conversion of a less efficient existing peaking facility to a new combined cycle plant. Commenters stated the proposa l should allow states to take credit for
emissions reductions associated with conversion to a NGCC facility, including: (1) the tons of emissions reduced as a result of the re-dispatch fr om a coal facility when utilizing a mass basis; (2) the lower emission rates associated with the r e-dispatch from a coal unit to the converted NGCC unit when utilizing a rate basis; and (3) the additional lower emission rates associated with the use of the NGCC facility as compared to th e previously existing simple cycle facility when utilizing a rate basis.

Commenters stated doing so will allow states to tak e advantage of cost-effective means for reducing CO2 emissions while providing ancillary be nefits from reduced criteria and toxic187

pollutants. Commenters stated that, in the past 15 years, tens of thousands of megawatts of efficient gas turbine technology have been installe d in a simple-cycle configuration, with the infrastructure in place to expand to a more efficie nt combined cycle configuration when the
market dictated such a move. Commenters stated that LS Power and other generators have the sites, ability and resources to successfully execut e many of these types of projects in the next few years. Commenters stated it is important that the f inal rule build on the NODA and remove uncertainties regarding the crediting of projects i nitiated prior to 2020 and grant credit for such early action.

Commenters stated the conversion of a fraction of s imple cycle combustion turbines to NGCC units, where reasonable, should be encouraged and s hould be included in the base. Commenters
indicated this should include units that are alread y under construction and units that have not completed construction by the date of the adoption of the final rule should meet the new power plant NSPS.

Comment 39: Commenters recommended various approaches to calcul ating BB2 for NGCC plants that were constructed since 2005, are likely to be constructed before 2030, and were under construction in 2012 and objected to the 55% capaci ty assumption.

Response 39: The EPA has finalized this rule and is not includin g new NGCC units. See section V and the TSD on Goal Setting for the EPA’s respons e to this comment.

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

Exempt units constructed since 2005.

Commenters suggested the EPA should exempt from the Building Block 2 re-dispatch calculation all NGCC capacity constructed since 200 5 to replace retired coal-fired capacity and recommended this exemption should include both exis ting NGCC capacity and NGCC capacity currently under construction.

Commenters requested that the EPA exempt NGCCs buil t after 2005 to replace coal from the 70 percent capacity factor assumption and recalculate the building block 2 assumption without these units, and that the EPA provide for early action cr edit for the renewable generation investments prior to 2012. Commenters requested that the EPA ac knowledge early performance by providing credit for actions taken pursuant to an existing st ate program, requirement, or measure on or after 2005, the baseline year for CO2 emission levels.

Include units likely to be constructed between now and 2030.

Commenters recommended that the EPA consider revisi ng building block 2 to incorporate the potential for re-dispatch from existing coal power plants to new NGCC plants likely to be constructed between now and 2030 and the potential for many existing coal-fired plants to cofire less carbon intensive fuels or convert to firi ng natural gas. Commenters stated this would better reflect demonstrated and available practices to reduce emissions, result in greater equity188

across states, and ensure that the effectiveness of EPA's proposal is not diluted by the construction of new NGCC plants.

Address units that came on line during, and were op erational for only part of 2012.

Commenters expressed concern that the Proposal incl uded in the baseline existing NGCC capacity for each state NGCC units that were commis sioned during the year 2012.

Commenters requested that EPA remove from the BSER and the state goal calculation NGCC
units under construction. Commenters stated the EPA should not rely on generating capacity from "under construction" units when applying Build ing Block 2 to calculate the proposed state goals. Commenters stated there is no legal requirem ent or basis for EPA to include a projection of future emissions and generation (megawatt hours) from these units in its determination of BSER and in calculating the state goals. Commenters stated the EPA has no basis to assume what generating capacity will be available for re-d ispatch from NGCC units that had no operating history during or prior to the 2012 basel ine year. Commenters stated that, given EPA's lack of justification for predicting the hypothetic al operating duty of units that were not operating in the baseline year of 2012, EPA should exclude "u nder construction" NGCC units from its application of Building Block 2 for the purposes of calculating state goals. Commenters stated that, because these units are technically "existing sources" under section 111(d) as proposed, they would remain subject to appropriate state plan requ irements once they begin operation and would count towards compliance with a state's inter im and final goals if they satisfy the relevant applicability criteria.

Commenters stated the EPA must address the state-sp ecific problem of NGCC units that came on line during, and were operational for only part of, 2012 and suggested the EPA should give such units the benefit of at least a 55 percent capacity factor, which EPA presumes for NGCC capacity that was under construction in 2012.

Commenters stated that the EPA has not appropriatel y accounted for under construction NGCC units when calculating the state goals. According t o the commenters, the EPA suggests that all states' NGCC fleets, including units under construc tion as of January 1, 2014, are able to achieve a 70 percent utilization rate, and the EPA assumes that the additional generation from under construction NGCC units also will displace coal gen eration, thereby reducing CO2 emissions. Commenters noted that the potential for re-dispatch ing these under construction units is one of the inputs used in calculating state-specific goals (79 FR 34896). Commenters stated that the
EPA should not include the units that were under co nstruction, and therefore unavailable to produce power, during the 2012 baseline year when c alculating state goals; only units that were operational and producing power in the 2012 baselin e year should be included in the baseline. Given that all the data used by EPA is based on the electric generation system as of 2012, commenters believe that removing the units that wer e not operational in 2012 will result in calculations that better reflect the real potential for re-dispatch in 2012.

Commenters stated that inclusion of plants under co nstruction in 2012 significantly depresses the actual realized capacity factor for North Carolina NGCC plants for 2012. Commenters stated that two of the units included in EPA's list of existing NGCC plants (H.F. Lee and Dan River) had de minimis generation in calendar year 2012 and were, in fact, under construction until very late in189

December. Commenters stated that these two plants h ad capacity factors of essentially zero for that year. Commenters stated the average capacity f actor for existing NGCC generation located in North Carolina, as designated by the EPA, adjust ed for IOU-owned units in North Carolina is approximately 44.7% for calendar year 2012. Comment ers stated that, when North Carolina's NGCC plants that were operational for all or the ma jority of 2012 (Smith 4, Smith 5, Buck, and Rosemary) are utilized, the North Carolina NGCC cap acity factor rises to 64.5% (utilizing nameplate capacity) for 2012. Commenters stated tha t, utilizing summer net capacity values for the same four plants, the annual capacity factor ri ses to 71%, which is above EPA's target of
70%. Commenters concluded that North Carolina's NGC C plants have minimal headroom for
additional utilization.

Recalculate for units constructed after 2013.

Commenters specifically requested that EPA recalcul ate the Virginia targets excluding the emissions and megawatt hours from the Warren and Br unswick NGCC units in Building Block 2. Commenters stated that, specific to Dominion, EP A included NGCC units that were under construction as of January 8, 2014, such as Dominio n's Warren and Brunswick facilities in Virginia, in the calculation of the state goals in Building Block 2, increasing the stringency of the state targets (by almost 40 lb/MWh). Commenters sta ted that, although "under construction" by new source performance standard (NSPS) definition, these units were not operational during the 2012 baseline year and therefore should not be incl uded in setting the state target. Commenters stated that including under construction NGCC units in the calculation of the state reduction targets disadvantages the state and the utility com pany for early actions to reduce the state's emission rate by investments in less carbon-intensi ve technology.

Commenters stated that, in the goal calculations fo r certain states, the EPA incorrectly included as part of the existing NGCC capacity certain NGCC projects that were constructed after 2013, are still undergoing construction, have yet to comm ence construction, or have yet to receive all necessary permitting and regulatory approvals. Comm enters stated the EPA must revise these
calculations to exclude such units and to ensure th at the existing NGCC units considered have actually been constructed.

Commenters objected to the preamble's inclusion of NGCC units that were in operation or had commenced construction as of January 8, 2014 becaus e it assumes that such units have operated at the intended output level prior to the stated da te. Commenters stated that North Carolina has undergone significant shifts from the retirement of older, less efficient coal-fired EGUs to new or modified NGCC EGUs in recent years and most of the NGCC capacity increase occurred
between 2012 and 2013. Commenters stated the EPA h as incorrectly accounted for NGCC EGUs that started operation just prior to January 8 , 2014. Commenters stated that two major areas of concern include the assumptions for existi ng and under construction natural gas combined cycle capacity and the misrepresentation o f the state's Renewable Energy and Energy Efficiency Portfolio Standard. Commenters stated th at all of these comments need to be
addressed in order to establish an accurate and mor e technically sound state goal for North
Carolina.

Do not agree with the 55% capacity assumption.190

Commenters stated that, to the extent EPA retains i ts proposed approach to include under
construction NGCC units in the calculation of state goals, EPA should take into account the specific circumstances of under construction NGCC u nits to determine the expected extent to
which those units can increase their utilization in order to displace higher-emitting steam generating units. Commenters stated the methodology for calculating state goals should be
revised to better reflect the actual emission rate improvements that under construction units are capable of delivering. Commenters stated that the s pecific circumstances of these units vary widely from EPA's assumed 55 percent, thereby artif icially increasing the stringency of the state goal in many states that are already building NGCC capacity to act as base load capacity to replace generation sources that have or are expecte d to retire for economic or environmental reasons. Commenters noted that (1) Dominion is curr ently constructing two NGCC units in Virginia, (2) in 2012, NGCC utilization across all NGCCs in Virginia averaged 60 percent, (3) Dominion's NGCC units averaged over a 75 percent ut ilization rate, and (4) Dominion is constructing these units to meet high intermediate or base load power needs, and they are expected to run at significantly more than 55 perce nt utilization, even without the proposed
Clean Power Plan. Commenters stated that the EPA's assumption that these units will run at only 55 percent capacity factor therefore significantly overestimates the contribution that these units can have in displacing CO 2 emissions from existing fossil fuel-fired steam ge nerating units. Commenters stated that, for purposes of calculating the state emission goals, under construction NGCC units designed and constructed to serve base l oad generation needs should not be
assumed to be BSER.

Commenters stated that if the EPA determines to con sider under construction NGCC units when finalizing the state goals, the EPA should not assu me the same re-dispatch potential for all under
construction units. Commenters indicated that EPA's assumption that under construction NGCCs would operate at a 55 percent capacity factor is ar bitrary, and that the EPA has not provided a basis in the record for applying this assumed capac ity factor to all under construction units. Commenters noted that assuming a 55 percent capacit y factor for all under construction units ignores the purpose for which they were built - if they were built to serve base load demand, they could be intended to operate at capacity factors ab ove 55 percent, reducing the capacity that would be available for dispatch under EPA's methodo logy. Commenters asserted that to the extent EPA retains its proposed approach to include under construction NGCC units in the calculation of state goals, EPA should take into ac count the specific circumstances of under
construction NGCC units to determine the extent to which those units can increase their utilization in order to displace higher-emitting st eam generating units.

State-specific issues.

Commenters referred to comments filed by Arkansas E lectric Cooperative ("AECC") on September 30, and stated the John W. Turk Power Pla nt in Arkansas has not been adequately captured in EPA's 2012 baseline emissions level. Co mmenters stated that, in 2012, as a new coal plant just coming online, Turk was undergoing testi ng and was in commercial operation for only ten days, and thus 2012 is not representative of Tu rk's emissions for a full year. Commenters agreed with AECC --the 2013 emissions from Turk mus t be factored into EPA's 2012 baseline emissions levels in order for the Proposed Rule to accurately capture the status quo; as a result, Turk's 2013 generation and emissions values (where it operated as a baseload unit for 365 days)
should be substituted in lieu of Turk's 2012 values

.191

Commenters stated that the EPA was not consistent i n its approach to under-construction NGCC units, excluding some from the state goal calculati ons. Commenters gave the example that, in calculating New Jersey's emission rate goals, the E PA failed to include several under
construction NGCC units. Commenters added that if t hese units are excluded, the EPA should make clear that New Jersey's compliance demonstrati on does not include these units, and that if
EPA chooses to consider under construction units wh en setting the final goals, EPA should
ensure that all under construction NGCC units in al l states are included.

Commenters added that the EPA must ensure that the data used to calculate the standards is correct, giving the example that the EPA incorrectl y lists PacifiCorp's Utah-based Lake Side 2 NGCC as operational in 2012 when the plant was unde r construction in 2012 and did not achieve commercial operation until June of 2014. The commen ters stated that this unit should be treated as an under construction unit, not an existing unit , for purposes of calculating Utah's state goal, and the re-dispatch portion of the Utah state targe t should be recalculated, consistent with the
intended use of the unit.

Commenters stated that, although these new units we re brought into service at different times during the year, EPA's calculation assumes that the y were available for operation for the entire year. Commenters stated this inaccurate assumption means that these new units are calculated to have an artificially low capacity factor, which pro duces then an artificially high amount of NGCC re-dispatch, with the end result of a state em ission rate goal that is biased low. Commenters noted two of the five existing NGCC unit s in Ohio were commissioned in 2012 (Dresden was commissioned January 31, 2012 and Frem ont was commissioned on January 20, 2012).

American Electric Power (24030) comments on "under construction" units.

Commenters stated that the EPA is inconsistent, inc omplete and inaccurate in its consideration of all NGCC units that were commissioned during and af ter 2012 in terms of if and how these units were classified into the "existing" or "under const ruction" category. Commenters asserted that it has identified numerous errors related to the scope of units considered (or not considered), the EPA's assumptions regarding the status of these pro jects and the EPA's methodology for considering these units within the block 2 calculat ions. Commenters provided detailed discussion of these issues (summarized below), and stated that the EPA must correct these issues, which Commenters believed to significantly diminish the N GCC capacity to be included within building block 2. Commenters added that for accurac y and completeness, the EPA should first review the scope of all NGCC units commissioned or to be commissioned after December 31, 2011, and second treat all of these units equally a s "under construction" in the building block 2
calculations. Commenters’ detailed comments about s everal aspects of this issue are summarized
below.

Commenters stated that in the calculation of existi ng NGCC capacity available in 2012, the EPA incorrectly included certain NGCC projects that wer e not commissioned until after 2012 as part of the "existing" NGCC units that were re-dispatche d up to a 70% capacity factor in the building
block 2 calculations. Commenters identified one exa mple facility that has not received its air permit or commenced construction, and as such would not be an affected source subject to the proposed section 111(d) guidelines. Commenters asse rted that the EPA must revise these192

calculations to exclude such units and to ensure th at the existing NGCC units considered have actually been constructed, and provided a table sai d to include examples of such units.

Commenters also stated that the EPA has incorrectly calculated the post-2012 "under construction" NGCC capacity for all nine states whe re the agency determined it applied. According to the commenters, for five of these stat es, the units determined to be "under construction" by the EPA represent fictitious "pote ntial" units identified within EPA's NEEDS database and Integrated Planning Model. Commenters indicated that these "potential" units are "phantom" units that do not represent real projects that have been proposed, designed, permitted or constructed, and that to the extent that these " potential" projects come to fruition, they would be subject to the new source standards under 111(b) , not the existing source 111(d) guidelines. Commenters asserted that these "potential" units sh ould not be considered in building block 2.

Commenters further stated that for the remaining fo ur states, the EPA incorrectly assessed the status of some units. Commenters gave the examples of the one "under construction" facility identified by EPA for Ohio - the Dresden Plant, whi ch was actually commissioned in 2012 - and the one "under construction" facility in Kentucky - the Cane Run project, which has yet to receive an air permit and has not yet commenced con struction. Commenters gave additional examples of units in Virginia and Wyoming.

Commenters added that not only has EPA mischaracter ized the under construction NGCC capacity for nine states, but the Agency has not re cognized other proposed NGCC projects that may fall into the under construction category. Comm enters indicated that its review of the spreadsheet tab marked "proposed" in the EIA860 rep ort that has been referenced by the EPA identifies many potential NGCC projects that were i gnored by EPA in building block 2. According to the commenters, potential NGCC project s have been identified for over 20 states, which may meet the definition of "under constructio n" as currently defined in building block 2.

Commenters noted that in determining the CO2 emissi ons associated with the re-dispatch of "under construction" capacity, the EPA used either the average emission rate for existing NGCC units in the state, or a national average if the st ate did not have any existing units. Commenters asserted that based on significant flaws in how the state average NGCC emission rates were calculated, the EPA's approach for determining the future emissions from under construction units is inaccurate and inequitable. Commenters pro vided a table showing the emission rates that
the EPA assumed for certain "under construction" NG CC facilities that commenters allege are not actual projects.

Commenters asserted that the EPA must correct what commenters believe are errors in both the scope of "under construction" units considered and the assumptions for consistently estimating
emissions from these units.

Commenters also stated that the EPA fails to consid er certain existing NGCC units that were commissioned during or after 2012 that could be con sidered existing 111(d) facilities, but were ignored by EPA in the building block 2 calculations . According to the commenters, these are units that commenced construction after 2012, but b efore January 8, 2014 - the effective date that the 111(b) standards for new sources were re-propos ed by the EPA. Commenters provided a table of including examples of such facilities.193

Commenters stated that the EPA overstates the amoun t of re-dispatch available from NGCC units commissioned in 2012 because it does not weig h the commissioning date into its calculation - when calculating re-dispatch, the EPA assumes that all of these units were available to operate throughout 2012 even though some of thes e units were not commissioned until later in the year. Commenters indicated that this assumption means that these new units are calculated to have an artificially low capacity factor, which pro duces an artificially high amount of NGCC redispatch, with the end result being a state emissio n rate goal that is biased low. As an example, commenters noted that two of the five existing NGCC units in Ohio were commissioned in 2012 (Dresden was commissioned 01/31/12 per Appalachian Power Company filing to the VaSCC on 03/20/12; Fremont was commissioned on 01/20/12 per AMP, Inc. filing to the Ohio Power Siting Board on 02/23/12.), and provided a table comparing baseline capacity factors for these two
facilities if calculated based on their in-service date versus the EPA's assumption that they were available for the entire year.

Commenters asserted that if units commissioned duri ng 2012 remain in the calculation of the "existing" category of units, then the potential re -dispatch for the existing NGCC fleet should be derived based on the historic capacity factor, not on the EPA approach of using historic generation. Commenters suggested a method of calcul ation that Commenters believe appropriately weighs the in-service date into the r e-dispatch calculation.

Commenters provided an example of the use of the su ggested approach for the Dresden and Fremont Plant which, along with the correction of o ther errors alleged by Commenters throughout the comments, would reduce the amount of NGCC re-dispatch calculated for Ohio from 5,793,981 to 439,452 MWh - a 92% reduction fro m EPA's calculated amount. Commenters gave another example, the H.F. Lee Plant, a 920 MW NGCC unit commissioned on December 31, 2012. Commenters contended that the unit was av ailable to operate for only 1 day in 2012, yet EPA's calculation assumes that the unit was ava ilable for the entire year. According to the commenters, the EPA calculated that approximately 6 ,548,976 MWh (equivalent of a 70% capacity factor) was available to be re-dispatched from this facility because it would have had a near 0% baseline capacity factor in 2012, which rep resent over 20% of the total re-dispatch
calculated for the state of North Carolina - even t hough the H.F. Lee plant had not been commissioned until the last day of the year. Commen ters added that the North Carolina goal is made more unrealistic by the commissioning of anoth er NGCC unit at the Dan River plant on December 10, 2012 - if the associated "re-dispatch" capacity from Dan River is considered as well, then nearly 40% of the re-dispatch capacity c alculated for North Carolina was from units that had not been commissioned or available to oper ate for most of the year. Commenters provided a table of alleged other examples of this issue.

Finally, commenters noted that the EPA's proposed 1 11(b) rule for new units included a technical support document for combustion turbines that was designed to evaluate potential
differences in emission rates due to various unit-s pecific factors, and that the EPA's evaluation
focused on NGCC units that were commissioned from 2 000 through 2010 because "[a]lthough new NGCC units came online in 2011, none are includ ed here as they lacked sufficient data to calculate a 12-month rolling average, the basis for determining a standard of performance". Commenters asserted that the EPA should apply this same rationale and exclude units
commissioned in 2012 from the calculation of existi ng NGCC units to be re-dispatched, and that these units could then be separately included in th e "under construction" category of units within194

building block 2 calculation. Commenters asserted t hat at a minimum, the EPA must at least revise the state goal calculations to properly acco unt for the date that new units were
commissioned in 2012.

Comment 40: Under Construction Unit (Deer Creek Station, SD)

Response 40: The EPA has decided not to finalize the relevant pr ovision of the rule, and no response to this comment is provided.

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

Commenters stated that South Dakota has only one NG CC plant, Basin Electric Cooperative's Deer Creek Station which began operating late in 20 12 running at about one percent of capacity, leading EPA to assume, incorrectly, that Deer Creek Station has an additional 69% of capacity available for increased generation. Commenters stat ed that, had EPA treated Deer Creek Station as under construction, or had it used a different b aseline year that properly reflected Deer Creek Station's status as a plant that is not yet operati onal, the emission reduction target for South Dakota would have looked very different from what E PA has proposed.

Commenters suggested the EPA needs to classify the Deer Creek Station as under construction because it was in its initial startup phase in 2012 . Commenters noted that, if EPA agrees with this request, South Dakota's state goal would increase f rom 741 to 1,036 pounds of carbon dioxide per megawatt-hour, which would give South Dakota mo re flexibility to use building block 2 as a method of demonstrating compliance with its state g oal instead of being penalized for the construction and installation of its sole natural g as combined cycle plant undergoing test firing in
2012.

Commenters stated that, even if it were feasible to re-dispatch energy between Deer Creek Station and the Big Stone Plant co-owners, the re-d ispatch target set for South Dakota under the proposed rule is arbitrary and capricious because i t is based on an erroneous exaggeration of the state's NGCC re-dispatch capacity. Commenters state d the error resulted using 2012 as the baseline year and treating Deer Creek Station as a fully operational generation source for that year, leading to an exaggerated assumption that Dee r Creek Station could ramp up generation by an additional 69% in future years. Commenters state d South Dakota is the only state assigned an overall 2012 NGCC capacity factor of less than 10%, and one of only three states assigned a capacity factor under 20%.

Commenters stated that, because Big Stone Plant is the only coal-fired unit in the state, the additional generation that EPA assumed exists at De er Creek Station would have to displace an equal amount of generation at Big Stone Plant, drop ping Big Stone Plant's total annual output from 2,923,000 MWh to just 958,000 MWh. Commenters stated that, to comply with the Building Block 2 emission target EPA assigned to So uth Dakota, Big Stone Plant would have to operate at an annual capacity factor of just 23%. C ommenters stated that since Big Stone Plant's minimum operating load is approximately 40% of norm al maximum load, running the plant at a 23% capacity would require it to be off-line at lea st half the year. Commenters stated that Deer195

Creek Station does not have sufficient excess capac ity to supplant such a significant reduction in Big Stone Plant energy production.

Commenters stated that operating a baseload generat ion unit such as Big Stone Plant so infrequently would be uneconomic, particularly afte r the unit has undergone a capital-intensive environmental retrofit to comply with the unrelated EPA regional haze and MATS rules. Commenters stated a replacement unit would need to be built to serve customers all 12 months of the year in a least cost manner. Commenters stated that fixed operation and maintenance costs, including 80 jobs, would remain even if Big Stone P lant were not operational for a period of time, which would strand the $384M investment in an AQCS driven by previous regulations and require the co-owners of Big Stone Plant to incur t he costs to replace the energy. Commenters stated it is important to remember that public utilities commissions in Minnesota and North Dakota granted advance prudence determina tions for the Big Stone Plant AQCS and this approved investment to serve electric consumer s and the continued viability of one of their primary sources of baseload electric energy should not be jeopardized by a flawed technical premise that EPA could rectify without affecting th e overarching methodology of the proposed rule. Commenters added that application of the rule should not contradict Administrator McCarthy's statement that coal plays a significant role in a diverse national energy mix (July 23, 2014, testimony to the Senate Environment and Publi c Works Committee).

Commenters noted that emissions standards set under Section 111(d) must, by statutory requirement, take into account the remaining useful life of the unit in question [section 111(d)(1)(B)] and that the EPA could prevent strand ing assets in this case by recognizing that
Deer Creek Station was under construction for most of 2012 and so classifying it for purposes of goal computation for South Dakota. Commenters state d that, after placing Deer Creek Station into the under construction category, if EPA contin ues to follow the proposed rule calculation methodology in the final rule, EPA should give the station a 55% capacity factor as the basis for South Dakota's Building Block 2 target calculation, as provided for in EPA's Goal Computation Technical Support Document. Commenters noted that f ollowing this methodology would result in a Building Block 2 target calculation for South Dakota that is similar in methodology to the target calculations for Wyoming and Kentucky. Comme nters stated that, because Wyoming and Kentucky had no existing NGCC units other than unit s that were considered under construction, EPA used a nationwide average NGCC emissions rate o f 907 lb/MWh (net basis) as the assumed
emission rate for these two states.

Commenters stated that, if EPA does proceed with in cluding under construction units in the final rule, using a nationwide average is a rational appr oach to determining the appropriate emissions rate. Commenters stated it is also more representat ive than using Deer Creek Station's 2012 CO2 emission rate average. Commenters stated that, if E PA insists on applying Building Block 2 to South Dakota despite its unique circumstances, EPA must recalculate the emission reduction targets to account for the reality of the situation in 2012.

Commenters stated that because South Dakota's only coal-fired plant, Big Stone, is located in a different RTO, has an entirely separate ownership, and serves entirely different customers than Deer Creek Station, any form of re-dispatch from co al to NGCC in South Dakota, as required by Building Block 2, is not really available.196

Comment 41: Commenters disagreed with BB2 calculations that inc luded certain sources and source types, such as sources that do not meet the NSPS eligibility criteria, double counting of sources, and units that do not exist.

Response 41: The EPA disagrees. In response to additional analys is and many comments, we have modified the proposal and RIA – the establishm ent of CO2 emission reduction standards is regionally based and the data updated. The 111(d) f inal rule requires that states develop plans

that establish emission standards for affected EGUs . We are providing states with substantial flexibility as to how they structure those plans to achieve the 111(d) requirements. The flexibility includes, for example, the choice of approaches, tr ading, time to develop plans, additional time before the start of the interim performance period (postponed from 2020 until 2022), and the ability to shift emission rate achievement between performance periods. The Building Blocks are not prescriptive, and states may consider local cir cumstances as they develop their plans, including system reliability, fuel diversity, and o ther regulatory requirements. See sections V.D, VIII.A, VIII.C and VIII.G of the final rule preambl e of the CPP and Chapter 3 of the GHG Mitigation Measures TSD for the CPP Final Rule supp orting the final CPP.

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

Commenters stated the EPA's calculation methodology incorrectly applies its building blocks approach to non-affected Subpart KKKK units. Commen ters stated the proposed goals assume that states will regulate these sources, but states can only regulate existing sources to which an NSPS would apply under Section 111(b). For GHG emis sions, Commenters stated an NSPS only applies to stationary combustion turbines that meet certain capacity-related criteria. Commenters stated that some NGCC units to which generation wou ld be shifted under EPA's Proposal for building block 2 do not qualify under these capacit y-related criteria, and EPA has not identified how many NGCC units in Arizona or elsewhere qualify under these criteria. Commenters stated the EPA's calculations assumed all of these units, whether or not they are subject to regulation, could participate in building block 2, arbitrarily and capriciously inflating the state goals.

Commenters stated that, for those NGCC units that c an properly be regulated, EPA made various errors in calculating capacity, double-counting som e units, and counting non-existing units. Commenters stated these mistakes are explained in m ore detail by UARG's consultant, James Marchetti, and APS incorporates his report and UARG 's comments on this issue.

Commenters stated that data available in the docket suggest that a substantial number of NGCC
units used in EPA's calculations would be excluded under Building Block 2 because they do not meet these required criteria for inclusion in secti on 111(d). Commenters stated that the success of Building Block 2 depends on the participation an d compliance of units that will not be subject to the Proposed Rule. Commenters stated that the EP A considered ineligible EGUs in the calculation of state goals, citing the Marechetti R eport. Commenters stated that the Proposed Guidelines may be used only to establish standards of performance for existing EGUs that otherwise meet the eligibility criteria for EPA's p roposed NSPS for GHG emissions from new EGUs (79 FR 1430) and the NSPS for new EGUs applies to any stationary combustion turbine197

that, inter alia, has a base load rating greater th an 73 MW (250 MMBtu/h) and was constructed for the purpose of supplying, and supplies, one-thi rd or more of its potential electric output and more than 219,000 MWh as net-electrical sales on a three-year rolling average basis. Commenters stated that the Proposed Rule makes the mistake of basing the state goal calculation on units that are not subject to regulation. Commen ters stated that, because States cannot impose standards of performance on these units, the increa ses in NGCC capacity EPA expects them to make will necessarily have to be made by EGUs that are subject to EPA regulation, with the
result that affected NGCC units will be forced to o perate at capacity factors significantly above 70% in order to achieve the generation EPA expects States to require from EGUs that the States may not regulate. Commenters stated the EPA include d in its calculation of state goals emissions from and capacity for existing NGCC units that do n ot currently exist, that have not yet been fully developed, and that may never be completed, r eferencing UARG comments (Section XIV.C).

Comment 42: Commenters stated the EPA should re-formulate its c alculations for Building Block 2 to address the relationship between re-disp atch and integrated gasification combined cycle (IGCC) plants.

Response 42: The EPA disagrees. EPA believes that these plants need to comply with this rule, and believes the rule provides sufficient flexibili ty, through approaches such as trading, that will permit states to address any special concerns to IG CC plans in their state.

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

Commenters stated that, if Indiana elects to impose direct limits on the operating profile of higher-emitting EGUs, the EPA expects NGCC plants t o fill the gap. Commenters stated that could be problematic for Indiana's IGCC units, whic h were specifically excluded from EPA's calculations for Building Blocks 1 and 2. Commenter s stated that emissions of CO2 at IGCC plants are in line with coal-fired power plants; ho wever, heat rate improvements are not viable due to the intrinsic nature of the process. Comment ers concluded that, in order for a coal-heavy state such as Indiana to meet EPA's goals, IGCC pla nts will be dispatched less frequently than would otherwise be the case. Commenters suggested t hat, because the existing investment in IGCC plants will be effectively penalized by the pr oposed rule, the EPA should re-formulate its calculations for Building Block 2 to directly addre ss the relationship between re-dispatch and IGCC plants in a way that takes into account those plants unique attributes.

Comment 43: Recommend Allowing Credit for Conversion from Liqui d Fuel to Natural Gas.

Response 43: The EPA has carefully considered cofiring -- and co nversions as a 100% cofiring option -- and determined that it is not part of BSE R (See Preamble Section V.A). However, sources that convert to liquid fuel under this rule can generate credits based on their reductions and states can fashion their plans to take advantag e of there aspects of the rule. See sections V.D,198

VIII.A, VIII.C and VIII.G of the final rule preambl e of the CPP and Chapter 3 of the GHG Mitigation Measures TSD for the CPP Final Rule supp orting the final CPP.

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

Commenters stated the Proposed Rule needs to be rew ritten to provide incentives for ratepayers to make investments that reduce CO2 emissions, such as conversion from liquid fuel to natural gas. Commenters asserted that States should be give n compliance credit for the full measure of CO2 emissions avoided by fuel conversion.

Commenters stated the Proposed Rule is unclear on h ow existing units that convert from liquid fuel to natural gas are to be addressed in any stat e plan to implement and attain the proposed CO2 emission target. Commenters stated that, in Ala ska, GVEA has a combined cycle unit in North Pole that currently operates on naptha. Comme nters stated that naptha is a liquid fuel, sometimes referred to as jet fuel, and thus the car bon emissions from this unit were excluded from the calculation of the EPA's proposed goal for Alaska. Commenters stated the North Pole combined cycle unit was designed for economic conve rsion to use of natural gas as fuel, should natural gas fuel become economically available in N orth Pole. Commenters stated that, in 2012, the North Pole combined cycle unit produced 423,592 MWh of energy and emitted 222,586.3 tons of carbon dioxide according to the EPA, which equates to an emission rate of 1,158.5 pounds/MWh. Commenters stated that, according to th e EPA, on average use of natural gas as
fuel would result in a 26.6% lower carbon dioxide e mission rate than jet fuel. Commenters stated that, assuming there is no heat rate penalty in con verting the North Pole combined cycle unit to natural gas, at 2012 energy production levels such conversion would result in a net savings of 59,208 tons of carbon dioxide for a net emission ra te of 850 pounds/MWh.

Commenters stated it appears that, as currently dra fted, the Proposed Rule would give Alaska credit for producing 423,592 MWh of energy from an affected EGU with an emission rate of 850 pounds/MWh. Commenters stated this would effectivel y ignore the emissions savings achieved between the 1,158.5 pounds/MWh actually achieved by the North Pole combined cycle unit in 2012, and the 1,003 pounds/MWh goal established by the EPA. Commenters stated that, in effect, in paying to get natural gas fuel to North Pole, GVEA ratepayers would be reducing their carbon dioxide emissions by nearly 30,000 tons, and getting no credit for that expenditure under the Proposed Rule.

Comment 44: Commenters stated the EPA should modify the propose d rule to allow existing OCGTs to be converted to CCGTs as part of a complia nce plan without making them subject to

the new NSPS for CCGTs.

Response 44: The EPA disagrees. These peaking units are not affe cted sources under the 111(d)

final rule.

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

Commenters stated that one option that could provid e Kentucky and OMU with significant carbon dioxide reductions more quickly than the con struction of new gas-fired generation is199

utilizing existing natural gas peaking units (OCGT) . Commenters stated that, under this approach, an existing OCGT would be converted to a combined cycle natural gas (CCGT) providing a lower carbon dioxide emitting source wi th a lower heat rate than either the OCGT or the coal-fired unit it is replacing. Commenters sta ted the proposed rule fails to provide any relief from the NSPS for new or modified NGCC units despit e the significant reductions in carbon
dioxide that can be achieved. Commenters stated the existing OCGTs have the benefit of already being interconnected with the electric transmission grid and thus an existing right-of-way; and already being connected to the interstate natural g as transmission system. Commenters stated that, in many cases the size of the natural gas pip eline feeding the OCGT is sufficient to deliver the required quantities of natural gas necessary fo r CCGT operation.

Comment 45: Building A number of commenters stated that the EPA should not have used nameplate capacity in calculating the capacity fact or in Block 2.

Response 45: The EPA agrees and has modified the calculations in Building Block 2 to use net capability rather than nameplate capacity. See sect ion V.A of the preamble of the final rule for the EPA’s response to this comment.

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

General

Commenters often pointed out that nameplate capacit y is the nominal maximum output of a generator, assuming a particular set of ideal, ofte n location-specific, operating conditions, including altitude, temperature, humidity and other factors that cannot be controlled by unit operators. Commenters noted that because of a varie ty of technical and ambient factors, power plants never achieve their technical maximum capaci ty. Commenters stated that net MWh generation divided by nameplate capacity conflates a measure of net generation with gross capacity and is not an acceptable metric.

Commenters suggested many alternative capacity metr ics.

Commenters applied a variety terms for other measur es of capacity that they believe would give more realistic values, including operating capacity , net summer capacity, summer net dependable capacity, actual tested ratings, net maximum depend able capacity, net dependable capacity, dependable capacity, minimum net generating capacit y, demonstrated net capacity, demonstrated maximum net capacity, unforced capacity, yearly sea sonal capacity average, average of the summer and winter capacities, net generating capaci ty, maximum monthly capacity, summer rated maximum net output, actual/rated capacity, an d average annual capacity. Commenters stated that seasonal capability considerations, as opposed to nameplate capacity, are also consistent with regional reliability standards. Com menters suggested the EPA utilize a weighted value of seasonal net capacity (60% summer and 40% winter) in calculations involving existing generation.

Commenters stated use of nameplate capacity makes t he state goals more stringent.200

Most commenters stated that using nameplate capacit y results in EPA adding an erroneously high level of gas-fired generation into a state's g oal calculation, thereby excessively reducing the amount of coal-fired generation included in determi ning a state's goal above and beyond what can reasonably be considered BSER. Commenters refer red to this as "phantom" capacity and generation that is not available for re-dispatch. C ommenters stated the EPA's arbitrary inflation of the amount of natural gas generation available f or re-dispatch may account for as much as twice as great a difference in total generation as EPA's entire building block one assumption of 6 percent. Commenters stated the EPA has failed even to acknowledge the implications of its use of nameplate capacity rather than net capacity, des pite the fact that an accurate assessment of the existing NGCC capacity actually available for re-di spatch is essential to developing an achievable Building Block 2 re-dispatch target. Com menters stated that capacity factors should be properly calculated by dividing a unit's net MWh generation by its summer net capacity because net capacity is the indicator of the amount of NGCC capacity available for re-dispatch purposes because it reflects the amount of energy t hat these units will actually be able to supply to the power grid. Commenters stated that, but usin g nameplate/gross capacity rather than actual/rated capacity, the EPA is relying on "phant om" megawatts. Commenters generally stated
that the EPA should correct for this "erroneous" ca lculation and remove this additional gas-fired generation from the re-dispatched NGCC generation e lement of the target in order to make its Proposal more workable. Commenters gave the followi ng examples:

• Commenters included Table 4 to illustrate the diffe rence in generation output using a 70 percent annual capacity factor with name plate capacity versus summer net capacity for eight states. According to the com menters, the table indicates that Minnesota would be required to meet a NGCC capacity factor greater than 90 percent based on summer net capacity, which the com menters characterized as both unequitable and unrealistic.

• Commenters stated that, while the proposed Rule sug gests there was NGCC capacity for Arkansas of 5,588 MW in 2012, the NGCC capacity number in 2012 was actually 4,804 MW. Commenters provided a table from EIA which shows the NGCC units in Arkansas with the nameplate ratin gs, the actual tested ratings
and the difference between the two numbers. Comment ers stated that the magnitude of this difference seriously undermines A rkansas' ability to meet its proposed 44% emissions reduction target, which was overly ambitious anyway.

• Commenters stated that the use of nameplate capacit y instead of net capacity results in (1) higher NGCC dilution of the CO2 emis sion rate goal, and (2) lower coal-fired generation contribution to the CO2 emiss ion rate goal than there should
be.

• Commenters stated that, to achieve the 70% capacity factor of the nameplate capacity that EPA uses for purposes of determining state goals, NGCC units would realistically have to operate well above a 70 % utilization rate with respect to its true, as-tested capacity. Commenters stated these utilization rates are wholly unprecedented and untested for purposes of meeting wholesale power grid demands and some facilities would be required to su stain actual utilization rates201 over 100% in order to functionally meet EPA's 70% g oal, which is obviously
unattainable.

• Commenters: As shown on Form EIA-860 for 2012, TVA' s John Sevier NGCC plant, the nameplate capacity for the plant's 4 uni ts totals 996.9 MW, but the summer net capability rating is 878 MW, a 12 percen t difference. Commenters included a table comparing differences in the demon strated net capacity and the nominal nameplate descriptor for Ohio, which commen ters indicated is typical for each state where NGCC capacity was identified by th e EPA.

• Commenters stated that, for Missouri, the net depen dable capacity of NGCC units is 1,881 MW as compared to 2,079 nameplate capacity

.

• Commenters stated the EPA's use of nameplate capaci ty in its Building Block 2 NGCC re-dispatch calculation means that in order to support the levels of redispatch assumed in EPA's proposed state goals, NGC C units would have to operate at statewide average capacity factors of 80 percent and above when accounting for operational reality - much higher th an the already- inflated utilization level of 70 percent that EPA assumes, b ut fails to demonstrate is achievable. Commenters provided the following examp les: in Florida, the difference in available generation for re-dispatch from 70 percent utilization of all NGCC units in the state based on the summer net cap acity of 23,784 MW versus their existing nameplate capacity of 29,485 MW is 3 5,054,309 MWh; the average annual capacity factor of all NGCC units in Florida would need to reach 87.0 percent to produce this amount of generation; and t he average capacity factor of
NGCC units in North Carolina would need to be 81.1 percent to produce the number of MWh the EPA has assumed for Building Bloc k 2 re-dispatch for the state. Commenters stated that, because these value s are statewide averages and many units cannot reach such high levels of utiliza tion, many NGCC units would have to operate at even higher annual capacity fact ors, levels that simply are not
sustainable.

• Commenters added that because the Proposed Rule ina ppropriately relies on nameplate capacity, it overestimates actual availab le net summer NGCC capacity by more than 33 GW (13 percent) and net winter NGCC capacity by more than 17 GW (7 percent) (referring to Table 1 in the comment ). Commenters stated that New York estimates the annual average for the State 's NGCC units (Summer Capacity and Winter Capacity) to be approximately 8 5% of nameplate capacity.

• Commenters stated that, in the case of New Mexico, for example, the total nameplate rated capacity of the NGCC units relied u pon by EPA in the building block 2 calculation is 1,662 MW, whereas the total summer net capacity is only 1,390 MW.

• Commenters stated that nameplate capacity does not reflect the balance of plant equipment and systems, auxiliary load requirements, or site-specific conditions such as ambient temperature, humidity or elevation, all of which can influence the202 actual net capability or rating of the unit. Commen ters stated that the EPA's suggestion that weather adjusted capacity data are not reported for the fleet
is incorrect as both summer and winter net demonstr ated capacities are reported annually to the Energy Information Agency and are s ummarized in the publically accessible EIA-860 report.

• Commenters provided Table 1, which shows the differ ence between the generation capacities of NGCC located within Arizon a assumed by the EPA compared to the actual available capacities of thes e units, and stated that the
EPA's failure to account for this situation reduces net NGCC generation capacity by nearly 2,000 MW relative to the nameplate rating s that are actually available during peak demand periods.

• Commenters stated that, in the case of MidAmerican' s Greater Des Moines Energy Center, by using nameplate capacity, the uni t's capability is overestimated by 17% (576 MW of nameplate capacity versus 492 MW of accredited capacity); as a result, a 70% capacity factor for this unit ac tually results in a net capacity factor of 82% - a significant difference.

• Commenters referenced a November 2014 James Marchet ti report and stated that (1) the EPA included a number of NGCC plants that w ere not available in 2012; (2) some of the plants used by EPA in calculating N GCC potential were simple cycle combustion turbines, and (3) the EPA ignored the constraints that grid operators and or state public service commissions m ay impose on the increased dispatch of NGCC plants by assuming all could reach a 70 percent capacity
factor.

• Commenters stated the capacity used by EPA is overs tated by 1,255 MW in the winter and 1,897 MW in the summer, resulting in an overestimate by EPA of the amount of energy that can be produced from the NGCC units.

• Commenters stated that for Deer Creek Station, EPA should recognize that it cannot generate more than 300 MW at any time and ad just the assumed reductions from application of Building Block 2 in South Dakota accordingly.

• Commenters suggested the EPA use net capacity from the National Electric Energy Data System (NEEDS), which is what EPA used when conducting the IPM modeling runs for the Proposed Rule (NEEDS v 5. 13). Commenters stated that, for Arkansas, Louisiana, Mississippi, and Tex as, peak power consumption occurs in the summer months; therefore, net summer capacity from NEEDS v 5.13 should be used in goal setting.

• Commenters stated that, in place of nameplate capac ity, EPA should use an average of NGCC units' summer and winter capacity r atings (which are typically filed with the appropriate electric reliability reg ional entity) when calculating the emissions impact of building block two. Commenters stated the average of the summer and winter reliability capacity ratings for South Carolina's NGCC units is203 15.7% lower than nameplate ratings, which results i n a 2012 NGCC capacity factor of 53%, rather than the 45% calculated by EP A.

• Commenters stated that, in Florida the difference b etween available NGCC generation from 70% utilization of the actual summe r net capacity of 23,784 MW and the existing nameplate capacity of 29,485 MW is a staggering 35,054,309 MWH. Commenters stated that the consequence of this difference is that, in Florida, NGCC units would have to operate at an 86. 8 percent capacity factor based on their true availability represented by act ual summer net capacity, to meet energy needs. Commenters cited the Marchetti Report and stated that, to support the levels of re-dispatch assumed in the Proposed R ule's state goals, NGCC units in much of the nation would have to operate at capa city factors far higher than 70 percent: in Arkansas, units would have to run at 83 .9%; in North Carolina, 80.9%; and in Texas, 80.1%. Commenters concluded that the use of nameplate capacity significantly distorts the actual generation that c an be provided by NGCC units running at 70% capacity.

Data is available in Form 860.

Commenters stated that the EPA acknowledges that ca pacity data accounting for weather/temperature conditions would be preferable, but states that it relied on nameplate capacity because "adjusted capacity by the hour/min ute" was unavailable across the affected
NGCC fleet. Commenters noted that the EPA states in its GHG Abatement Measures TSD that it used nameplate capacity instead of net capacity because hour/minute net capacity data are not reported, but stated that this is not justification for the EPA to have calculated capacity factors as
it did. Commenters noted that net summer and winter capacity data are reported in EIA Form 860 for the vast majority of NGCC units, and the EP A should have used these data in its evaluation of NGCC re-dispatch opportunities instea d of nameplate capacities.

Commenters stated that the Agency "properly" used 2 012 summer net capacity from each state's nuclear fleet in determining each state's nuclear c apacity "at risk". Commenters stated that the EPA actually compares the nameplate and summer capacities for each existing electric generation source in the Regulatory Impact Analysis for the proposed rule, and that on a national basis for units combusting natural gas the summer c apacity is 13% less than the nameplate capacity (422,364 MW vs. 485,957 MW). Commenters no ted that EPA's IPM model uses the data from Form 860 (IPM Documentation at 4-2) and t hat the RIA also notes that EPA analyzed net summer capacity from Form 860 in an analysis of existing electricity generation (RIA at 2-1 to 2-2; IPM Documentation at 4-4). Commenters state d that consistent with these other pieces of its analysis, the EPA should utilize Form 860 to de termine state NGCC capacity. Commenters stated that the widespread recognition and use of n et seasonal capacity, including the rationale underlying EPA's own NEEDS database, renders EPA's use of nominal nameplate capacity for purposes of evaluating available underutilized NGCC capacity arbitrary and unreasonable. Commenters stated that any use of historic capacity factor data to assess the potential for increased utilization of NGCC must, first and forem ost, be calculated correctly and it must be evaluated in context with the broad scope of other factors that may influence the potential for greater operation.204

Recalculate at a higher capacity.

Commenters stated that, while the EPA has failed to demonstrate that its Building Block 2 target of re-dispatching existing NGCC units up to an over all capacity factor of 70 percent by 2020 is adequately demonstrated or achievable, what the EPA really must demonstrate, but has not, is that re-dispatching existing NGCC units to a much h igher capacity factor, in the 80 percent or higher range, based on the use of summer net capaci ty and a proper calculation of capacity factors, is adequately demonstrated or achievable a nd can be accomplished by 2020.

Commenters stated that the basis of the capacity fa ctor calculations should be the average annual capacity instead of nameplate capacity, but differe d from other comments by advocating that the EPA consider re-dispatching affected NGCC units to a higher fleet-wide capacity factor than currently contemplated by the proposal on this basi s. Commenters noted that this recommendation is contingent on the EPA also adopti ng its recommendation pertaining to inclusion of new natural gas capacity in the buildi ng block, which is included elsewhere in this document. Commenters stated that the average annual capacity is derived from the net summer capacity and the net winter capacity of the affecte d NGCC plants, since these values indicate the maximum load a generator can support at the point o f interconnection during the respective

season.

Net capabilities decline over time.

Commenters stated that plant capacity will continua lly decline due to plant degradation, a factor
U.S. EPA also failed to consider. Commenters stated that most combined cycle resources are relatively new and their net ratings are based on n ew and clean conditions. According to the commenters, net capabilities will decline over time as a consequence of combustion and steam turbine degradation, so the EPA's analysis should f ocus on the net MDC rating and available dispatchable energy that has been demonstrated to b e achievable.

Use of duct burners.

Commenters stated that duct burners may be operated when determining summer and winter peak ratings, and the amount of heat input from duc t burners can be significant. Commenters said that the EPA should use summer capacities with out duct burner operation for purposes of goal setting as duct burners decrease the efficienc y of a plant and therefore do not fit the Agency's ideal NGCC operation model.

State regulators use net capacity.

Commenters stated that the EPA errs in using a gene rator's nameplate capacity in the capacity factor Block 2 calculations. Commenters suggested t he EPA should use the actually measurable net capacity instead of the theoretical nameplate c apacity in calculating reductions under Block 2. Commenters stated that, when referring to capaci ty, system planners and regulators refer to the real-world, actually available capacity, not the th eoretical, under-perfect-design-conditions nameplate capacity used by the EPA. Commenters note d that state regulators use net capacity incorporating summer and winter capacity ratings wh en determining reserve margins for planning purposes.205

Summer peaking capacity is key in some areas.

Commenters stated that Arizona and other states in the desert Southwest are highly summer peaking and, by using the annual capacity factor, E PA misses this fact and effectively assumes energy from the non-summer months could be used in summer months to displace coal. Commenters stated that the only correct way to dete rmine the amount of coal generation that could be displaced by NGCC capacity is through the use of an hourly or even sub-hourly generation dispatch model which would take into acc ount all of the appropriate generation dispatch constraints such as regulation reserves, s pinning reserves, ramp rates, etc. Commenters
stated that the result of this error leads to EPA's unrealistic assumption that all of Arizona's coal generation could be replaced by NGCC capacity in th e summer, and that Arizona's utilities could still meet their load obligations. Commenters state d that an examination of the 2012 actual hourly data of the affected generating units using data from EPA's Clean Air Markets Division in 2012 demonstrates that the NGCC generation is not a dequate to displace all of the coal generation. Commenters stated this data also demons trates that the capacity factor of the NGCC generation in the summer months is about double the annual average of 27 percent used by EPA in its goal setting. Commenters stated that, while the EPA may not have ready access to hourly data or may lack the capability to perform an hourl y dispatch, if EPA cannot perform the hourly analysis, then EPA must at least use the maximum mo nthly capacity factor for NGCC units. Commenters stated that monthly net energy is readil y available to EPA to calculate these capacity factors, and EPA's failure to use this rea dily available data is unreasonable.

Commenters stated that, because the Proposed Rule i nappropriately relies on nameplate capacity,
it overestimates actual available net summer NGCC c apacity for Pennsylvania by 1,374MW and net winter NGCC capacity by 999MW. Commenters state d that forcing PPAs be to be
dishonored would run afoul of the Contracts Clause. Commenters stated that, where compliance would require PPA abandonment, credit markets would tighten causing economic impacts that EPA has not analyzed.

Suggested recalculation method.

Commenters stated the EPA should adjust the megawat ts of NGCC capacity it presumes are available for re-dispatch to account for the shortc omings in its capacity calculations. Commenters stated the EPA should conservatively det ermine capacity based on net dependable summer NGCC capacity, and determine a metric to do so for the few instances where net summer capacity information is unavailable; the EPA should then further reduce presumed NGCC capacity by accounting for permitting restrict ions on operation, merchant NGCC capacity, and NGCC that is or must be available to support existing or future renewable energy.

Comment 46: Commenters expressed concerns regarding availabilit y and capacity factors.

Response 46: The EPA disagrees and we believe address thse conce rns regarding NGCC unit availability and capacity factors. In response to additional analysis and many comments, we have modified the proposal and RIA. The 111(d) fina l rule requires that states develop plans that

establish emission standards for affected EGUs. We are providing states with substantial206

flexibility as to how they structure those plans to achieve the 111(d) requirements. The flexibility includes, for example, the choice of approaches, tr ading, time to develop plans, additional time before the start of the interim performance period (postponed from 2020 until 2022), and the ability to shift emission rate achievement between performance periods. The Building Blocks are not prescriptive, and states may consider local cir cumstances as they develop their plans, including system reliability, fuel diversity, the n eed for ancillary services other regulatory requirements and infrastructure. The 111(d) final r ule does not require every individual NGCC to meet a CO2 emission performance rate, but rather th e 75 percent capacity factor was used in the calculations to establish a rate. See sections V.D, VIII.A, VIII.C and VIII.G of the final rule preamble of the CPP and Chapter 3 of the GHG Mitiga tion Measures TSD for the CPP Final Rule supporting the final CPP.

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

Commenters stated that an NGCC's average annual ava ilability does not equate to a unit's ability to maintain an annual 70 percent capacity factor in an integrated electricity system. Commenters stated the EPA has inappropriately conflated a unit 's annual availability and capacity factor. Commenters stated that annual availability is "the percentage of time that a generating unit is available to provide electricity to the grid." Comm enters stated annual availability can also be characterized as the "total number of hours in a ye ar when the unit was in an active state." Commenters stated that, even though a technology ma y have a high annual availability, it may be constrained from generating by other factors, such as resource and fuel limitations, reliability needs, transmission constraints, and economics. Com menters stated that a technology's capacity factor captures the other factors that may be prese nt during certain years. Commenters stated that, for example, EPA's annual availability assump tion for simple-cycle combustion turbines (CTs) in its Base Case v.5.13 is 85 to 93 percent; however, capacity factors for these units are significantly lower due to the operational capabili ties of these units and their role in an integrated electric system. Commenters stated that, by maintai ning unique operational capabilities (e.g., high annual availability coupled with quick ramping capability), NGCCs are frequently called upon to provide ancillary services and balancing ar eas on a moment's notice frequently requires generation for ancillary services. Commenters state d that, although an NGCC may frequently operate to meet ancillary services, this does not m ean the unit is operating at a high capacity factor (e.g., 70 percent). Commenters stated that, while the EPA surveyed 2012 data for 1,800
NGCCs and concluded that the NGCC fleet had an aver age capacity factor between 44 and 46 percent, the EPA erred in assuming "significant pot ential for re-dispatch" was available because the average capacity factor was less than the techn ology's annual availability.

Commenters stated that, by focusing its assessment on the availability and capacity factors of the existing NGCC fleet, the EPA not only narrows its r eview to irrelevant (availability factors) and inaccurate (capacity factors) information, but also ignores other more significant factors that influence the utilization of a unit. With respect t o the availability factor, commenters did not agree that availability refers to the maximum amoun t of generation that could be expected from a given source, and that more than 80% of the existin g NGCC capacity are able to achieve to achieve high availability factors. Commenters also did not agree that the capability of NGCCs to operate at capacity factors of 70% and greater is i ndicated, in part, by statistics on the average207

availability factor of NGCCs, which in the U.S. gen erally exceeds 85%, and can exceed 90% for selected groups.

Commenters stated that the availability factor is t he percentage of time that a unit is available to provide energy to the grid, and is an indicator of the reliability of the unit and associated outage rates and, in terms of assessing the potential for increased utilization of the NGCC fleet, the availability factor is of trivial value. The commen ters stated the fact that a unit is available does not automatically imply that it can generate all of its demonstrated capacity; for example, a hydroelectric unit or wind turbine facility may be available, but water levels or wind conditions may be insufficient for those units to achieve thei r maximum potential output. Commenters stated the operation of every type of generation re source is affected by any number of factors that determine not only if the unit is operated when it is available, but also how it is operated when available; therefore, the issue is not whether the unit has a high availability factor, as nearly all units and types of generation achieve that regularl y, rather, the issue is how the unit operates when it is available, which is a more complex evalu ation given the number of dynamic technical, regulatory, economic, and market factors that must be weighted.

Commenters stated that, although capacity factor is one metric to assess how often units operate when available, consideration of historic capacity factors in a vacuum is insufficient for evaluating the potential increased utilization that may be achievable by a unit. Commenters noted a table from NERC which summarizes the availability factor and net capacity factor from 2009- 2013 for various generation resources and stated th at all have high availability factors, but for various reasons have different capacity factors. Co mmenters suggested that, if the EPA's goal is the re-dispatch of low-carbon emitting generation r esources, then using the NERC table shows that hypothetically existing combined cycle units, as well as oil steam boiler, simple cycle turbine, and hydroelectric units are all underutili zed and should all be demonstrably redispatched at higher rates to offset higher emittin g coal units. Commenters stated this overly simplistic scenario fails to consider the numerous factors that influence how units are dispatched and the potential amount of increased utilization t hat may be achievable.

Comment 47: Commenters stated that, for areas that have high i ntegration of renewable energy, like Oklahoma, the EPA fails to recognize that NGCC load factors are lower because they are utilized to regulate around variable energy resourc es such as wind and solar.

Response 47: The EPA disagrees. In response to additional analys is and many comments, we have modified the proposal and RIA – the establishm ent of CO2 emission reduction standards is regionally based. The EPA recognizes the balancing role performed by NGCC capacity. The 111(d) final rule requires that states develop plan s that establish emission standards for affected EGUs. We are providing states with substantial flex ibility as to how they structure those plans to achieve the 111(d) requirements. The flexibility in cludes, for example, the choice of approaches, trading, time to develop plans, additional time bef ore the start of the interim performance period (postponed from 2020 until 2022), and the ability t o shift emission rate achievement between performance periods. The Building Blocks are not pr escriptive, and states may consider local circumstances as they develop their plans, includin g system reliability, fuel diversity, the need208

for ancillary services other regulatory requirement s and infrastructure. The 111(d) final rule does not require every individual NGCC to meet a CO2 emi ssion performance rate, but rather the 75 percent capacity factor was used in the calculation s to establish a rate. See sections V.D, VIII.A, VIII.C and VIII.G of the final rule preamble of the CPP and Chapter 3 of the GHG Mitigation Measures TSD for the CPP Final Rule supporting the final CPP.

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

Commenters stated that studies by MISO, ERCOT, and the NREL demonstrate that the displacement of NGCC by wind ranges from 32.6 perce nt in the MISO region to 83 percent in the West, and 87 percent in ERCOT. The commenters s tated the existing "head room" between historic NGCC capacity factors and their full capac ity cannot be used both for re-dispatch and continued support of variable generation resources. This headroom is what allows the integration of variable generation resources like wind and sola r.

Commenters added that, if EPA continues to mandate re-dispatch, Western Farmers urged EPA to recalculate emission rate goals utilizing a 50 p ercent "displacement factor" in calculation of emission rate goals. Commenters suggested an estima te for wind displacement for existing NGCCs of 50 percent is reasonable. Commenters state d that applying a displacement factor would provide Oklahoma with some flexibility to con tinue operation of NGCCs in concert with renewable energy resources, and encourage the conti nued integration of renewable energy

resources.

Comment 48: Commenters recommended allowing states to use multi ple, representative data years, rather than 2012.

Response 48: The EPA generally disagrees. See section VI.D. of the final rule preamble of the CPP for EPA’s response to this comment.

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

Commenters stated that the 2012 data year, or any o ther specific year, selected for establishing state emission rates is not representative of norma l plant operations. The commenters suggested the EPA select multiple years that reflect operatio nal variability to establish a baseline in which to develop emission targets. The commenters asked, for example, how does a state comply in a year where its only nuclear generator is on outage but said unit was operating during the base year of 2012? Commenters stated that instances such as this need to be reflected in the baseline
data.

Commenters stated that the EPA improperly calculate d the number of hours in Building Block 2
and should correct its calculations. Commenters ind icated that the EPA's use of a leap year to
calculate the hours that must be run to achieve a 7 0 percent capacity factor was an erroneous assumption. The commenters asserted that the number of hours used to determine what megawatt hours are run by the fleet at 70 percent capacity f actor should be set using either a typical year or the average of hours per year over four years (8,76 0 or 8,766). According to the commenters, despite the theory the EPA uses to take the generat ion in 2012 and divide it by the hours in 2012209

(because there is only one year of data and some pl ants may not have been functioning normally), the extra 24 hours of data could influen ce a state's requirement by up to 0.002 percent compared to a normal year, which in some states cou ld amount to several hundred thousand MWh. Commenters gave the example of Texas, in which the amount of NGCC generation calculated at 70 percent capacity factor over 8,784 hours is 230,875,142 MWh while at 8,760 it could be 201,331,956 MWh. Commenters stated that th e only way for the EPA to solve this problem is to allow states to use multiple, represe ntative data years. The commenters added that the Agency appears to attempt to address this in th e NODA, and the commenters encouraged the EPA to allow states to use multiple years in settin g baseline requirements as a solution for this
issue.

Comment 49: Commenters stated that the EPA should calculate the CO2 emission impacts resulting from increased dispatch to existing NGCC power plants using different values than those proposed: no more stringent than a NSPS rate; equivalent to the EPA's proposed standards for new, modified or reconstructed units; multi-yea r; state-specific; incremental, or unit-specific.

Response 49: The EPA disagrees. We believe the 111(d) final rule clarifies the treatment of NGCC units. In response to additional analysis and many comments, we have modified the proposal and RIA – the establishment of CO2 emissio n reduction standards is regionally based. The 111(d) final rule requires that states develop plans that establish emission standards for affected EGUs. We are providing states with substan tial flexibility as to how they structure those plans to achieve the 111(d) requirements. The flexi bility includes, for example, the choice of approaches, trading, time to develop plans, additio nal time before the start of the interim performance period (postponed from 2020 until 2022) , and the ability to shift emission rate achievement between performance periods. The Buildi ng Blocks are not prescriptive, and states may consider local circumstances as they develop th eir plans, including system reliability, fuel diversity, the need for ancillary services other re gulatory requirements and infrastructure. The 111(d) final rule does not require every individual NGCC to meet a CO2 emission performance rate, but rather the 75 percent capacity factor was used in the calculations to establish a rate. See sections V.D, VIII.A, VIII.C and VIII.G of the fina l rule preamble of the CPP and Chapter 3 of the GHG Mitigation Measures TSD for the CPP Final R ule supporting the final CPP.

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

No more stringent than a New Source Performance Sta ndard.

Commenters stated the EPA should assume an emission rate for re-dispatched existing NGCC units that is no more stringent than a New Source P erformance Standard emission rate. Commenters stated that, in the development of BSER, EPA's calculations utilize the 2012 actual emission rate for all existing NGCCs re-dispatched to a 70% capacity factor, which results in a national-average emission rate for these units of 8 65 lb CO2/MWh. Commenters stated this average emission rate is significantly more stringe nt than the proposed greenhouse gas emission standard for new sources (79 FR 1430). Commenters s tated an existing source performance standard should not be more stringent than a new so urce performance standard for the same210

pollutant. Commenters suggested the EPA adjust Buil ding Block 2 so that existing NGCCs are assumed to operate at an emission rate of 1,000 lb CO2/MWh. Commenters stated this emission rate is a more reasonable representation of what ex isting NGCC units can achieve on a long-term basis, especially when operating at much higher cap acity factors and will likely need to utilize less efficient duct firing capacity to achieve thes e new capacity factors.

Commenters stated the existing NGCC units should no t be held to a performance standard more stringent that the performance standard for new NGC C units. Commenters stated that the EPA used a single year to depict the carbon emissions r ates for existing NGCC units and, apparently, the EPA assumed all future years will be consistent with the single, baseline year. Commenters stated this assumption is not necessarily true for at least a couple of reasons: (1) equipment wears
over time and efficiencies are lost over the life o f the equipment and (2) the single baseline year is not necessarily representative of future operati ons. Commenters stated that, as more renewable generation comes on line, existing NGCC units will be doing more load following and, when operating in a continuous load following manner, ca rbon emission rates will creep higher. Commenters stated the EPA recognized that equipment wears over time when it proposed the
carbon emission rate standards for new NGCC units. In that proposal, commenters stated the EPA states "These values represent the emission rat es that modern high efficient NGCC facilities
located in the U.S. would be able to maintain over its life (emphasis added)" (79 FR 1487).

Equivalent to EPA's proposed standards for new, mod ified or reconstructed units.

Commenters recommended the use of NGCC emission rat es for setting emission rate goals that are equivalent to EPA's proposed standards for new, modified or reconstructed units. Commenters stated that, while the EPA uses state sp ecific average NGCC emission rates to calculate emissions in the goal setting formula for Building Block 2, for most states, this 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 section 111(b). Commenters stated the unreasonable and unrepresenta tive 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 stated that the EPA chose the proposed N SPS limit based on a review of emission rates achieved by NGCC units constructed since 2000 and reported to the Clean Air Markets program. According to the commenters, the EPA state d in the preamble that the 1,000 lbs/MWh emission rate could be met by 95 percent of all com bustion turbines constructed since 2000. Commenters stated that the EPA does not present a s imilar analysis of emission rates from existing NGCC units for this existing EGU rule, nor does it reference the data collected and evaluated for the proposed new source rule.

NGCC units that did not operate in 2012.

Commenters stated that, while the EPA assumed that re-dispatched NGCC units would have the same emission rate as NGCC units that operated in 2 012, this ignores the likelihood that NGCC units that did not operate in 2012 had higher heat rates (or lower efficiency) and hence higher emission rates than units that did operate. Comment ers stated that, in Texas, EPA assumed an emission rate of 837 pounds CO2 per megawatt-hour f or re-dispatched NGCC units, which211

implies an average heat rate of 7.17 MMBtu/MWh. Com menters stated that, in NERA's modeling database, all existing NGCC units in Texas that increase their generation in response to a 70% capacity factor constraint have heat rates in excess of 7.17 MMBtu/MWh, and some are as high as 9.6 MMBtu/MWh. Commenters stated the EPA's block 2 analysis is arbitrary and capricious as to Texas.

Some fossil-steam generation is replaced by renewab le generation.

Commenters stated that the EPA should assume that a t least some of the displaced fossil-steam generation is replaced by renewable generation rath er than assuming that the fossil-steam generation curtailed under Block 2 will all be repl aced by existing NGCC capacity in the state at
the current emission rates of those units. Commente rs stated that it is also reasonable and appropriate to require some level of HRI for NGCCs, especially high-emitting existing NGCCs. Commenters suggested the EPA should base emission l evels for any NGCC replacement capacity that it assumes on reasonable HRI at those units in determining Block 2 emission rate
reductions.

Multi-year averages.

Commenters recapped the method that the EPA used to calculate each state's NGCC emission rate and asserted that the EPA's approach establish es the average of all the turbines existing in a state, but does not reflect the actual capabilities of any of them. According to the commenters,
when there are a small number of units that have si gnificantly different capacity factors, the state average can be skewed by one unit with a high capac ity factor. Commenters suggested that the baseline conditions used to establish the goals sho uld be a multiyear average, which would better reflect actual operating conditions at each NGCC us ing EPA's proposed approach to calculating
the NGCC emission factor. Commenters added that usi ng a multiyear average the emission rates for each NGCC produces a state NGCC emission rate t hat better reflects the characteristics of the turbines in a state's NGCC fleets. Commenters reque sted that the EPA revise its calculation of NGCC emission rates consistent with a multiyear bas eline approach and set an emission rate for all existing, affected NGCC units in the United Sta tes that is no lower than the emission limit in
lbs CO2/MWh that the EPA finalizes for new NGCC uni ts.

State-specific issues.

Commenters stated the EPA has calculated different emissions rates for existing NGCC units in each state for Building Block 2, using 823 lbs CO2/ MWh for the emission rate for the existing NGCC units in Washington. Commenters indicated that based on the analyses done in Washington for establishing the state's power suppl y/power plant GHG emission performance standard and recent BACT decisions, this 823 lbs/MW h value would be appropriate as a BACT
emission limitation - this emission rate is lower t han could be expected of some, but does not reflect the capabilities of all existing NGCC units . Commenters stated that Washington State recently evaluated and completed rulemaking setting an emission standard for new power plants,
which determined that an emission rate of 970 lbs t otal GHG per MWh (equivalent to 922 lbs CO2/MWh) was an appropriate standard for new power plants to meet throughout their operating lifetime. Commenters also noted that the recently p roposed NSPS for new EGUs proposed an212

emission limitation for CO2 from new NGCC units of 1,000 lbs CO2/MWh, and that the EPA discussed and requested comment on a range of limit ations of 950-1,100 lbs/MWh.

Commenters stated that the EPA's unreasonable goals for Arizona represent an emissions rate for existing natural gas that is much lower than what t he Agency says is achievable for brand new natural gas units.

Commenters stated that, even assuming that within a period of five years, Texas Municipal Power Agency could design, fund, build a gas pipeli ne, and convert combustion/boiler systems at Gibbons Creek, it would still not meet EPA's requir ement of reducing CO2 emissions to 853 lbs/MWh by the year 2020, let alone 791 lbs/MWh by 2030. Commenters stated the current rate
of CO2 emissions at Gibbons Creek is over 2200 lbs. per megawatt-hour (MWh). Commenters stated a complete conversion of Gibbons Creek from coal-fired to gas-fired generation would reduce CO2 emissions to approximately 1,220 lbs/MWh

.

Incremental emission rate.

Commenters stated that, instead of using the averag e baseline year NGCC CO2 emission rate,
EPA should use the incremental NGCC CO2 emission ra te. Commenters stated that using the average baseline year underestimates the additional NGCC CO2 emissions due to the redispatch. Commenters explained that most of the mos t efficient, lowest emitting units are already generating at or near the basis 70 percent capacity factor, whereas the units that would actually be re-dispatched and contribute the most increase i n net generation are the less efficient, higheremitting units. Commenters stated the incremental e mission rates of these higher-emitting units
must be used to estimate the additional CO2 emissio ns from the re-dispatch. Commenters stated that, to compute the state average incremental NGCC CO2 emission rate, an analysis of the eGRID baseline data at the generator level is requi red. Commenters stated that after appropriately determining the generator net capacit y ratings, EPA must calculate and review generator by generator the baseline capacity factor , CO2 emission rate, and potential contribution of each to the re-dispatch.

Commenters recommended the following procedure to c ompute the state average NGCC redispatch incremental CO2 emission rate and noted th at, based on this computation, the
incremental NGCC CO2 emission rate for Florida is 9 96 lb/MWh-net, as opposed to the average
rate EPA used of 864.

• For each NGCC generator, calculate the baseline yea r net capacity factor using the eGRID net generation and newly determined net c apacity rating. Subtract this number from 70 percent to determine the net capacit y factor increase (or decrease) available. If a generator was operating a bove a 70 percent net capacity factor in the baseline year, the FCG-EC believes th at it is appropriate to adjust this downward to the 70 percent target for the purp ose of calculating the goal. For each NGCC generator, calculate the baseline year av erage CO2 emission rate by dividing the CO2 emissions (in tons) by the net gen eration MWh, times 2,000 to convert to pounds. Some due consideration is needed with respect to how representative the baseline period is for low capac ity factor generators. For units operating at a low capacity factor, efficiency can be poor due to unit cycling,213 operating at low load points, and accumulated off-l ine reserve auxiliary power. Some of the NGCC generators in the eGRID baseline d ata have calculated CO2 emission rates as high as 3000+ lb/MWh-net at a thr ee percent to five percent capacity factor. It is reasonable to assume that su ch high CO2 emission rates would improve drastically if the unit was actually operated at 70 percent capacity factor. Therefore, the FCG-EC suggests a capacity f actor test to determine
whether the baseline CO2 emission rate should be li mited. The suggested test is: (1) if the baseline year net capacity factor is gre ater than 30 percent, then use the calculated baseline year CO2 emission rate; the FCG -EC believes that a 30 percent capacity factor is sufficient for an NGCC u nit to have achieved a reasonable and steady operating profile and (2) if the baseline year net capacity factor is between 0 percent and 30 percent, then li mit the baseline year CO2 emission rate to a maximum of 1,250 lb/MWh-net; thi s is a reasonable proxy for less efficient units, given the alternative not to limit the emission rate at all.

• For each NGCC generator, calculate the number of an nual net generation MWh available for re-dispatch using the net capacity fa ctor increase (or decrease) available, and the net capacity rating of the unit. Again, for units already operating above a 70 percent capacity factor, this will be a negative number (reduced net generation). For each NGCC generator, calculate the annual CO2 emissions increase (or decrease) by multiplying the baseline year limited CO2 emission rate by the number of annual net MWh avail able for re-dispatch (again, increase or decrease). For each state, accumulate t he total number of annual net generation MWh available for re-dispatch from all N GCC generators, and the total annual CO2 emissions changed from all NGCC ge nerators.

• For each state, divide the accumulated annual CO2 e missions by the accumulated annual generation available. This is the incrementa l NGCC CO2 emission rate. Use this in place of the baseline year average NGCC CO2 emission rate when computing the CO2 emission increase from NGCC units due to the Building Block 2 re-dispatch.

Evaluate unit-specific data to determine emission r ates.

Commenters did not agree with the use of the averag e NGCC emission rate for each state, based on actual 2012 operation, for all NGCC re-dispatchi ng. Commenters noted that the average emissions rate following re-dispatching would be di fferent because the existing NGCC that have significant availability also have higher emission rates. Commenters provided a table which delineates that the existing NGCC that have signifi cant availability also have higher emission rates. Commenters stated this means that, should th e EPA require them to operate more by redispatching to these under-utilized existing NGCC, the average emissions rate would necessarily increase. Commenters noted the table uses operating hours reported through Clean Air Markets Database (CAMD) to calculate availability (with 8,7 84 total hours in calendar year 2012) and the
emission rate values are referenced from EPA's calc ulations (20140602tsd-plant-level-date-unitlevel-inventory_0.xls). Commenters stated this is n ot a unique component of Florida's 2012 operation, rather it is a logical outgrowth of re-d ispatching. Commenters stated that, as the EPA acknowledges, "electricity generation conforms to t he principle of least-cost economic dispatch",214

this means that those NGCC with better heat rates w ill be dispatched first. Commenters stated that, if EPA is requiring more generation from NGCC s, the under-utilized units will be those with poorer heat rates, and correspondingly higher CO2 emission rates.

Commenters stated the challenge with basing a futur e limit (a potential to emit constraint) on past actual emissions from a sampling of sources, i s that the understanding of all potential impacts to actual emissions must be fully understoo d and considered. Commenters stated that, in the development of standards that represent the emi ssions limit "achieved in practice" under Section 112 of the Clean Air Act, the EPA justifiab ly adds "variability" to actual emissions data. Commenters stated that, in the development of this rule, it appears that the EPA made no such attempt, and took a snapshot of actual annual data as appropriate for re-defining potential emissions from an entire power generation sector. C ommenters stated the EPA must consider whether or not the units relied upon represented mo dern, low-emitting designs, or where their generation profile fit within the industry. Comment ers stated that, even unit-specific information that impacts efficiency and emissions rates for whi ch EPA already has data were overlooked.
Commenters stated the EPA must evaluate which units utilized add on pollution controls (e.g., selective catalytic reduction), which can significa ntly lower oxides of nitrogen (NOx) emissions, albeit at the expense of a slightly poorer heat rat e (and higher CO2 emissions rate).

Commenters stated the EPA's heat rate assumption fo r NGCC units (6,430 btu/kWh) is in error and is below real world, net operating conditions. EPA's heat rate assumption is actually below what new, high efficiency NGCC plants currently und er construction can achieve on a net basis.
EPA should have used historical net heat rates of t he actual units that will be dispatched to meet the target in determining the level of emission red uctions possible under Building Block 2, similar to the procedures used for coal units.

Comment 50: Commenters addressed provisions in the CPP related to emission rates and useful thermal output (UTO).

Response 50: The EPA generally agrees and has modified the treat ment of useful thermal output. Useful thermal output is not included in t he final rule in determining goals. See sections V.D, VIII.A, VIII.C and VIII.G of the final rule pr eamble of the CPP and Chapter 3 of the GHG Mitigation Measures TSD for the CPP Final Rule supp orting the final CPP.

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

According to commenters, the CO2 emission rates for 82 other NGCC units were calculated using the UTO-related energy output, and the commen ters provided a summary of the UTO impact to the emission rates calculated for all of these facilities Appendix B to the comments. Commenters stated that eight facilities had CO2 emi ssion rates that were even lower than the value EPA calculated for Pine Bluff, which the comm enters summarized in a table included in
the comments. Commenters also noted that while a si ngle co-generation facility reduced the overall state NGCC fleet CO2 rate in Arkansas by 8 percent, other states have multiple cogeneration units that may have much more significan t impact. As an example, commenters stated that the EPA identified 14 co-generation facilities in Texas whose CO2 emission decreased on215

average by 34% with the application of the UTO ener gy output; commenters summarized these
results in a table in the comments.

Commenters stated that the Building Block 2 calcula tions for 24 states included the addition of UTO related energy output when determining the base line NGCC CO2 emission rate. According to the commenters, the impact of the added UTO ener gy output can be significant as is most
evident in the reduction in the baseline NGCC CO2 e mission rates for Louisiana (-21%), Michigan (-19%), Washington (-17%), and Texas (-14% ).

Commenters reviewed the EPA's adjustment made for c ogeneration units to determine useful thermal output (UTO) and stated the results of thes e calculations indicate that the EPA has overestimated the UTO available from these units for re -dispatching as electricity generation. .
Commenters stated the calculated emission rate base d on net energy output for some of these units is extremely low; e.g., Auburndale Power Part ners and Orange Cogeneration Facility have
calculated emission rates of 724 lb/MWh and 755 lb/ MWh, respectively. Commenters stated the EPA is calculating an emissions rate from 20 year o ld facilities that is significantly better than what the newest, most efficient greenfield NGCC's c an achieve under GHG BACT. Commenters stated that, compared to other facilities identifie d as cogeneration facilities in Florida that produced only electricity in 2012 (net electric gen eration was equal to net energy generation), it appears that EPA's estimate of UTO is inappropriate . Commenters stated that cogeneration
facilities much newer than the others have emission rates approximately 20% higher in some cases. Commenters stated this is not representative of real emission rates should the cogeneration facilities be re-dispatched for higher electric gen eration.

Commenters suggested that it is inappropriate to co nsider useful thermal output (UTO) as available for re-dispatch. Commenters stated that, based on the clearly erroneous emission rates derived when UTO is considered, it should also not be included when determining NGCC
emission rates. Commenters stated the EPA should no t default the NGCC emission rate to the "Emission Rate (lb/MWh) net electric" which EPA cal culated to result in a value of 868 lb/MWh
for Florida based on 2012 data. Commenters stated t hat, if the EPA considers additional electric generation from cogeneration facilities it must do so at an adjusted heat rate which reflects the unit's efficiency for primarily electric generation , as EPA's re-dispatching does not define demand for steam (where the cogeneration facilities are able to improve heat rate). Commenters stated the EPA actually included a state goal calcu lation without UTO in the docket, noting "the reason for providing these rates is to help states understand their goals and the role (or lack of role) that useful thermal output plays. Commenters stated that the EPA appears to be claiming that UTO has very little impact in the calculated s tate goal, as the no-UTO state goals presented in the docket are nearly identical to those propose d that do include UTO. Commenters stated the EPA claims in this spreadsheet--that the rates in t he preceding worksheets rely on the same data and calculations, but do not go through the process of including useful thermal output--are misleading. Commenters stated that in addition to c hanging the NGCC emission rate to ignore UTO, it also changes the adjusted coal emission rat e and significantly lowers the emissions and generation from "other" sources, among other possib le changes.

Commenters stated the thermal energy produced at NG CC units should be converted into equivalent MWh and be included in the calculation f or Building Block 2.216

Comment 51: Commenters expressed concern that Building Block 2 strongly impacts some certain states, but not others.

Response 51: The EPA disagrees. In response to additional analys is and many comments, we have modified the proposal and RIA – the establishm ent of CO2 emission reduction standards is regionally based. The 111(d) final rule requires th at states develop plans that establish emission standards for affected EGUs. We are providing state s with substantial flexibility as to how they structure those plans to achieve the 111(d) require ments. The flexibility includes, for example, the choice of approaches, trading, time to develop plans, additional time before the start of the interim performance period (postponed from 2020 unt il 2022), and the ability to shift emission rate achievement between performance periods. The B uilding Blocks are not prescriptive, and states may consider local circumstances as they dev elop their plans, including system reliability, fuel diversity, the need for ancillary services oth er regulatory requirements and infrastructure. The 111(d) final rule does not require every indivi dual NGCC to meet a CO2 emission performance rate, but rather the 75 percent capacit y factor was used in the calculations to establish a rate. See sections V.D, VIII.A, VIII.C and VIII.G of the final rule preamble of the CPP and Chapter 3 of the GHG Mitigation Measures TS D for the CPP Final Rule supporting the

final CPP.

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

States that acted early to build NGCC plants

Commenters expressed concern that the Proposal does not recognize states and companies that acted early in building NGCC plants.

Commenters stated that the proposed displacement of existing coal-fired steam and oil/gas-fired steam generation by increasing generation from exis ting NGCC capacity penalizes companies in states that acted early in building NGCC plants to support RE. Commenters noted that these units currently operate at relatively low capacity factor s but must have all capacity available to meet peak generation demands and to fill in generation w hen a state's renewable energy production falls - increasing NGCC capacity to 70 percent also would hinder these plants' ability to provide flexible load-following generation to support varia ble RE.

Commenters contended that, because the rule begins its data baseline in the year 2012, it tends to ignore actions prior to that date. The commenters f urther stated that the target-setting process embeds mechanisms (some of which may have been unin tentional) that further ignore early action. The commenters opined that Building Block 2 imparts more stringent targets on states and utilities that have already developed natural g as combined cycle plants, or that operate natural gas combined cycle plants to integrate high levels of wind.

Commenters stated that New Hampshire cannot further transition from coal and oil to natural gas beyond what was achieved as of 2012 without negativ ely impacting the delivery of reliable, costcompetitive electricity to its consumers. Commenter s stated the EPA's analysis of NGCC redispatch opportunity under Building Block 2 ignores the fact that New Hampshire has already217

transitioned to NGCC to the maximum extent possible given the availability constraints and the dire need for fuel diversity within the state and r egion as a whole. Commenters stated that, since this building block represents the bulk of the redu ction required in New Hampshire, it is not reasonable to expect New Hampshire to be able to re cover from an inability to implement this building block by increasing implementation of the remaining building blocks. Commenters
illustrated the dramatic shift from oil and coal to natural gas that has occurred within the last decade in New Hampshire: the average consumption of coal and oil for power g eneration during the period between 2005 and 2012 represent decrease s of 15, and 86 percent respectively, when compared to the average coal and oil consumption du ring the period between 1990 and 2005; natural gas consumption in New Hampshire between 20 05 and 2012 has increased by 450 percent, when compared to the average natural gas c onsumption between 1990 and 2005. Commenters stated these values illustrate the imple mentation of Building Block 2 that occurred prior to 2012 in New Hampshire. Commenters stated t hat, according to a separate analysis by the EIA, natural gas accounted for 21 percent of New Ha mpshire's net electricity generation in 2013, down from a record-high of 37 percent in 2012. Comm enters stated that, due to various factors including the exceptionally mild weather in 2012, t he record-high natural gas generation in 2012 has proven difficult to repeat and nearly impossibl e to exceed.

Commenters stated the Proposed Rule Building Block 2 approach would result in excessive disparity in stringency among the states, penalizin g states who have invested in natural gas combined cycle units to improve reliability (via re serve margin). Commenters asserted the EPA's analysis does not provide a reasonable basis for go als predicated on 70 percent NGCC utilization rates nor does it provide a reasonable basis for op erating existing steam EGU's at an unsustainably low capacity factor.

States with limited NGCC

Commenters recommended that EPA generally provide f or consistency between target-setting and reasonably-foreseeable compliance options so as to maintain the integrity and effectiveness of the program. Commenters stated that, as currentl y proposed, building block 2 requires little to
no reductions from states that have limited or no e xisting natural gas capacity, despite the fact that new NGCC and co-firing of natural gas in heavi ly coal-dependent states would result in significant reductions in state CO2 emission rates. Commenters stated that this has resulted in a disparity in state goals between states. Commenters stated that, because the current proposal might allow a state to count new NGCC capacity towa rds compliance with its state goal, omitting such potential in the goal computation met hodology could set less stringent state goals than some states could cost-effectively and reasona bly achieve.

Commenters stated that, because the City of Fremont , Nebraska does not have an NGCC unit and there is only a very limited number in the Stat e as well, this strategy will have a minimal
effect in Nebraska.

Commenters stated that Minnesota has little uncommi tted NGCC unit dispatch opportunity to accommodate the EPA's assignment of a 70 percent ca pacity factor level of operation.

States with limited coal218

Commenters asserted that there is ample fossil gene ration to displace with NGCC generation in historically coal-dependent states, however, in sta tes that are historically less dependent on coal do not have this opportunity. Commenters noted that , while Georgia would need to increase NGCC generation by 13.8 million MWh to achieve a 70 percent capacity factor (up from the 2012 average of 51 percent), since Georgia's 2012 c oal and steam generation was 41 million MWh, there is sufficient generation to allow for re -dispatch of the state's NGCCs up to the 70 percent maximum. Commenters noted even if Californi a re-dispatched all of its historical coal and steam generation to NGCCs, it would still only achieve a 49 percent NGCC capacity factor, an increase of just 4 percentage points.

States with substantial NGCC capacity

Commenters stated the proposed Rule disproportionat ely targets states with underutilized NGCC capacity without any analysis concerning why the ca pacity is under-utilized. Commenters stated, in Arkansas' case, the Union Power Partners Station is under-utilized due to transmission constraints among other reasons, issues that no amo unt of re-dispatch, as contemplated by the proposed Rule, can address.

Commenters stated the inclusion of BB2 is one of th e principal drivers of the inequitable pattern of emission reduction targets among states because States with substantial NGCC capacity in place are assigned large reductions related to this capacity, while states without any NGCC units do not receive any reduction requirements.

Commenters stated Building Block 2 leads to inequit able results among the states. Commenters stated that Texas, Louisiana, and Arkansas have lar ge amounts of natural gas fired generation, and as such, under EPA's methodology, a larger burd en has been imposed upon these states to
reduce CO2 emissions. Commenters asserted that stat es that have a prevalence of natural gasfired generating capacity are required to reduce th eir CO2 emissions more than other states. Commenters stated that the State of Texas, with a c urrent CO2 emissions rate (1,284 lbs/MWh) lower than the national average (1,442 lbs/MWh), is , as proposed, required to reduce emissions by a level greater than the national average (38% v ersus 30% nationwide). Commenters stated that heavy coal generation states such as Kentucky, West Virginia, Montana, North Dakota, and Wyoming, are at the bottom of the list, with requir ed reductions of 20% or less, which is clearly an inequitable result.

Commenters stated Building Block 2 portends signifi cant negative consequences for the Texas electricity market and the Texas economy and is pat ently unfair to the state of Texas. Commenters stated that, because Texas has invested heavily in NGCC capacity, existing coalfired units are unfairly penalized. Commenters stat ed that states that rely primarily or almost exclusively on coal, and do not have NGCC capacity, are not asked to re-dispatch and therefore
are not asked to reduce their CO2 emissions under B lock 2. Commenters asserted that a state that has significantly increased NGCC capacity, is force d to penalize existing coal plants, whereas a state that has a predominantly coal fleet is allowe d to continue to operate existing coal plants unimpeded.

Commenters stated that the proposed rule penalizes Texas for the very thing the rule will purportedly achieve: the addition of modern, effici ent natural gas-fired generation. Commenters219

noted that ERCOT has added substantial new efficien t natural gas combined cycle generating plants over the last decade (14,775 MW of NGCC gene rating capacity since 2001) and currently has more installed natural gas capacity than any ot her state. Commenters asserted that because of the existing base of natural gas fired generation c apacity, Building Block 2 effectively requires a 52% reduction, or 72 million megawatt hours, in Tex as's utilization of coal fired electricity, which is more than the total coal generation in all but six other states. Commenters believed that the EPA's methodology inappropriately discriminates against Texas because of the existing base of natural gas fired generation capacity, noting th at other states with a very high proportion of their total electricity generation provided by coal are impacted very minimally by Building Block 2's application, resulting in a vastly disparate im pact to Texas.

State-specific comments

Commenters stated that the EPA noted an average 24. 5% capacity factor for Minnesota existing NGCC units in 2012, a year that they reported exper ienced unprecedented low natural gas prices that would not be commercially expected in the futu re. The commenters asserted that EPA's presumption that re-dispatch of existing NGCC presu ming a 70% capacity factor can be achieved while serving as a base load resource is i nappropriate. The commenters asserted that
EPA needs to consider the measures and costs that w ould be incurred to replace the intermittent renewable resource reliability, peak power generati on resource service electric and natural gas transmission support that the NGCC units currently provide.

Commenters stated the proposed Rule disproportionat ely burdens states with perceived underutilized NGCC capacity with higher emissions r eduction. Commenters stated that, as a result, Arkansas Electric Cooperative Corporation a nd Arkansas are disproportionately affected by the emission reduction targets, a result that pe nalizes early adoption of a diverse portfolio.

Commenters expressed concern that, despite the curr ent 57% level of emissions-free power generation supplied by MEAG to the communities, res ulting in an overall lb CO2/MWH emission rate well below EPA's proposed goals for G eorgia, the Rule would require MEAG to "re-dispatch" away from its coal units and acquire additional generation that is otherwise not

necessary.

Commenters asserted that, because Florida's ESPS Bu ilding Block 2 depends primarily on frontloading and shifting 90 percent of their coal- fired generation to gas-fired generation, the shift will result in the premature closing of many of their coal-fired generation plants.

Commenters stated that the CPP fails to recognize t he significant carbon emissions reductions already made by Louisiana through an increase in NG CC dispatch over the past several years. Commenters stated that Louisiana's natural gas heat rates have fallen 9.7 percent in the last 10 years and natural gas-fired emissions have fallen 1 1.2 percent.

Commenters expressed concern that, since pipeline c ompanies that serve South Carolina have reported that their pipelines are "essentially full " and are fully subscribed, this means that additional pipeline facilities or system modificati ons would be required for South Carolina to obtain the additional natural gas necessary to run its existing NGCC units at 70 percent capacity and certainly limits future development. Commenters asserted that other states that have better220

gas pipeline capacity but no existing NGCC do not h ave their state goal affected by the redispatch of their coal units to natural gas. Commen ters stated that the failure of this proposed rule to capture and account for natural gas pipelin e capacity presents practical problems on the achievability of the goals that are set for our sta te and, as a result, South Carolinians are being
asked to bear a burden that is not commensurate wit h our current carbon intensity. Commenters
concluded that the Clean Power Plan results in the inequitable treatment of South Carolina and other states as the national goal is derived from a n inconsistent methodology.

Commenters asserted the EPA's Proposed Rule fails t o consider that the regions in which Heartland's customers are located, including portio ns of eastern South Dakota, southwestern Minnesota, and Iowa, are very rural and feature eno rmous distances between service territories. Commenters stated cooperative and municipal electri c utilities were created in these regions partially because of these geographic challenges an d these very same geographic challenges are the reasons why natural gas infrastructure has not been built out in these parts of the country. Commenters stated the natural gas infrastructure is severely limited in the Heartland footprint, making a build-out of those resources cost-prohibit ive. Commenters stated that to now penalize our region because of the large distances between c ustomers is unreasonable and discriminatory.

Commenters stated that the underlying design elemen ts of Block 2 of EPA's BSER model would disproportionally harm Texas and Texas' coal miners . Commenters stated that the Proposal would force a 52 percent reduction in coal-fired ge neration in Texas. Commenters stated this reduction is greater than any other state and only North Carolina's (33 percent) and Michigan's (23 percent) reductions are even close to Texas'. C ommenters noted that states like Kentucky (1 percent) and Indiana (5 percent) experience very li ttle impact to their coal fleets. Commenters stated this disparity and inequity is not allowed b y the CAA, which requires a uniform standard across the states, where the states themselves can choose to meet these uniform standards in the best ways they see fit. Commenters stated that, in this Proposal, the EPA has chosen to target some states, especially Texas, to bear the brunt of huge a proportion of the nation's CO2 reductions, while asking little of other states.

Commenters indicated that in states like West Virgi nia that do not have any NGCC plants, the proposed rule would but a much higher burden on the efficacy of the other Building Block assumptions, while at the same time limiting the am ount of West Virginia coal that can be sold to neighboring states. Commenters stated that because West Virginia does not have any NGCC units, its budget calculated by the EPA does not fa ctor in Building Block 2. Despite this, the commenters believed that West Virginia and the memb ers of the West Virginia Coal Association will still suffer as the demand for coal plummets i n favor of natural gas as a result of the EPA's assumption that all NGCCs could increase their capa city factor to 70%. Commenters indicated that arbitrary and dangerous assumptions underlie B uilding Block 2. Commenters stated that Building Block 2 would significantly reduce coal ge neration in many states and eliminate it entirely in 12 states.

Comment 52: Commenters stated the EPA should favor mechanisms t hat don't create "winners

and losers."221

Response 52: The EPA disagrees that the final rule has the impac t referenced in the comment. In response to additional analysis and many comments, we have modified the proposal and RIA –

the establishment of CO2 emission reduction standar ds is regionally based. The 111(d) final rule requires that states develop plans that establish e mission standards for affected EGUs. We are providing states with substantial flexibility as to how they structure those plans to achieve the 111(d) requirements. The flexibility includes, for example, the choice of approaches, trading, time to develop plans, additional time before the s tart of the interim performance period (postponed from 2020 until 2022), and the ability t o shift emission rate achievement between performance periods. The Building Blocks are not pr escriptive, and states may consider local circumstances as they develop their plans, includin g system reliability, fuel diversity, the need for ancillary services other regulatory requirement s and infrastructure. The 111(d) final rule does not require every individual NGCC to meet a CO2 emi ssion performance rate, but rather the 75 percent capacity factor was used in the calculation s to establish a rate. See sections V.D, VIII.A, VIII.C and VIII.G of the final rule preamble of the CPP and Chapter 3 of the GHG Mitigation Measures TSD for the CPP Final Rule supporting the final CPP.

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

Commenters referred to the October 30, 2014 NODA wh ich requested comment on a number of potential revisions to the CPP, and stated the only reasonable solution to Building Block 2 is to remove it (along with the other three Building Bloc ks) and start again with a rule that complies
with the CAA. The commenters stated the EPA's attem pt to force re-dispatch in states with little or no existing NGCC illustrates clearly that Buildi ng Block 2 arbitrarily creates winners and losers by punishing states that burn more natural g as for electricity generation and rewarding
states that burn less. Commenters stated the EPA no w seeks to fix this serious error by forcing re-dispatch to NGCC units that do not exist. Commen ters opined this type of requirement is even more arbitrary and unreasonable than the existing B uilding Block 2.

Commenters stated that re-dispatching to natural ga s from coal will create winners and losers since not all utilities and/or generators in Utah o wn both types of plants. Commenters stated, for example, one Utah utility operates the three larges t NGCC plants in the state and, thus, redispatching to NGCC would require a large shift in generation from coal plants owned by several stakeholders to NGCC plants operated by a relative few.

Comment 53: Commenters asserted that, in assessing the emissio ns reductions that Building Block 2 can achieve state-by-state, the proposal fa ils to account for the existing trend of the retiring role of the high-emissions fossil-fired pl ants, primarily coal, in favor of new lower zeroemission resources.

Response 53: The EPA disagrees. We believe the rule sets achiev able, but not maximum goals, and that the flexibility we provide allows states t o develop plans that don’t result in over construction of capacity. In response to additional analysis and many comments, we have modified the proposal and RIA – the establishment o f CO2 emission reduction standards is regionally based. The 111(d) final rule requires th at states develop plans that establish emission222

standards for affected EGUs. We are providing state s with substantial flexibility as to how they structure those plans to achieve the 111(d) require ments. The EPA believes the approach is achievable and sound. See sections V.D, VIII.A, VII I.C and VIII.G of the final rule preamble of the CPP and Chapter 3 of the GHG Mitigation Measure s TSD for the CPP Final Rule supporting

the final CPP.

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

According to the commenters, this means that the EP A has set 2030 as a goal that some states can easily achieve, particularly states that are co al-dominated and coal-intensive. The commenters stated that, to ensure that this block i n the proposal has achieved additive reductions in carbon pollution, it should be adjusted to accou nt for the planned and anticipated coal and other fossil plant retirements and general rates of generation change from coal to lower-emitting resources. In other words, the commenters stated, t he EPA should ensure that block two will drive additional emissions reductions, and that all states should be expected to transition from hot coal, high-emitting coal and gas plants to clea ner resources over time.

Comment 54: Commenters stated that the EPA's re-dispatch calcul ations contain numerous fundamental calculation errors and data quality iss ues that result in the amount of potential redispatch to be substantially overstated.

Response 54: EPA has reviewed calculations and data quality comm ents and revised modeling procedures and inputs for the final rule, including an updated NEEDS file.

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

Commenters stated that the EPA's re-dispatch calcul ations contain numerous fundamental calculation errors and data quality issues that res ult in the amount of potential re-dispatch to be substantially overstated, including (1) incorrect d ata inputs; (2) inappropriate use of nominal nameplate capacity instead of the actual net demons trated capacity; (3) incorrect inclusion of
units that do not meet the definition of an "affect ed source" subject to the proposed rule; (4)
incorrect inclusion of NGCC units that were never c onstructed; along with (5) incorrect and inconsistent assumptions on units that were commiss ioned in 2012 or later. Commenters indicated that he data quality issues and methodolo gical errors are not limited in scope, but are present in the building block 2 calculations for ev ery state with NGCC capacity. Commenters asserted that the impact of these concerns is signi ficant, stating that correcting the errors would reduce the amount of NGCC re-dispatch that EPA calc ulated by 51% in Louisiana and 92% in Ohio. Commenters provided a table highlighting the scope of building block 2 calculation issues
that have been identified for each state with NGCC capacity.

Commenters stated that any attempt to correct the c ommenters’ identified concerns or determine how these corrections impact state goal calculation s, "flexible" compliance strategies, reliability evaluations and cost-benefit analyses is too comple x to complete within the public comment period. The commenters asserted that given the natu re and scope of concerns to be resolved in223

building block 2, the EPA must withdraw the current proposal, address these issues and publish a new proposed rule for public comment.

Commenters noted that the proposed Rule indicates N GCC capacity in Arkansas is currently 5,588 MW, but stated that Arkansas Electric Coopera tive Corporation's analysis shows there is a maximum of 5,114 MW of NGCC capacity in the state.

Commenters noted that the NEEDS Version 5.13 databa se underestimated the capacity for the Warren facility at 570 MW. The design capacity of t he facility is 1,358 MW. Including the correct capacity of the Warren facility would actua lly further reduce the Virginia target by approximately 6 lb/MWh.

Commenters stated the EPA also made numerous errors in calculating the potential emission reductions achievable through re-dispatching coal a nd natural gas units: According to the commenters, the EPA used the incorrect maximum capa city values for NGCC units, included some NGCC units that do not serve the power grid, a nd some units that are neither in operation
nor under-construction.

Comment 55: Commenters pointed out what the commenters characte rized as inconsistencies in the EPA's analyses and asked for clarifications.

Response 55: The EPA agrees that data sets and calculations from the proposal can be updated.

The EPA has modified its calculations for these bui lding block issues. See the GHG Mitigation Measures TSD, Preamble V.D for Building Block 2 cal culations, and the Goal Setting TSD for treatment of NGCC capacity factors in goal setting.

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

Commenters raised the following issues about specif ic pages in the GHG Abatement Measures
TSD:

Page 3-11: "Adding in the existing sources that wer e not yet online in 2012 (under construction) increases total NGCC generation calculated in the g oal setting to 1,444TWh." This would represent a 50% increase over what was produced in 2012, which was a record year; however, in the "Building Blocks" memo TSD, EPA predicts NGCC p ower production in 2030 will be 1,743TWh, which is 178% of the 2012 value. That imp lies a significant increase in natural gas consumption versus today. For 2020 EPA predicts NGC C power production will be 1,369 TWh,
which shows a mismatch between what is in this refe rence document and what is in the costbenefit calculation memo. Page 3-12: "For compariso n, NGCC generation growth of 450TWh (calculated in goal setting) would result in increa sed gas consumption of roughly 3.5 TCF for the electricity sector." There is a miscalculation here based on what is stated in Footnote 69 where the heat rate of an NGCC is assumed to be 10,000 Bt u/kWhr - Commenters believed this is too high. To get 3.5 TCF from 450TWh of electricity one has to assume a heat rate of 7,964 Btu/kWhr. However, EIA estimates the electric power sector consumed 9.1 TCF of natural gas in 2012. Consuming an additional 3.5 TCF of natural ga s would mean an increase of 38.5%, but that does not seem to match with the statement on p age 3-11 that NGCC generation would224

increase by 50%. Although the amount of power produ ced by simple cycles might be large enough to account for this discrepancy, the modelin g results in the cost-benefits memo show only a very small amount of power being generated b y simple cycles. Table 3-6: The base case has an NGCC capacity factor of 52% which is signifi cantly higher than the value in 2012. It is uncertain whether this is due to the assumed impact of planned coal unit retirements and NGCCs taking up the slack or another reason. Page 3-26: A t the top of the page it is stated: "This is because only 29 state goals are premised on the exi sting NGCC fleet achieving an average capacity factor of 70 percent. Consequently, a 70% utilization rate target for the existing NGCC fleet requires an average national capacity factor of 63 percent." This second sentence is confusing and should be clarified.

3.2.3 Natural Gas Supply

This section discusses the supply of natural gas, i ncluding transmission and distribution systems and energy markets, to meet the needs of EGU’s as t here is substitution for generation from the most carbon-intensive affected EGUs with generation from less carbon-intensive affected EGUs (specifically NGCC units) under building block 2.

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

Comment 1: Although natural gas may be cheap and plentiful now and production increases are projected, general concerns were expressed about th e effect of increased demand on energy markets, the adequacy of supply during extreme weat her events, the lack of certainty of future supply and reliance on any single source of supply.

Response 1: The EPA agrees that natural gas prices have demonst rated historical variability. See section V.D of the final rule preamble of the CPP a nd Chapter 3 of the GHG Mitigation Measures TSD for the 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 noted that natural gas is cheap and plen tiful now, but questioned whether we know it is going to remain so in the next 15 years when the reductions required under this plan must be

met.

Commenters stated that since many chemistry process es require large amounts of electricity and natural gas, both as a raw material and as an energ y source, the U.S. chemical industry is highly attuned to how EPA's regulation for the electricity sector could affect energy markets. Commenters agreed that natural gas production is in creasing overall, but asked whether the increased production will be enough to offset the h uge increase that will be required for power generation by switching to natural gas.225

Commenters stated that although natural gas today a ppears to be plentiful and the cheaper alternative for power generation, that may not alwa ys be the case given the desire of many companies to export liquefied natural gas from the United States to other countries. Commenters added that considering the historic volatility of n atural gas prices, it seems likely that a reliance on natural gas will result in increased costs for e lectricity generation in coming years.

Commenters stated that while re-dispatch will ultim ately reduce GHG emissions, reliance on this Building Block will increase the usage of natural g as. Commenters asserted that if this Building Block remains a component of BSER, options for miti gating this increased natural gas usage
should be considered.

Commenters stated that there are many critical issu es and questions with a large-scale fuel switch to natural gas for power electrical generation purp oses including, among others addressed in
other sections of this document: What is the real l ong-term U.S. natural gas supply? How does that projected natural gas supply balance with the new much larger increase in fuel source
demand?

Commenters stated that the nation's natural gas sys tem of production and distribution could not meet demands for fuel during weather extremes this past winter; in fact there were a number of power plants that could not operate because of a lack of natural gas. Commenters asked what changes in drilling rates and trenching for new nat ural gas pipelines the EPA foresees that will
allow it to meet the additional demand for natural gas to generate millions of megawatt hours of electricity in 2020 and beyond. Commenters also ask ed what economic and environmental impacts those shifts will have on tho se who use natural gas for other purposes such as residential heating.

Commenters also expressed concern over the availabi lity of natural gas and the transportation of natural gas during extreme weather events. Commente rs emphasized the distinction between the availability of natural gas and the availability of natural gas transportation and balancing infrastructure needed to support the expected high capacity factor operations of existing NGCC
units. Commenters referred to the 2013-2014 winter which posed unique natural gas delivery and operational flexibility challenges for Brazos Elect ric, when the four natural gas pipelines servings its generation units placed restrictions o n non-ratable consumption that were mainly due to unrelenting consistently cold days. Commenters s tated that during a normal winter, a cold blast will last a few days before fading to warmer weather, which allows pipelines to recover.
Commenters stated that the consistent cold of the 2 013-2014 winter did not allow sufficient time the natural gas pipelines to recover for the next c old period, so operational flexibility was limited on non-extreme days. Commenters stated that the ass umption of readily available natural gas is inaccurate in the Brazos Electric's experience and for the nation as a whole.

Commenters stated that analysts at the Center for S trategic and International Studies and the Rhodium Group report that natural gas demand for co mpliance with the CPP may be three times greater than the EPA projects in the absence of agg ressive energy efficiency programs.
Commenters indicated that the CPP will lead America to greater dependence on natural gas as a main source of electric generation, and that CSIS f orecasts that natural gas use could more than double as a percent of total electric generation, r ising from 19% in 2010 to 43% in 2020 (CSIS at226

17, national scenario without energy efficiency) wi th the share of coal generation declining from 46% to 21% over this period due to higher demand fo r natural gas.

To develop a stable natural gas supply market to su pport stable electric power production, Commenters recommended that the EPA establish firm, clear and predictable environmental rules on natural gas development, transportation an d emissions.

Commenters stated that while Colorado currently has an abundant supply of low cost natural gas there is no certainty this will be true in the futu re. Unlike coal, which has locked in long-term cost certainty, according to the commenters, natura l gas production is subject to market and regulatory uncertainty which could create substanti al price increases. Historically, the commenters noted natural gas markets have been extr emely volatile and this is likely to continue, particularly if proponents of LNG export are succes sful.

Commenters stated that it is unwise to rely too hea vily on any single source of energy because, like any other commodity, natural gas is susceptibl e to fluctuations in supply, demand and price - not to mention the specter of additional environmen tal and drilling regulations, which could have a serious impact on future production and price lev els.

Comment 2: The U.S. possesses abundant natural gas supplies ca pable of meeting greater

demand from the electric sector and other industrie s; competitive markets must remain liquid to aid efficient delivery of natural gas to customers, adequate infrastructure (including pipeline capacity) and an efficient and predictable siting a nd permitting process for new infrastructure will be needed in response to shifts in sources of natural gas supply and demand.

Response 2: The EPA agrees. See section V.D of the final rule preamble of the CPP and Chapter 3 of the GHG Mitigation Measures TSD for the CPP Fi nal Rule supporting the final CPP for EPA’s response to this comment.

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

Commenters indicated that the U.S. possesses abunda nt natural gas supplies capable of meeting greater demand from the electric sector and other i ndustries. Commenters agreed that natural gas supplies are adequate at reasonable prices. Comment ers noted he has been involved in the energy production business for a long time and said ample supply and cheap prices will continue for the foreseeable future, making compliance with this rul e relatively easy, or easier than we would have thought a few years ago.

Commenters stated that to facilitate the greater us e of natural gas-fired generation, and its corresponding emissions benefits, competitive natur al gas markets must remain liquid to aid efficient delivery of natural gas to customers. Com menters opined that a critical component of a healthy and liquid natural gas market is adequate i nfrastructure and an efficient and predictable siting and permitting process for the new infrastru cture that will be needed in response to shifts in the sources of natural gas supply and demand. Co mmenters stated that new pipeline capacity will play an essential role in transporting gas to market. According to the commenters, the227

natural gas industry has shown its ability to quick ly expand and improve natural gas infrastructure in the past and can continue to do s o given clear market signals prompting investment. Commenters added that regulators, inclu ding the FERC, should remove any
structural barriers that inhibit the construction o f new natural gas pipelines and should support market stakeholders as they seek to ensure adequate and timely infrastructure is in place to support the greater use of natural gas.

Commenters stated that the natural gas market featu res a wide array of contracting tools that facilitate efficient and timely natural gas use - a sset management agreements, pipeline park and loan services, storage contracts, and no notice ser vice are a few options at the disposal of customers. Commenters indicated that these tools, w hen secured in advance as part of a diverse procurement strategy, can assist generators in reli ably meeting their obligations, while physical and financial hedging tools can help mitigate price swings and exposure to the spot market. Commenters concluded that taken together, these pro curement tools can assist power market participants in accessing robust and reliable suppl ies of natural gas for their needs.

Commenters stated that it has long advocated for EP A to update its assumptions regarding the supply and availability of natural gas, citing comm ents made on the proposed MATS and 2012 GHG power plant NSPS and praising the EPA's approac h to evaluating and updating its projections on natural gas production based on the EIA's AEOs. Commenters asked the EPA to continue to use up-to-date assessments of natural g as supply and availability in this and future regulatory actions. Commenters encouraged the Agenc y to further review EIA's AEO 2014, the final release of which projects increased productio n of natural gas and increased natural gas-fired generation relative to EIA's AEO 2013 used by EPA t o calibrate the IPM modeling platform used to evaluate the potential impact of the propos ed rule.

Commenters stated that a recent analysis by Bentek supports the conclusion that natural gas production is expected to grow significantly across the country . Commenters indicated that such production growth has driven, and is driving, large investments in infrastructure to move gas from supply basins to demand markets. Commenters ad ded that because much of this increased production will originate from the Northeast produc ing region, many infrastructure projects are adding bi-directional capability to existing pipeli nes to increase their operational capacity. According to the commenters, this bi-directional fe ed relieves pipeline capacity constraints and hence creates new pipeline flexibility. The comment ers said this benefit was recognized when MISO completed the third and last phase of its eval uation of the ability of Midwestern pipeline infrastructure to support significant replacement o f retiring coal capacity.

Comment 3: Neither the Proposed Rule nor its Technical Suppor t Documents address concerns about the historic variations of EIA projections of natural gas supply.

Response 3: The EPA disagrees. In response to additional analys is and many comments, we have modified the proposal and RIA. See sections V. D, VIII.A, VIII.C and VIII.G of the final rule preamble of the CPP and Chapter 3 of the GHG M itigation Measures TSD for the CPP Final Rule supporting the final CPP.228

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

Commenters stated neither the Proposed Rule nor its Technical Support Documents address concerns about the historic variations of EIA proje ctions of natural gas supply.

Commenters noted that for the RIA, the EPA uses for ecasts of natural gas demand from the EIA, which acknowledges that its historical record on fo recasting natural gas prices is poor (see the latest EIA retrospective review). In addition, Comm enters believed that EIA's methodology underestimates industrial demand for natural gas. C ommenters stated the belief that industrial demand for natural gas is increasing beyond EIA's p redictions and the demand will continue to
increase in 2017-2020 with the construction of the announced projects in the chemical industry.

Commenters stated that projections of the future na tural gas supply are uncertain because shale gas reserves are more difficult to project than con ventional gas reserves. Commenters noted that the EIA's projects U.S. natural gas production to i ncrease from 23 trillion cubic feet in 2011 to 33.1 trillion cubic feet in 2040, a 44% increase, a lmost all of which is from projected increases in shale gas production. Commenters indicated that due to the fact that shale gas reserves are more difficult to project than conventional gas reserves , EIA has had to revise its shale gas numbers downwards several times in the last five years. Com menters asserted that nothing in the Proposed Rule or TSDs acknowledges these downward p rojections or what that could mean for long-term supply - without new natural gas producti on from shale gas (and oil) formations, it would be extremely difficult to achieve the CO2 emi ssions reductions required by the Proposal. Commenters stated that natural gas production from conventional supplies (found in reservoirs) has decreased over the last thirty years and is exp ected to continue to do so. According to the commenters, various sources have made widely diverg ent predictions, so it remains an open question just how much shale gas exists in the U.S. , and more fundamentally, what the production rate will be. Commenters indicated that all conventional gas wells tended to have lower production after 10, 20, or 30 years and that available shale gas production records from a few states (predominantly the Texas Railroad Commis sion 131) show shale gas wells tend to deplete significantly after about three years.

Commenters stated that insufficient information exi sts thus far to predict whether the dry shale natural gas plays in the Utica, Marcellus, and othe r formations will be as lucrative as those in the Williston Basin and the Eagle Ford Shale formation. Commenters added that the availability and timeliness of drilling reports varies among states, further complicating the ability to predict supply, and that EPA staff may not be familiar with all the nuances of drilling reports or the fact that many EIA reports comingle liquid natural gas o r wet and dry data when reporting on annual drilling and production records. According to the c ommenters, such commingling can inadvertently provide an overly optimistic picture of shale gas production.

According to commenters, estimates regarding produc tion from shale gas formations have varied widely, and had to be adjusted downward several tim es due to a variety of factors, including poor methodology and inaccurate or untimely information, among others. Commenters said that the EPA appears to take it on faith that EIA's current long-term estimates of low-cost, plentiful domestic natural gas supply are accurate. Commenter s urged the EPA to examine these projections carefully and to incorporate analyses f rom other respected sources to arrive at a more balanced assumption about future supply. Commenters stated that according to EIA, the229

Marcellus formation, which stretches from New York to West Virginia, produced about 15.6 bcf of natural gas per day in August 2014, about 38% of total U.S. natural gas production for the month. However, according to the commenters, recor ds are minimal for dry gas production from
the Marcellus and Utica formations. Commenters stat ed that given how little information actually exists about production, continuing public concern about fracking, and other issues such as water and land use, it seems premature to assume these formations will be able to produce the gas needed for large-scale and long-term fuel switc hing.

Commenters stated that, while the EPA relies on EIA natural gas forecasts in determining, under BB2, that redispatching large amounts of coal-fuele d electricity to NGCC units is economically viable (79 FR 34857), it has become increasingly ap parent that EIA forecasts for natural gas differ substantially from outcomes. Commenters prov ided the following additional information:

• As EPRI reports, "history has demonstrated the pric e of natural to be highly volatile, and multi-year forecasts have consistentl y been inaccurate." A striking example of this difference is in 2002, when EIA pro jected the cost of natural gas to electric utilities in 2006 would be $3.85 per th ousand cubic feet (Mcf) (2006 dollars). The actual cost was $7.56. Further, in 20 03, EIA overestimated domestic production in 2006 by almost 2 trillion cubic feet- more than the annual natural gas production of natural-gas rich Oklahoma.

• These problems are systemic. An error-decomposition analysis of one-, two-, three-, and four-year-ahead forecasts by EIA from 1 998 to 2006 revealed that:

1. On average, a one-year ahead-average percentage for ecast error for wellhead natural gas prices of 16%, with the errors steadily increas ing to more than 45% with the fouryear-ahead forecast. More than 54% of the errors fo r the one-year-ahead forecasts can be attributed to systematic bias;

2. Natural gas consumption in electric generation is c onsistently below actual observations. The absolute error for the one-year-a head forecast was more than 900 bcf - more than 15 percent of consumption in the el ectric sector for that year;

3. Dry natural-gas production is consistently over-pre dicted. The absolute errors are quite sizeable. The two- through four-year-ahead fo recast errors exceed one trillion
cubic feet.

• The analysis indicates that the forecast errors are not reflective of random chance. Rather the forecasts contain evidence of systematic bias, either arising from a fixed, linear bias or from a systematic error comin g from the NEMS model. These biases emerge over a much shorter period (4-year ho rizons) than the 10-year plus scenarios that EPA is conducting for this rulemakin g.

• The prospect of even greater errors on the critical factors of natural gas supply, power sector consumption and natural gas prices is highly probable, if not a certainty. For instance, in the first two months of 2014, the delivered price of natural gas breached $7.46/MMBtu and during Februar y reached $7.78/MMBtu-230 well above EIA's previously forecasted price for th at same time period. AEO 2013 did not project delivered natural gas prices t o the power sector to reach $7.00 until 2035-a projection that was proven inacc urate by a mere 21 years. AEO 2014 appears equally inaccurate and obsolete since the reference case pegs delivered natural gas prices reaching $7.00 in 2035 -about the same time as AEO 2013. We reached the $7 price point two decades ear lier than EIA forecasts.

• Both the AEO 2013 and AEO 2014 reference cases cont ain dubious and unsustainable projections. These include:

− The projected demand for natural gas is significant ly underestimated. EIP predicts that natural gas demand will increase subs tantially to replace the lost generation from current and projected coal plant re tirements and higher consumption from the industrial sector as additiona l manufacturing capacity in gas-intensive industries come to the U.S. in the face of higher natural gas costs in Europe and Asia. AEO 2013 and 2014 forecas t a natural gas demand increase of 7 percent between 2013 and 2022. NMA's analysis indicates that the combination of increased power and industrial s ector consumption will increase demand in that period by 15 percent - a 1. 83 Tcf difference from the EIA estimate. NMA's analysis and EIA's forecast beg in to diverge by 1 Tcf by 2014 with that gap beginning to widen in 2020. All of this coincides with the increased coal plant retirements in 2014 through 20 20. At a minimum, EPA
must look at the retirements of coal-fired EGUs tha t are known and forecasted and calculate the natural gas requirement to replac e that generation. After all, EPA states in its proposal that it anticipates that most of the lost coal generation will be filled by new natural gas-fired generators and increasing the capacity factors at existing natural gas-fired EGUs. It must also look more closely at more recent analysis on growing industri al sector consumption;

− The forecasted natural gas prices are too low to su pport the supply growth rate AEO 2014 forecasts, and are well below levels neces sary to sustain the supply growth other analysts peg at twice the level foreca sted by EIA. With shale gas comprising a greater share of overall supply in all forecasts, neither AEO 2013 nor 2014 account for the steep decline rates f or shale wells and the impact on ultimate recovery. The steep decline rate s require a constant drilling treadmill of more expensive wells at a faster pace just to maintain current production levels. The recent shift of drill rig de ployment from dry gas to oil and liquid rich reserves is one of several signals that prices are inadequate to sustain the replacement rate. Some analysts have co ncluded that gas prices in the range of $8.00 to $9.00/Mcf are required to bre ak even on a full-cycle basis. Notably, the growth rate of dry gas producti on has slowed since 2011 with lower pricing. In 2013, the growth rate was le ss than 1 percent.231

Comment 4: The EPA failed to support its claims that sufficien t natural gas will be available to fuel all of the additional NGCC generation.

Response 4: The EPA disagrees. The EPA has decided not to inclu de the provision in the final CPP relating to the compliance period beginning in 2020. The EPA believes that estimates of natural gas supply are more than adequate to suppor t the calculations for the establishment of CO2 emission performance rates. See section V.D of the final rule preamble of the CPP, Chapter 3 of the GHG Mitigation Measures TSD for the CPP Fi nal Rule supporting the final CPP, and the regulatory impact analysis of the CPP.

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

Commenters stated that the EPA's analysis of the ab ility of the country to sharply expand generation is meager, just one page (GHG Abatement Measures TSD at 3-12) out of a 224-page technical support document that EPA uses to explain its building block assumptions. Commenters noted that, while the EPA recognizes tha t it took twelve years, from 2000 to 2012, to increase natural gas production by 32 percent, t hat is the same level of increase in natural gas production that would be needed to satisfy EPA's bu ilding block two 70 percent NGCC capacity factor assumption only this time that increase woul d have to occur much more quickly and from a higher baseline. Commenters stated that, even if those efforts began today, they would have to be completed by 2020, which is just over five years away. Commenters added that, if those efforts do not begin until states finish developing their implementation plans (or, more likely, EPA approves those plans), only a few years would b e left before the significant amount of additional natural gas supply would be needed to su pport EPA's proposal. Commenters stated that the EPA has no basis for assuming that the unp recedented growth in natural gas supplies from 2000 to 2012 can be similarly replicated in ha lf of that time or less, particularly since each additional cubic foot of gas is likely to come at i ncrementally higher price than the previous one and given the large pipeline infrastructure investm ents which must be planned, permitted and constructed in that same time period.

Comment 5: The EPA needs to address competing demands for natu ral gas, such as LNG exports, Canadian gas, compressed natural gas and U .S. manufacturing.

Response 5: The EPA disagrees. EPA believes that estimates of n atural gas supply are more than adequate to support the calculations for the establ ishment of CO2 emission performance rates. See section V.D of the final rule preamble of the C PP, Chapter 3 of the GHG Mitigation Measures TSD for the CPP Final Rule supporting the final CPP, and the regulatory impact analysis of the CPP.

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

Some commenters stated that to determine whether th e United States can accommodate an increase in the average NGCC capacity factor to 70% , it is important to evaluate what is232

expected to be consumed by the LNG export facilitie s which have recently been approved. As an example, Commenters estimated that 3.6 trillion cub ic feet (TCF) per year have already been approved and another 3.6 TCF is under review by DOE (citing table of proposed LNG export projects in N. Powell and S. Sullivan, "How LNG exp ort projects could slot into DOE's reshuffled queue", SNL Data Dispatch, June 2, 2014) . Commenters recommended that the EPA clarify its assumptions for the potential magnitude of LNG exports to the potential price of natural gas.

Commenters stated that in recent years, there have been a significant number of proposals to bring large industrial facilities and LNG export te rminals online which, if built, will create a significant increase in the demand for natural gas from sectors other than the electric power sector. As an example, commenters noted that the In dustrial Energy Consumers of America, in early 2013, estimated that more than 100 industrial projects, representing nearly 95 billion dollars in investment, may come on line, which woul d represent a significant increased industrial demand for natural gas. Commenters added that the U .S. DOE has been evaluating applications to export LNG from the U.S. to countries with which the U.S. does not have a qualified free trade agreement in place - DOE has approved nine su ch applications to export LNG, and has more than 20 additional applications pending for re view. Commenters asserted that when the EPA assumed that a 70% capacity factor is available for NGCCs, it does not appear that the Agency considered the significant impact that this increased natural gas demand could have on natural gas prices, and consequently the ability fo r natural gas power plants to achieve the target capacity factor used to calculate the state emissio ns rate in the proposed guidelines.

Commenters stated that the EPA has failed to consid er the impact exports of LNG and nonelectric utility demand will have on natural gas su pply and prices. Regarding LNG exports, commenters indicated that given the recent applicat ions to the DOE for approval to construct new LNG export terminals, U.S. producers will begin exporting natural gas to European and Asian markets where demand for gas is also increasi ng and prices are higher than in the U.S.
Commenters added that the domestic demand for natur al gas is also projected to increase for use by manufacturers as feedstock and by the transporta tion sector as a fuel source. According to commenters, the EPA apparently has not examined any of these issues that could impact the supply available for electric utilities or the pric e they would pay for the gas. Commenters asserted that the Agency needs to look at these iss ues and accordingly revise its assumptions about the timing and feasibility of pervasive fuel switching from coal to natural gas to reduce
CO 2 emissions from power plants.

Commenters stated that shale gas production has inc reased domestic supply significantly and reduced prices, which, along with international dem and for natural gas, have led to recent efforts by domestic producers to export their gas as LNG. C ommenters added that European concerns about reliance on Russian gas have led to calls by some for the U.S. to export gas to the continent. According to the commenters, while it is still unclear how much domestic natural gas may be exported, it is very likely that exports wou ld put upward pressure on domestic prices, which would impact electricity rates. Commenters as serted that the EPA needs to factor this real possibility into its assumptions about how much fue l switching from coal to natural gas can
occur to reduce CO 2 emissions from the utility sector.233

Commenters stated that more than 25 applications fo r LNG export terminals have been filed with DOE, and several have been approved. Commenters con ceded that it is unclear how much natural gas will be exported, but indicated that gi ven the great demand for natural gas in Europe and Asia, where prices are much higher than they ar e in the U.S., it is very likely the U.S. will start exporting LNG, which will impact domestic pri ces, as well as the long-term supply of natural gas for use by the utility, manufacturing, and other sectors. While noting that most LNG facility applications at FERC would require substan tial construction time, commenters pointed out that the Sabine-Golden Pass project that was ap proved in late September is currently an LNG import terminal, whose owners plan to change the di rectional flow to enable the export of an amount of gas that is approximately three percent o f all U.S. natural gas production per day, so that the facility will begin exports in the near fu ture.

Commenters stated that the EPA also has not looked at the impact Canadian LNG exports could have on U.S. natural gas prices and supply, noting that the U.S. is the largest user of Canadian gas and many utilities use it for generation. Comme nters added that if Canada exports some of its natural gas that it currently supplies to the Unite d States, which will also put upward pressure on gas prices. Commenters also pointed out that U.S. s hale gas can be exported through Canadian
LNG terminals to other international markets.

Commenters stated that Asia petrochemicals manufact urers want to take advantage of U.S. natural gas supplies and plan to build tanks and re tool plants to store and process liquefied petroleum gas (LPG) derived from shale gas. Comment ers indicated that this LPG would replace costlier naphtha, a byproduct from oil and gas well s, as a raw material for the manufacturing of chemical products and plastics. Commenters said tha t such Asian imports of LPG will reduce U.S. domestic supply of shale gas.

Commenters stated that many transportation companie s have announced plans to move to compressed natural gas (CNG), some of citing the lo wer price of natural gas and others citing meeting other environmental regulations. Commenters indicated that while natural gas exports via LNG for international transportation demand may be at least five or ten years away, it is also relevant for consideration under the Proposed Rule. According to the commenters, Energy consultants Wood Mackenzie say global gas demand in the transport sector could grow from under 5 billion cubic meters (bcm) in 2012 to over 160 bcm by 2030, which would be equivalent to two-years-worth of current (2014) British gas de mand (approximately 3 million barrels of oil).
Commenters concluded that with international CNG ru nning at about double the price of U.S. natural gas in Europe ($10 Mcf) and almost four tim es the price of U.S. natural gas in Asian import markets (approximately $20 Mcf), the export of CNG for transportation markets is not implausible.

Commenters stated the EPA failed to assess the econ omic effects on other economic sectors from higher natural gas prices or potential gaps in the incremental natural gas supply. Commenters noted that many sectors of the economy rely on natu ral gas and have increased natural gas consumption since pre-recession levels, including t he power, industrial, and transportation sectors. Commenters stated that natural gas exports will begin to coincide with the accelerated retirement of coal generators. Commenters noted tha t (1) four LNG export projects approved so far by DOE have the capacity to export 7.1 bcfd of natural gas by 2018, amounting to more than 10% of the current daily supply of 70 bcfd; (2) the Sabine Pass liquefaction terminal will begin234

operations at the end of 2015 and has locked custom ers into 20-year contracts; and (3) U.S. exports of natural gas to Mexico are expected to ri se by 3.5 bcfd by the end of this year according to DOE - nearly double the current rate. Commenters stated the EPA's analysis does not touch upon any of these market developments and how the proposed rule will affect the economic sectors and residential customers that dep end upon natural gas.

Commenters stated that recent history provides more than ample experience on the scope and depth of the consequences of over-relying on natura l gas. Commenters stated that, between 1997 and 2009, the natural gas market experienced five s ignificant price spikes which contributed to the loss of nearly 4 million jobs in manufacturing and turned a $19 billion U.S. chemical trade surplus into a deficit from 2001-2007. Commenters s tated this occurred even when natural gas demand fell - but prices increased by 160%. Comment ers stated all of this coincided with an increase in natural gas power plant builds and a 27 % increase in natural gas consumption in the power sector - more than three times the overall gr owth in natural gas demand by all sectors. Commenters concluded that there is little question of the direct correlation between manufacturing job losses and higher and more volati le natural gas prices during this period. illustrates a decline in employment in the manufact uring sector from 1995 to 2005 (a reduction of over 3,000 jobs). Commenters stated that Nick Ak ins, CEO of American Electric Power, accurately summed it up in testimony to the Senate Energy Committee: "It has become clear that we are having to make a choice in the winter betwee n committing natural gas resources to generating electricity or to heating homes. Right n ow, we cannot do both. Given the number of additional base load generating units that will be retired in the next 14 months, we face a real possibility that we will have to make that choice m ore often in the future."

Comment 6: The IPM ignores important effects and feedbacks out side the electric sector, the electricity sector represents a only a portion of n atural gas consumption, and as a result, the EPA must reassess its proposal in order to more fully e stimate and reflect the significant effects and feedbacks it has on the U.S. economy.

Response 6: The EPA disagrees. This comment is not correct abou t the IPM model. The natural gas component of the model includes all natural gas consumption, not just the power sector. See http:epa.gov/powersectormodeling for documentation.

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

Commenters stated that IPM is a multi-regional mode l limited to analyzing the U.S. electric power sector that ignores important effects and fee dbacks outside the electric sector, which include: (1) significant changes in the use and tra de of natural gas; (2) significant changes in the aggregate levels of economic activity in different sectors of the U.S. economy; (3) significant changes in the pace of overall economic growth; and (4) significant changes in the use of electricity. Commenters asserted that assessing the se effects is important because the electric sector represents only a portion of the natural gas consumption in Alabama, Florida, and Georgia.235

Commenters stated that nationally, the electricity sector represents even less of a share of total natural gas consumption - approximately 34 percent in 2013. Commenters concluded that the EPA must reassess its proposal in order to more ful ly estimate and reflect the significant effects and feedbacks it has on the U.S. economy. Commenter s stated that the EPA's IPM results indicate a significant increase in natural gas cons umption from the electricity sector by 2020 in Alabama, Florida, and Georgia, and expressed concer n about the adequacy of the natural gas supply.

Comment 7: The EPA's assessment of energy requirements and ava ilable natural gas supply reflects a fundamental misunderstanding about the d istinction between resources and reserves.

Response 7: The EPA disagrees. The EPA believes that estimates of natural gas supply are more than adequate to support the calculations for the establishment of CO2 emission performance rates, and that states have flexibility and time to develop plans that ensure reliability. See sections V.D, VIII.A and VIII.C of the final rule preamble of the CPP, Chapter 3 of the GHG Mitigation Measures TSD for the CPP Fina l Rule supporting the final CPP, and the regulatory impact analysis of the CPP. See section V.D of the final rule preamble of the CPP and Chapter 3 of the GHG Mitigation Measures TSD for th e CPP Final Rule supporting the final

CPP

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

Commenters stated the EPA uses EIA's AEO 2012 estim ates that the U.S. possesses 2,214 Tcf of technically recoverable resources (TRR) of natural gas and then asserts that at current rates of consumption, the resources are enough to supply ove r 90 years of use (RIA at 2-23). Commenters stated that only a small subset of the T RR can be considered "reserves" (about 24 years currently of potential supply) reasonably ava ilable for consumption. Commenters stated this distinction is especially important in the con text of the proposed rule because EPA policies will drive increased reliance on natural gas for po wer generation and preclude the deployment of
the nation's enormous coal reserves-the most cost-e ffective fuel for base load power generation.

Commenters stated that, while the TRR are divided i nto three categories, speculative, possible and probable, only the probable TRR have been teste d by drilling and known to be, in fact, technically recoverable. Commenters stated that app roximately 30 percent of the TRR is classified as probable, only about half of the prob able TRR is likely to become reserves, and, thus, only 15 percent of the entire TRR are likely to be considered as consumption reserves. Commenters stated that, using the TRR estimate of 2 ,214 Tcf, the probable TRR is 664 Tcf-or about 25 years of supply at the consumption rates o ver the past two years (26.60 Tcf) and converting the probable TRR to reserves equals abou t 332 Tcf that can be added to the already proved reserve base of 305 Tcf. Commenters conclude d that the combined total of 635 Tcf leaves 24 years of supply at current consumption ra tes.

Commenters stated that, while economic viability is a key factor whether resources are eventually converted to reserves and developed and higher prices would convert more probable resources to reserves, these higher energy prices c arry consequences for the other sectors236

consuming natural gas and the economy as a whole. C ommenters stated the EPA's assessment lacks any analysis of the economic effects of the l ikely prospects of either higher natural gas prices or a gap in incremental natural gas supply. Commenters stated that less than a quarter century of natural gas reserves is a thin supply ma rgin to risk on a policy that will have profound effects on the economy but not make any material di fference in direct global temperature changes.

3.2.4 Technical Considerations

This section discusses technical considerations per tinent to building block 2. These include such issues as the electric transmission and natural gas infrastructure, natural gas contract mechanisms, the entities that control dispatch of E GUs, and coordination of the natural gas and electric systems.

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

Comment 1: Some commenters agreed that the natural gas delive ry infrastructure will support the level of re-dispatch proposed under building bl ock 2.

Response 1: The EPA agrees to the extent that comments support the BSER determination for NGCC for the 111(d) final rule. See section V.D of the final rule preamble of the CCP and Chapter 3 of the GHG Mitigation Measures TSD for th e CPP Final Rule supporting the final

CPP.

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

Analysis indicates adequate infrastructure.

Commenters stated that the availability of transpor t capacity is illustrated by the mapped results from the draft Eastern Interconnection Planning Col laborative (EIPC) Target 2 Report of the EIPC's DOE project, "Evaluate the Capability of the Natural Gas Systems to Satisfy the Needs of the Electric Systems," which evaluates the ability of the natural gas systems in the study region to meet the demand of end use and gas-fired electri c generation customers over 5-year and 10- year planning horizons. According to the commenters , two EIPC maps showing pipeline capacity conditions during a peak winter day, one under a re ference gas demand scenario and the second under a high gas demand scenario in modeled year 20 23, indicate that the extent of fully utilized pipeline segments is not dramatically different bet ween the two Winter 2023 scenarios and that there are natural gas pipeline systems not fully ut ilized under either set of Winter peak day
conditions. Commenters also stated that a second se t of EIPC maps shows EIPC's modeled peak summer day pipeline conditions and that when compar ed with the winter peak conditions under both the reference gas demand scenario and the high gas demand scenario, it is clear that there237

are predicted to be many fewer fully utilized pipel ine systems in the summer months under either
scenario.

Commenters stated that the limiting factor to a sus tained increase in generation of FPL's NGCC units would be the availability of natural gas supp ly, including both commodity and transportation, in that new natural gas infrastruct ure would be needed throughout FPL's service territory to meet this need. Commenters believed, h owever, that any technical constraints of this nature for is service territory could be addressed during the lengthy time frame afforded by the rule to achieve compliance because FPL is well posi tioned to continue and, if necessary, expand its pursuit of additional natural gas capacity and future natural gas generation. Commenters noted that in December 2012 FPL issued a Request for Prop osals to find the best option for new natural gas supply for its customers, which will result in a system comprised of two new pipelines and an interconnection hub. According to the commenters , the Sabal Trail Transmission and Florida Southeast Connection pipelines are progressing thro ugh the development process - a certification application for the Florida Southeast Connection pi peline has been filed with the Federal Energy Regulatory Commission and an application for Sabal will be filed by the end of November 2014. Commenters indicated that construction of the propo sed interstate pipeline system is scheduled to begin in 2016 and operations to deliver natural gas to FPL, Duke Energy Florida and other
users are scheduled to commence in mid-2017.

Commenters referenced several infrastructure studie s and stated that, when looking across regions broadly, these studies support the signific ant availability of delivered gas supplies for electric power generation. Commenters stated that, while these studies address natural gas availability for gas-fired electric generators on n atural gas peak demand days, they do not directly assess annual natural gas availability for gas-fired electric generators. Commenters stated that, given the often significant availabili ty of delivered natural gas for electric power generation on peak gas demand days, one can infer a n even greater amount of gas available for electric power generation throughout the year. Comm enters stated that recent pipeline capacity have been significant and pipeline capacity will co ntinue to grow. Commenters also stated there are several factors that make New England unique an d an inappropriate example to use for comparison with other regions of the U.S. Commenter s stated that natural gas infrastructure additions have been significant since 2007. Comment ers provided a Figure 4 (titled: “U.S. Pipeline Capacity Additions, EIA Pipeline Data”) an d stated that the cumulative infrastructure
additions more than doubled between 2007 and 2013 w hen compared to the 2000 through 2006 timeframe. Commenters referenced Appendix A of thei r comments which contains a list of proposed infrastructure projects for 2015-2018 and stated that over 55 billion cubic feet per day (Bcf/d) of additional capacity has been proposed to come online by 2018.

Commenters stated that, even absent EPA's proposed section 111(d) rule, analysts predict increased reliance on natural gas within the electr ic power sector as older, less efficient generating facilities are retired from the system. Commenters provided a Figure 7 (titled: “EIA Projections of Electric Sector Natural Gas Demand”) which shows a range of natural gas demand projections for the electric sector developed by th e EIA as part of its AEO series. Commenters stated that the AEO 2008 projected a steady decline in natural gas use by the electric power sector while, in contrast, AEO 2014 projected a 48 percent increase in natural gas utilization in the electric sector from 2011 to 2040, up from a pr ojected 25 percent increase in AEO 2013.238

Commenters stated this shift is due to the expected retirement of coal-fired and oil-fired power plants and to confidence in the long term outlook f or natural gas price and supply.

Commenters noted that the height of natural gas con sumption occurs during winter months mainly due to residential and commercial seasonal h eating needs. Commenters provided a Figure 6 (titled: “Average U.S. Monthly Natural Gas Consum ption”) and stated that since 2001, U.S. natural gas consumption during non-winter months is 64 percent of the annual maximum consumption, on average. Commenters noted that, whi le New York and New England's pipeline infrastructure is constrained to serve daily peak n atural gas demand during winter months, the
rest of the U.S. does not suffer such infrastructur e constraints. Commenters stated that, as with all systems delivering energy to consumers during e xtreme weather events, the system can be stressed; however, these events are infrequent acro ss the years and relatively short in duration. Commenters stated that, while the 2013-2014 winter severely stressed the electric grid and the natural gas delivery system, no bulk power outages occurred, and natural gas customers utilizing firm contracts did not experience supply curtailmen ts. Commenters stated that, when looking across regions more broadly, the following studies support the significant availability of delivered gas supplies for electric power generatio n:

• The FERC determined that if similar conditions to l ast winter emerged this winter, Mid-Atlantic demand would be slightly highe r; however, natural gas spot prices at certain liquid trading points would likel y not be as severe due to new pipeline capacity coming online by the start of win ter.

• The "Natural Gas Infrastructure Adequacy in the Wes tern Interconnection: An Electric System Perspective" interim report for the Western Interstate Energy Board found that "existing gas transportation infra structure will generally be adequate to meet the regional needs of the electric sector except under extreme
winter conditions."

• The Electric Reliability Council of Texas ("ERCOT") commissioned a study in 2012 to examine the risk of gas supply curtailment to electric generators within its service. The study found that ERCOTs electric gener ators' gas supply capacity "is well in excess of their peak natural gas needs."

• The Midcontinent Independent Transmission System Op erator ("MISO") commissioned a study to examine the availability of pipeline capacity to serve natural gas-fired generation in its footprint. The study found that, "[o]verall, pipeline capacity in the MISO Midwest is positive a nd continually improving due to shale gas developments and accommodating pipelin e expansions, contract expirations and the benefits of increased pipeline reticulation underway in the
Eastern Interconnect."

Commenters stated the existing NGCCs in Arkansas ha ve sufficient gas supply to run at 100% capacity now under most conditions. Commenters stat ed the EPA's Air Permits Program Database shows each of Arkansas NGCC operating at o r above its rated capacity in some hours of each year, so they clearly have adequate connect ions to the gas pipeline system. Commenters stated that, considering the enormous supplies avai lable from the Arkansas wellheads and239

pipelines, no additional infrastructure is likely t o be necessary for Arkansas NGCCs to operate at 70% capacity factors. Commenters stated Arkansas pr oduces an average of 3,132,000 MMBtu/day, enough to power about 18,000 MW of NGCC at 100% capacity factor or 26,000 MW at 70%. Arkansas has only a total of about 5,10 0 MW of coal plants subject to reduced usage or retirement, and had only about 700 MW of u nderutilized NGCC capacity in the average
hour of 2012. Commenters noted Arkansas also lies o n a massive pipeline corridor from the gas fields of Oklahoma, Texas, and Louisiana to the Mid west and stated that, as long as gas is available in North America, which seems very likely for at least the next few decades, adequate supply should be available for Arkansas generation.

Flexibility to average allows states to comply.

Commenters stated that the proposed rule provides f lexibility for states to comply by allowing them to average the CO2 emissions rate associated w ith affected units across a state, within a year, for each year during the 2020 to 2029 period. Commenters added that the EPA's rule can be implemented through a mass-based allowance system, under which emissions allowances can be traded on an interstate basis with other states (wh ich commenters recommended as discussed elsewhere in this document). Commenters concluded t hat all of this suggests that the existence of a current infrastructure constraint need not preclu de CO2 reduction through re-dispatch.

Commenters stated that the seasonal pattern of dema nd for natural gas transportation services, current efforts to address peak day infrastructure constraints and the flexibility of compliance provisions under the proposed rule all support the stringency of building block 2. Commenters disagreed with some other commenters' suggestions t hat the EPA's building block 2 assumptions are unrealistic due to existing constraints in natu ral gas supply. While conceding that transport constraints exist during some peak demand days in s ome regions of the country, commenters stated that transport capacity is still available f or re-dispatch in unconstrained regions and off peak times of the year. Commenters indicated that n atural gas consumption in the United States peaks during the winter home heating season and int erstate gas pipeline capacity is often fully utilized during at least some of that season, but i n other times of the year pipeline capacity is
often available unless it is used to fill market-ar ea storage or for other purposes. Commenters stated that this capacity could allow existing NGCC units to increase generating output without infrastructure expansion.

Commenters stated that certain stakeholders' concer ns regarding the adequacy of natural gas pipeline infrastructure to accommodate the increase d utilization of existing NGCC units appear to be unfounded and provide no justification for re ducing the utilization rate assumption in Building Block 2. Commenters referenced the NODA (7 9 FR 64543, 64546) and noted that some stakeholders have challenged the 70% utilization fa ctor that provided the basis for Block 2 by pointing to alleged deficiencies in natural gas pip eline infrastructure. Commenters stated that, because Block 2 is not premised upon the assumption that every existing NGCC facility in the U.S. will be utilized at a 70% capacity factor, the anecdotal information offered by some to suggest that particular existing NGCC facilities ma y not be able to achieve a 70% capacity factor today, due to their geographic location and existin g pipeline constraints, does not provide a basis for applying a lower capacity factor in the calcula tion of Block 2. The commenters stated that, in the event there are existing NGCC units that cannot increase their utilization due to existing pipeline constraints, the projected expansion of th e natural gas pipeline system leading up to240

2020 should be more than sufficient to ensure addit ional pipeline capacity and flexibility in meeting any increased demand for natural gas caused by the Clean Power Plan. The commenters referenced EIA and FERC reports and stated this is underscored by the significant number of natural gas pipeline projects under development (in cluding expansions, new pipelines, laterals, and reversals) that will collectively provide the c apacity to transport an additional 65 BCF/d of natural gas by 2020 (EIA-NaturalGasPipelineProjects .xls (Oct. 1, 2014), available at : http://www.eia.gov/naturalgas/data.cfm#pipelines; see also FERC, Major Pipeline Projects on the Horizon, http://www.ferc.gov/industries/gas/ind us-act/pipelines/horizon-pipe.pdf (indicating that 21.96 BCF/d of new interstate pipeline capacit y is in development). Commenters stated that, accordingly, claims about insufficient natural gas pipeline capacity provide no basis for EPA to
amend its Block 2 benchmark.

New England's infrastructure is not representative of the U.S.

Commenters indicated that concerns regarding gas de liverability and electric supply in New England are not representative of electric-gas cond itions across the country, illustrating this with a figure from EIPC's Target 1 Report, titled "Basel ine Existing Natural Gas-Electric System Interfaces" (EIPC, Target 1 Report, Table 7, availa ble at: http://www.eipconline.com/GasElectric_Documents.html). Commenters went on to not e that the gas and electric industries, along with federal and state regulators, are engage d in multiple efforts to assess and, where needed, bolster the adequacy of fuel transport and storage systems. Commenters believed that for this reason, it is likely that any critical infrast ructure constraints can be addressed.

Commenters stated there are several factors that ma ke New England unique and an inappropriate example to use for comparison with other regions of the U.S.:

• First, New England does not have the geology to sup port geologic gas storage like the rest of the U.S. Due to this issue, liquefied n atural gas ("LNG") peaking storage facilities are used to manage winter local distribution company loads (mainly residential and commercial customer heating demand). This type of storage is more expensive than geologic storage; he nce, if market rules do not allow for cost recovery, it is difficult for custom ers to afford such services.

• Second, New England demand is highly seasonal. Beca use the total gas consumption swings greatly between summer and winte r, significant amounts of pipeline capacity are available for electric genera tors during non-winter months. This seasonal demand profile, coupled with cost rec overy challenges in the region's electric market rules reduces the incentiv e for electric generators to commit to firm pipeline capacity.

• Third, New England ISO electricity market schedulin g differs from that of New York ISO, thus creating a disadvantage for New Engl and because New York is able to procure gas earlier in the day, leaving New England to procure gas in tighter market conditions as the daily gas volumes are sold most heavily in the morning hours. Even with all of these challenges, t he incremental pipeline capacity provided by the Algonquin Incremental Mark et Project ("AIM") is241 expected to greatly reduce volatility in the region . This project is scheduled to
come online in November 2016.

FERC actions are enhancing the infrastructure.

Commenters stated that improvements to gas market d esign such as those currently being considered by FERC will considerably enhance gas su pply and deliverability to power generators from the existing infrastructure, which would allow the electric power sector to reduce emissions at a lower cost than would otherwise be possible. C ommenters stated that while some additions to today's natural gas delivery infrastructure may be necessary before 2030, the current natural gas delivery infrastructure is robust and is capabl e of delivering significantly more natural gas to the power fleet than it does today. Commenters indi cated that this is particularly true on an annual basis, but is also true even during peak per iods of demand. According to the commenters, even during extreme cold weather conditions when ag gregate natural gas demand for both heating and electric generation is highest (such as during the January 2014 polar vortex), many pipelines have available and unused capacity to del iver more gas. Commenters noted that FERC
is in the midst of efforts to refine the standards and rules governing interstate gas transportation to, among other things, ensure that the market desi gn better serves natural gas-fired electricity generators. Commenters stated that FERC issued a No tice of Proposed Rulemaking on March 20, 2014, regarding proposed revisions to the sched uling practices used by interstate natural gas pipelines to schedule natural gas transportation se rvices (79 Fed. Reg. 18, 223). According to the commenters, FERC proposed, as part of a series of o rders, to revise its regulations to better coordinate the scheduling of natural gas and electr icity markets "in light of increased reliance on natural gas for electric generation..." because "th is trend is expected to continue, resulting in greater interdependence between the natural gas and electric industries" (79 Fed. Reg. 18, 224).

Commenters stated that beginning in 2012, FERC host ed a series of meetings to engage natural gas pipelines, electric transmission operators, and other market participants and stakeholders in both industries regarding natural gas and electric industry coordination. Commenters noted that in its April 2013 technical conference, market part icipants and FERC staff considered natural gas and electric scheduling practices including whether and how natural gas and electric industry
schedules could be harmonized in order to achieve t he most efficient scheduling systems for both industries (citing "Staff Report on Gas-Electric Co ordination Technical Conferences," Docket No. AD12-12-000, available at http://elibrary.ferc. gov/idmws/File_List.asp). Commenters stated that the FERC proposal was issued in response to an interest in updating market design to enhance the ability of natural gas-fired generators to acquire natural gas, and to augment the means by which the pipelines schedule and deliver n atural gas to power plants.

According to commenters, the FERC action proposes t o align the timing for gas pipeline scheduling and delivery to the timetables and utili zation patterns prevalent in the electricity markets (e.g., the morning ramp up), and also propo ses to increase flexibility for gas-fired generators by requiring pipelines to provide additi onal delivery scheduling opportunities so that power grid operators and power plants can better ad just to contemporaneous market and operational conditions. Commenters indicated that i n the proposal, FERC presented specific proposed reforms to existing natural gas industry s cheduling practices and also provided market participants within the natural gas and electricity industries an opportunity to collaboratively develop alternatives for changes in scheduling prac tices, through a consensus standards-242

development process at NAESB. Commenters stated tha t after a series of meetings and votes over the summer 2014, representatives of the two in dustries reached a series of agreements to enhance coordination and NAESB subsequently filed a series of consensus standards with the Commission on September 29, 2014. Commenters added that while there remains an open issue regarding the start of the gas day, it is highly li kely that FERC's final order, when issued, will include a series of new scheduling and delivery sta ndards which will enhance the operational capabilities of natural gas-fired power plants and the deliverability of natural gas.

Comment 2: Commenters stated that, if additional pipeline cap acity is needed to support compliance with the Clean Power Plan, INGAA is conf ident that the industry will be able to respond to this demand, although the ability to res pond in a timely manner depends on several factors including making improvements in the permit ting process.

Commenters referenced a 2014 NYISO reliability stud y and stated that, because of this constraint, it is not possible to access all the in stalled NGCC capability that is located in UPNY (NYISO's 2014 Reliability Needs Assessment at pp. 2 4 and 28, available at http://www.nyiso.com/public/webdocs/markets_operati ons/services/planning/Planning_Studies/ Reliability_Planning_Studies/Reliability_Assessment _Documents/2014%20RNA_final_091620 14.pdf.)

The EPA agrees to the extent that the industry has demonstrated the ability to add needed infrastructure. For EPA's response to this comment see section V.D of the final rule preamble of the CCP and Chapter 3 of the GHG Mitigation Measure s TSD for the CPP Final Rule supporting the final CPP. Pipeline permitting is not addressed here as this is outside of the scope of the CPP.

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

Commenters stated that pipeline companies do not bu ild new pipelines or add capacity to existing pipelines based on speculation or any pre- determined schedule or master plan; rather, pipelines are built and capacity is added when cred itworthy shippers commit to long-term (e.g., 15-year) contracts for firm transportation service. In connection with this point and in order to ensure that there is no confusion regarding the pro cess for developing new pipeline capacity, commenters provided some context and clarification to a statement in EPA's analysis.

EPA states: The third consideration supporting the conclusion regarding the adequacy of the infrastructure is that pipeline and transmissio n planners have repeatedly demonstrated the ability to methodically relieve bottlenecks and expand pipeline capacity. Natural gas pipeline capacity has been regularly added in respo nse to increased gas demand and supply, such as the large amounts of new NGCC capac ity from 2001 to 2003, or the delivery to market of unconventional gas supplies s ince 2008 (79 FR 34829, 34864).

While EPA refers to "pipeline planners," it should be understood that, unlike electric transmission lines, interstate natural gas pipeline s are not "planned" in a centralized manner or on a regional basis. Pipelines are developed competiti vely in response to the market demand that manifests itself in the willingness of shippers to commit to long-term contracts for firm pipeline243

service. Often more than one pipeline competes for a market opportunity. It is the market that determines the winners in this competition, i.e., w hich of the competing proposals receives sufficient shipper commitments enabling it to proce ed. While pipeline developers are aware of forecasted increases in supply and demand, this alo ne is not the basis for proceeding with a pipeline project, i.e., pipelines are not built on speculation. Consequently, while the development of unconventional natural gas supplies spurred dema nd for additional pipeline capacity, those pipelines were not developed until shippers (typica lly natural gas producers or natural gas marketers) contracted for the capacity to transport their supply to the market. Similarly, while the addition of new NGCC capacity created additional de mand for pipeline capacity, pipelines were not developed until shippers committed to long-term firm contracts for the pipeline capacity that would be used to satisfy that demand. In fact, deve loping pipeline capacity to serve the demand created by NGCCs in organized wholesale power marke ts (and, in particular, the markets in which generation has been divested by incumbent uti lities) has been problematic. Rules in those markets create little incentive or ability for merc hant generators to contract for firm pipeline capacity. According to the commenters, this is an i mportant point in connection with satisfying the need for new interstate natural gas pipeline ca pacity that may be created by implementation
of the Clean Power Plan.

Commenters stated the legal and regulatory process for siting and permitting new pipelines and adding capacity on existing pipelines is a very com plex multi-year process, in which the time between the inception of a pipeline project and an in-service pipeline historically has averaged about three years, depending on the size and comple xity of the project and issues encountered in the permitting process. Commenters stated that, whi le it can be significantly shorter if mainline pipeline capacity is available and only a lateral p ipeline is needed to connect the new customer, the process can be significantly longer if the prop osed routing of the pipeline is contested or if it is difficult to obtain necessary permits. Commenter s stated that recent experience indicates that the pipeline siting and permitting process is becom ing more challenging and continued performance at this rate should not be taken for gr anted.

Commenters stated the state implementation plans mu st allow sufficient time to (1) identify the instances in which incremental pipeline capacity wi ll be needed, (2) ensure that a creditworthy entity has the ability to contract for long-term, f irm pipeline service (i.e., ensure cost recovery in that entity's rates, if it is a regulated utility, or by other means if it is not), and (3) site, perm it and
construct the needed facilities. Commenters stated that, while pipeline operators can work with generators and with state authorities to explore so me of these questions prior to the finalization of state implementation plans, actual commitments b y shippers to subscribe firm pipeline capacity and by pipelines to develop new facilities are unlikely to occur until it is certain what will be required pursuant to a state implementation plan.

Commenters stated that the part of this process wit h perhaps the greatest potential for improvement is the permitting that must occur in co njunction with the certificate of public convenience and necessity issued by FERC pursuant t o the Natural Gas Act. Commenters stated these permits ensure compliance with other federal resource and environmental laws, such as the Endangered Species Act and the Migratory Bird Treat y Act. Commenters stated that delays in processing and issuing these permits can add signif icantly to the time needed to construct a pipeline project. Commenters suggested the EPA shou ld be mindful of how regulations and244

associated permitting requirements within the scope of its authority will affect the ability to add the natural gas pipeline infrastructure that will f acilitate compliance with the Clean Power Plan.

Commenters suggested the EPA support the Obama Admi nistration in its efforts to improve the efficiency of the federal permitting process for in frastructure that contributes to economic growth and the achievement of other public policy objectiv es, since Interstate natural gas pipelines fit squarely within this category. Commenters suggested the administration should work constructively with the Congress on statutory refor ms that will make it possible to increase the efficiency and predictability of pipeline permittin g. Commenters noted that any deterioration in the efficiency of this process at the federal and s tate levels will impair the ability to add pipeline capacity in a timely manner, which would frustrate implementation of the Clean Power Plan by creating uncertainty about the ability to add pipel ine capacity in a timely and predictable manner and thereby support the increased utilization of NG CCs.

Comment 3: Commenters stated the advantages of clean-burning n atural gas-fired generation consistently outweigh other alternatives, even duri ng extreme weather events.

Response 3: The EPA agrees to the extent that natural gas suppl y is adequate to allow for establishment of CO2 emission standard rates, and t hat generation shifting is an appropriate approach. See section V.D of the final rule preambl e of the CCP, Chapter 3 of the GHG Mitigation Measures TSD supporting the final CPP, a nd the regulatory impact analysis of the

final CPP.

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

Commenters stated that, although the winter of 2013 /2014 created multiple challenges for grid operators, the majority of problems encountered dur ing these extreme conditions were not an issue of natural gas availability. Commenters cited a letter from PJM in response to questions about the polar vortex from members of the U.S. Hou se Committee on Energy and Commerce:

Although there has been much focus on gas issues as sociated with interruptible transportation, overall the gas interruptions were not the major dr iver of the high forced outage rates experienced in the PJM region. Natural gas interrup tions, although significant, removed less than five percent of the total capacity required to meet demand on January 7, while equipment issues associated with both coal and natural gas units mad e up the far greater proportion of forced outages.19 More than three quarters, or 30,900 MW, of the forced outages were associated with equipment breakdowns, startup failures, and ot her problems related to operating generating facilities in extremely cold temperatures. These pr oblems impacted all generation types, including 14,000 MW of coal capacity, 9,700 MW of n atural gas capacity, 1,400 MW of nuclear capacity, and 6,100 MW of other capacity (including hydropower and oil). An increased focus on cold weather preparedness should help to mitigat e these problems in the future.

Commenters stated these "interruptions" were a func tion of the gas delivery contracts generators had with the pipelines. Commenters stated that, in times of high demand, generators holding a lower-cost, interruptible contract will see that se rvice interrupted - that is wholly consistent with245

the contractual agreement and not a function of nat ural gas availability. Commenters stated this aspect is acknowledged in a separate communication where PJM noted that, "the gas supply problems experienced last winter were primarily con tractual and economic, not physical constraints, meaning that for many gas-fired genera tors, fuel firmness can be achieved through new arrangements with marketers even witho ut expansion of the gas pipeline system" which further demonstrates that natural gas availab ility was not the source of problems encountered during the polar vortex.

Commenters stated existing NGCC resources have the ability to operate at high utilization levels, at or above 70 percent, without sacrificing the abi lity to fill other needs; specifically, NGCC units running at high capacity factors may still op erate as load following units and retain the ability to quickly ramp up or down in response to f luctuations in renewable energy supply and electricity demand throughout the day. Commenters s tated the operating characteristics of natural gas-fired power plants enable the expansion of inte rmittent resources, like solar and wind, allowing grid operators to keep supply and demand o f electricity in balance. Commenters stated the presence of natural gas generation provides gri d operators the freedom to accept capacity from renewable energy sources without putting elect ric system reliability at risk. Commenters
cited a number of studies that have affirmed the im portant role of natural gas-fired power plants in enabling renewable power.

Commenters described a number of benefits related t o using natural gas for electric generation, including low-cost technology, reliable baseload, p eaking or intermediate power, ability to ramp up quickly, increased grid diversity, reduced air p ollution, and ability to accommodate intermittent electricity sources such as wind and s olar generation. Commenters stated the capacity of natural gas to meet growing energy dema nds is particularly significant in light of the resurgence in U.S. manufacturing and noted natural gas facilities are scalable and require only minimal lead time as compared with other traditiona l power sources. Commenters referenced EIA data and stated that, in light of the continued positive outlook for natural gas supply and availability, the electricity sector's use of natur al gas as fuel will not hinder manufacturing and commercial growth and, more specifically, will not impede the availability of natural gas as a
feedstock for other industrial uses. Commenters sta ted that NGCCs can effectively and efficiently supply baseload power to the electric p ower system. Commenters noted that, in 2013, natural gas-fired power plants accounted for over 5 0 percent of new utility-scale generating capacity7 with about half of that capacity in the f orm of NGCC power plants that provide intermediate and baseload power. Commenters stated that, over the first six months of 2014, natural gas-fired power plants again made up more t han half of the utility-scale capacity
additions in the United States and almost all of th ese plants were NGCC, the majority of which are designed to serve baseload power in the regions in which they operate. Commenters stated there is a recognition in the industry that current price and regulatory dynamics have created an opportunity for existing NGCCs to increase utilizat ion and act as a baseload resource.

Comment 4: Commenters expressed concern regarding extreme weat her events impact on the electric system and failure of pipeline infrastruct ure to keep pace with demands.246

Response 4: The EPA disagrees that these considerations preven t the achievement of the goals. In response to additional analysis and many comments, we have modified the proposal and RIA. The 111(d) final rule requires that states dev elop plans that establish emission standards for affected EGUs. We are providing states with substan tial flexibility as to how they structure those plans to achieve the 111(d) requirements. The flexi bility includes, for example, the choice of approaches, trading, time to develop plans, additio nal time before the start of the interim performance period (postponed from 2020 until 2022) , and the ability to shift emission rate achievement between performance periods. Neither th e Building Blocks nor the IPM analyses are prescriptive, and states may consider local cir cumstances as they develop their plans, including system reliability, fuel diversity, the p ossibility of extreme events, other regulatory requirements and infrastructure. See sections V.A, V.B, V.D, VIII.A, VIII.C and VIII.G of the final rule preamble of the CPP and Chapter 3 of the GHG Mitigation Measures TSD for the CPP Final Rule supporting the final CPP.

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

Commenters referred to last winter's polar vortex w hen electric power companies up and down
the eastern and southern United States scrambled to deploy all generating assets. Commenters cited the polar vortex from the winter of 2014 when stating that many natural gas system operators faced significant reduction of generation capacity as a result of curtailments and gasfired generation during extreme weather events. Com menters stated that, in an integrated natural gas/electric power market following implementation under the proposed rule, where gas delivery systems will be further strained as more gas-fired electric generating units displace coal-fired units, a similar polar vortex event could cause maj or interruptions in meeting peak heating demand. Commenters noted that the current natural g as pipeline system is not equipped to accommodate greater utilization of natural gas-fire d generation, and since natural gas pipelines are only built after customers have subscribed to t he majority of the pipeline's capacity, there is not sufficient time to build addition natural gas i nfrastructure to support expanded natural gasfired generation as a result of the timing of the p roposed CPP.

Commenters noted that natural gas delivery restrict ions to power plants during the 2014 winter resulted in an increase in prices over 1,000 times greater than normal prices. Commenters questioned how the EPA proposes that states mitigat e increased exposure to extended electrical power outages caused by natural disasters when pipe lines are severed and pipeline pump stations are closed down. Commenters noted that natural gas plants only have seconds of onsite storage, but, as noted by commenters, coal-fired power plant s have a 45-day supply of resources onsite, which allows for greater reliability of energy supp ly and price volatility. Commenters also noted that many coal plants in existence today and which will be affected by the proposed rule were built in the 1970's when it was illegal to build na tural gas plants.

Commenters urged the EPA, in its finalization of th is rulemaking, to factor into its BB2 analysis a more refined consideration of the impacts of extr eme weather events on the ability of gas-fired generation in the PJM region to manage increased di spatch under extreme cold weather events. Commenters stated this would require a closer consu ltation by EPA with entities such as NERC,
INGAA and PJM. Commenters stated the EPA's sole rel iance on traditional historic EIA and247

INGAA reports fail to account for the impacts of ex treme weather events and the stressors these events place on the system.

Commenters stated the EPA relies on EIA and industr y publications, primarily INGAA's Midstream Infrastructure Report through 2035, to su pport its assertion that the industry can currently manage intermittent gas pipeline constrai nts, relieve bottlenecks and expand capacity. Commenters stated the INGAA Report's principal find ings indicate that significant infrastructure will be needed to support growing gas use. Commente rs stated the base case assumes $100 per barrel of oil and shows gas prices rising from $4 p er MMBtu to an average of $6 per MMBtu in the longer term. Commenters stated the base case pr ojects significant supply development and growth in gas production, primarily from shale reso urces. Commenters stated producers are likely to develop shale resources with large quanti ties of oil and gas, which also have significant needs for new pipeline infrastructure. Commenters s tated the base case projects substantial gas production growth, especially from the Marcellus an d Utica shale regions in the northeastern United States and also from other shale regions in the U.S. and Canada. Commenters stated a significant number of gas processing, pipeline, and fractionation facilities will also be required to accommodate growing gas production.

Commenters stated that, as last winter's "polar vor tex" demonstrated, pipeline capacity failures during extreme weather conditions and general break down of pipeline infrastructure is a continuing reality. Commenters stated that on Janua ry 8-9, 2014, PJM experienced a 22% forced outage rate during an extreme cold weather event wi th gas supply failure a major contributing
factor. Commenters stated the breakdown of forced o utages by primary fuel type shows that natural-gas-fired generators accounted for 47 perce nt of the unavailable megawatts. Commenters stated the 9,300 MW of generation that was unavaila ble due to natural gas interruptions was a larger amount than PJM reported immediately after J anuary 7. Commenters stated that, subsequent to January, PJM worked with generation o wners to further validate the outage reasons, and, based on these additional discussions , natural gas issues were found to be larger than initially reported largely due to other genera tion fuel types being dependent on natural gas and the natural gas infrastructure. Commenters stat ed an example is a generator that burns oil but that needs natural gas to start up. Commenters refe renced the 2014 NERC Report on the Polar Vortex and stated this report highlighted the contr ibution of gas supply shortfalls as follows:

• One of the largest issues impacting gas-fired gener ation was the curtailment or interruption of fuel supply. Unlike other fuel sour ces, natural gas is not typically stored on site. As a result, generators rely on rea l-time delivery of natural gas from their suppliers. Often, as units are not confi dent that they will be dispatched, the fuel is obtained on the spot market as an inter ruptible fuel supply.

Comment 5: Commenters agreed the EPA should seek to lower CO2 emissions by redispatching the electric generating fleet, but the commenters expressed concern that the necessary infrastructure for this re-dispatch to oc cur may not be available in time.

Response 5: The EPA agrees that shifting generation is an effe ctive means to reduce CO2 emissions. EPA disagrees that natural gas infrastru cture will prevent the achievement of the248

goals. In response to additional analysis and many comments, we have modified the proposal and RIA; the establishment of CO2 emission reduction st andards is regionally based. The 111(d) final rule requires that states develop plans that establish emission standards for affected EGUs. We are providing states with substantial flexibilit y as to how they structure those plans to achieve the 111(d) requirements. The flexibility in cludes, for example, the choice of approaches, trading, time to develop plans, additional time bef ore the start of the interim performance period (postponed from 2020 until 2022), and the ability t o shift emission rate achievement between performance periods. Neither the Building Blocks no r the IPM analyses are prescriptive, and states may consider local circumstances as they dev elop their plans, including system reliability, fuel diversity, other regulatory requirements and i nfrastructure. See sections V.A, V.B, V.D, VIII.A, VIII.C and VIII.G of the final rule preambl e of the CPP and Chapter 3 of the GHG Mitigation Measures TSD for the CPP Final Rule supp orting the final CPP.

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

Commenters stated its belief that most NGCC facilit ies have the technical capability to operate at an average annual capacity factor of 65 or 70 perce nt, and noted that several plants owned by member of the commenters' trade association have op erated above these levels for extended periods of time. Commenters indicated that whether the system as a whole can operate with most states' NGCC fleets averaging this utilization leve l by the early part of the compliance period (as implied by the goal computation) is less clear. Acc ording to the commenters, many states would be able to rapidly increase the utilization of exis ting NGCC facilities, but others may require
additional time because of infrastructure constrain ts, characteristics of existing in-state generation facilities or because of their load cent ers' locations in the electric or gas transmission system. Commenters stated that procuring adequate n atural gas supplies to sustain a high level of utilization year round could mean, in the case of s ome states, building new pipelines or increasing the capacity of existing ones, while in others getting the electricity to consumers currently served by steam units without expanding t ransmission may be a challenge.

Based on these types of uncertainties, commenters r ecommended that the EPA establish a more strategic approach to Building Block 2. While agree ing with the EPA's conclusion that, over time, existing fleets have the technical capability of reaching a 70 percent capacity factor and agreeing with the EPA's finding that states could c omply with the emission guidelines without increasing NGCC utilization to 70 percent, commente rs would support changes to the rate at which Building Block 2 is deployed as part of the g oal-setting process. Commenters added that as much as the shift EPA has proposed as a part of Building Block 2 is about increasing NGCC utilization, it is also about decreasing boiler ste am generation and replacing the services that boiler steam capacity currently provides to the gri d.

Comment 6: Commenters disagreed on the feasibility of EPA’s ca pacity factor used in developing the CPP goals. Some stated that the EPA has not adequately considered the many system constraints that will limit the level of re- dispatch to NGCCs that is achievable under building block 2, while others contended that it wa s feasible.249

Response 6: The EPA disagrees that we have inadequately conside red technical and regulatory constraints on the utility power system. In respons e to additional analysis and many comments, we have modified the proposal and RIA; the establis hment of CO2 emission reduction standards is regionally based and additional time is provided to achieve the performance goals. The 111(d) final rule requires that states develop plans that establish emission standards for affected EGUs. We are providing states with substantial flexibilit y as to how they structure those plans to achieve the 111(d) requirements. The flexibility in cludes, for example, the choice of approaches, trading, time to develop plans, additional time bef ore the start of the interim performance period (postponed from 2020 until 2022), and the ability t o shift emission rate achievement between performance periods. Neither the Building Blocks no r the IPM analyses are prescriptive, and states may consider local circumstances as they dev elop their plans, including system reliability, fuel diversity, the “useful life” of generation ass ets, other regulatory requirements and infrastructure. See sections V.A, V.B, V.D, VIII.A, VIII.C and VIII.G of the final rule preamble of the CPP and Chapter 3 of the GHG Mitigation Meas ures TSD for the CPP Final Rule supporting the final CPP.

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

Commenters stated that the proposed rule incorrectl y assumes in building block 2 that there is sufficient generating capability from Oregon's exis ting NGCC units to fully displace Boardman's generation today. Commenters said Figure 2 (titled: “2012 Oregon Fossil Generation by Month”) shows the monthly generation from Oregon's fossil E GUs in 2012 and the hypothetical generation from the state's NGCC units constantly o perating at a 70 percent capacity factor. Commenters stated that the months when the green li ne is above the red line - late winter and late summer/early fall - demonstrate that Oregon's NGCC units do not have the excess NGCC generating capability at 70 percent capacity factor to fully displace Boardman's generation and meet the total demand previously served by affected EGUs. Commenters continued, stating that the proposed rule compares annual fossil generation and annual NGCC generation at 70 percent capacity factor, but this analysis misrepresents th e actual amount of additional capacity available in the northwest. Commenters said the majority of f ossil generating capacity in the northwest does not operate in the spring, when load is relati vely low and hydropower and wind resources are relatively high. Commenters said the lack of fo ssil generation during the spring creates the illusion that the state has available NGCC capacity to fully displace coal, when in reality it does not. Commenters added that the proposal's use of 20 12 as the base year further exacerbates the over-estimation of available gas capacity in Oregon , explaining that annual hydropower generation in 2012 was more than 127% of the 30-yea r historic average. Commenters noted that high hydropower production, such as what was observ ed in 2012, displaces fossil generation in the Northwest, and conversely, in average and low w ater years, northwest fossil plants are dispatched at much higher levels to meet the region 's power needs, particularly in the winter months. Commenters believed the proposal's analysis does not reflect more typical rates of gas utilization, however.

Commenters stated concern that not all NGCC plants in Indiana will be able to operate at a 70% capacity factor as proposed by the application of B SER under Building Block 2. Commenters explained that based on consultation with electric utilities in Indiana and surrounding states that run NGCCs, there is concern whether older facilitie s will be able to run at 70% capacity factor250

due to the age of the equipment and the required ma intenance. Also, commenters said some NGCCs have been built using equipment from older co al units and as a result are not as efficient
as newer units.

Commenters' general concerns are identified below a nd cover several issues, including contractual obligations, transmission capacity cons traints, pipeline availability, security considerations, and air quality limitations. Many o f these issues are addressed in more detail in other portions of section 3.2.4.

Contracts and costs

Commenters stressed that assumptions regarding 70 p ercent capacity factors for NGCC units do not consider market prices or firm pipeline capacit y. Commenters asked the EPA to carefully consider the assumptions that underlie the proposed rule.

Commenters stated that an indication of where incre ased natural gas demand may signal some risk for the power sector is if demand in the area has already experienced pricing pressure. Commenters stated that empirical analyses of spot p rices identify those regions of the interstate pipeline network that are sensitive to constraints. Commenters identified pipelines and market areas that showed sustained price spreads (basis di fferentials) between the pipeline-based trading hubs and the reference Henry Hub market. Commenters noted that a hub was considered to be constrained on a trading day if its closing price w as double the price at Henry Hub; if the hub was constrained more than 250 times between June 1, 2009 and October 6, 2014 then it was classified as congested. Commenters provided a tabl e (titled: “Historically-Congested Pipelines / Trading Areas"), which listed ten natural gas pipel ine hubs, including: Texas Eastern Transmission (TETCO) M3, Transcontinental Pipeline (Transco) Zone 6 Non NY, Dominion South, Maritimes & Northeast Pipeline, Iroquois Zon e 2, North East Dracut, Boston / New England City Gate, El Paso, Northeast Transco Zone 6, Tennessee Gas Pipeline Zone 6.

Commenters stated that Building Block 2 is not a vi able option because natural gas is not an
available fuel without limitations. Commenters stat ed that SCANA, like many utilities, has insufficient firm capacity on the interstate pipeli nes to increase natural gas usage for many of its
units. Commenters stated SCANA would need additiona l firm pipeline capacity on Carolina Gas Transmission Corporation (CGT) and an upstream inte rstate pipeline - either Transcontinental Gas Pipeline (Transco) or Southern Natural Gas Comp any (SNG). Commenters noted that for the past several years, CGT has reported that its pipel ine is "essentially full," and Transco and SNG are also fully subscribed. Commenters stated this m eans that additional pipeline facilities or system modifications would be required for SCANA to obtain additional natural gas capacity. Commenters stated that, pursuant to FERC regulation s, projects to add capacity to natural gas pipelines are subject to a lengthy approval process . Commenters stated that, it may sound easy to re-dispatch from coal to natural gas, but this cann ot be done if there is a shortage of natural gas
available to use as fuel.

Commenters stated that in Building Block 2, EPA pro jects that coal-fired electricity generation can be reduced significantly by prioritizing the di spatch of NGCC facilities ahead of coal-fired EGUs. Commenters recognized the critical role that natural gas fired EGUs - and in particular NGCC turbines - have and will continue to play in e nsuring the reliable supply of low-cost251

electricity throughout the United States and does n ot dispute that many NGCC facilities are capable of operating at an average capacity factor of 70% or more. However, commenters said EPA is arbitrarily and capriciously relying on the fact that all NGCC facilities in a given State are necessarily capable of simultaneously operating at a 70% capacity factor by 2020, when EPA assumes that Building Block 2 will be implemented, explaining that EPA did not fully account for several current challenges associated with exis ting NGCC units in its BSER analysis. Commenters continued, stating that while it is only a function of time until infrastructure and supply constraints, EPA must evaluate existing NGCC facilities within the context of the existing infrastructure in the States in which they are oper ated, and, when viewed in that context, there are a number of challenges that must be considered when determining whether existing and under construction NGCC facilities collectively can be dispatched at a 70% capacity factor in a given State. Commenters believed EPA's proposal is arbitrary and capricious because it does not adequately evaluate the potential impact of those a dditional real-world factors on States - ability to achieve EPA's Building Block 2 projections in th e time frame contemplated by the Agency. Commenters provided 6 supporting statements for their position.

1. Commenters said even if EPA is correct that, as a t echnical matter, all existing NGCC facilities are capable of operating at 70% capacity , EPA did not consider whether they were legally authorized to do so. Commenters said e xisting NGCC facilities operate pursuant to State-issued permits, and in some cases , those permits may limit a facility's hours of operation or total amount of fuel that can be used. Commenters said, for example, a facility may rely on a permit condition to limit operating hours or annual fuelfiring rates to maintain its status as a minor sour ce with respect to the Clean Air Act's PSD permitting program. Commenters said such a faci lity would effectively be barred from operating at the capacity envisioned by EPA. C ommenters said, likewise, in some cases, specific components at a facility may not be warranted to operate at a 70% capacity, and facilities would incur significant ec onomic risk by operating outside the
bounds of those warranties. Commenters believed it is arbitrary and capricious for EPA to ignore these legal constraints in its BSER analy sis. At a minimum, commenters suggested that EPA must provide a mechanism for Sta tes to adjust their emission reduction targets to account for any existing NGCC facilities that are not legally authorized to operate at 70% capacity.

2. Commenters stated, by relying on the nameplate capa city of NGCC facilities on an annual basis, EPA's analysis may mask seasonal vari ations that limit the amount of coalfired electricity generating capacity that can be r edispatched to NGCC facilities. Commenters said, because electricity demand is not consistent, EPA must account for cyclical demand when evaluating the amount of coal- fired electricity generation that can be displaced. Commenters said, for example, in high -demand summer months, NGCC facilities may already operate at or near 70% capac ity and, thus, may have little ability to further increase capacity in order to displace coal -fired electricity generation. Commenters said, in contrast, in months with lower overall demand, shifting generation to existing NGCC facilities may completely displace coal-fired electricity generation before a 70% capacity factor is achieved. Commenter s stated, as a result of these seasonal variations, existing and under construction NGCC fa cilities may not be capable of displacing as much coal-fired electricity generatio n as EPA projects, even if NGCCs operate at 70% capacity. Rather than relying on ann ual generation data, commenters252

suggested that EPA must incorporate seasonal variat ion to more accurately estimate the effect of increasing capacity at NGCC facilities.

3. Commenters said EPA's proposal assumes that electri city produced by different EGUs is completely fungible and that existing and under con struction NGCC facilities can immediately substitute for existing coal-fired EGUs . Commenters stated that EPA's assumptions ignore the non-generating services that some coal-fired EGUs provide to the electricity generation and transmission sectors. Co mmenters said, for example, coal-fired EGUs may be located strategically to provide voltag e support and other grid reliability benefits. Commenters said existing and under constr uction NGCC facilities at other locations may not be capable of replacing these fun ctions. Commenters said, likewise, certain coal-fired EGUs may be designated as "black start" facilities that are capable of restarting without any electricity input or for oth er reasons may be designated as "must run" facilities by FERC or RTOs. Commenters noted t hat these coal-fired EGUs cannot be retired and replaced immediately by existing or under construction NGCCs. Commenters stated, while new NGCC facilities could be constructed to provide those services, such new facilities are outside the scope of this rulemaking and EPA's BSER analysis. Commenters suggested that EPA's BSER anal ysis must address these other services currently provided by coal-fired EGUs and ensure that they can be provided by other EGUs on a time period that is consistent with EPA's compliance schedule.

4. Commenters stated that EPA does not give adequate c onsideration to infrastructure changes that may be needed to accommodate the incre ase in NGCC capacity envisioned in Building Block 2. Commenters noted, unlike coal- fired EGUs, NGCC facilities do not maintain onsite storage of feedstocks and instead r ely on real-time delivery of natural gas through pipelines. Commenters stated, in some cases , increased natural gas-fired electricity generation may strain or go beyond the capacity of existing pipeline systems and ultimately require additional infrastructure in vestments. Commenters said, likewise, because existing NGCC facilities are not co-located with the coal-fired EGUs whose generation they would displace, additional investme nts in transmission infrastructure may be needed to ensure that the electricity generated by existing and under construction NGCC facilities can reach consumers currently suppl ied by coal-fired EGUs. Commenters stated that the same challenges related to transmission infrastructure apply to increased renewable energy generation under Buil ding Block 3. Commenters noted, in fact, renewable energy generation may pose even mor e challenges, as locations with renewable energy generation potential may be far re moved from population centers that demand electricity. Commenters stated that EPA glos ses over these challenges by suggesting that any necessary infrastructure can be constructed to accommodate increased NGCC and renewable capacity. Commenters s aid it may prove challenging to finance, plan, and complete infrastructure projects by 2020, when Building Block 2 will be implemented under the interim compliance schedul e proposed by EPA. Commenters asserted that the challenges presented by EPA's com pliance schedule will be exacerbated by complex and, at times, inefficient federal permi tting systems and the opposition efforts that are often mounted against these large-scale in frastructure projects. Commenters said it is arbitrary and capricious for EPA to not consi der the degree to which new infrastructure investments will be needed to displa ce coal-fired electricity generating capacity and the time that such projects will take.253

5. Commenters stated that EPA simply assumes in its ca lculation of State emission reduction targets, without support, that all NGCC f acilities that are currently under construction will actually be completed and operate d. While the commenters had no reason to question the viability of any particular NGCC project, history has shown there is always a risk that unforeseen circumstances coul d cause an NGCC project to be stalled, delayed, postponed, or canceled. Nor, commenters re marked, does EPA provide a contingency plan to adjust a State's emission reduc tion targets in the event that construction of a facility is postponed or cancelle d.

6. Commenters said in the NODA EPA requests comment on "whether to establish a minimum value as a floor for the amount of generati on shift for purposes of building block 2" which could be achieved, in part, though c o-firing natural gas at existing cofired EGUs. 79 Fed. Reg. at 64,550. Commenters said , as an initial matter, EPA explicitly rejected co-firing natural gas as BSER in the propo sed rule, 79 Fed. Reg. 34,875, and provides no facts in the NODA or elsewhere in the r ecord that would provide a reasoned basis for the Agency to reverse course in a final r ule. Further, commenters noted that EPA does not offer any analysis of a number of pote ntial challenges to co-firing natural gas, including that (1) natural gas igniters instal led at coal-fired EGUs should not be run continuously because they are intended to operate d uring startup, shutdown, and periods of flame instability, (2) safety equipment such as flame scanners pose distinct safety challenges when gas igniters are used, (3) that con tinuous or long-term co-firing of natural gas can cause problems with ash accumulatio n, and (4) at lower loads, co-firing natural gas can increase emissions of NOx and CO an d reduce efficiency by forcing other units offline at the facility. Commenters suggested that EPA must more fully explore these potential challenges before relying on co-fir ing to reduce CO2 emissions. Commenters stated, further, while these challenges may be capable of being addressed through equipment upgrades and retrofits, EPA must consider both the cost of those upgrades and whether they would trigger a modificat ion under Section 111(b). Commenters stated EPA asserts in the proposed rule that the costs of fuel-switching from coal to natural gas would be between $83 and $150 p er metric ton of CO2 depending on the proportion of natural gas generation after modi fication. 79 Fed. Reg. at 34,875. Commenters said EPA concluded in the proposed rule that those costs were too high to qualify as BSER and, without a significant change i n EPA's cost analysis, it would be arbitrary and capricious for EPA to rely on co-firi ng

Infrastructure

Commenters stated that building block 2 increases t he utilization of combined cycle natural gas fire and presupposes that pipeline infrastructure i s adequate or that it can be built to enable plants to operate at 70 percent capacity factors. Commente rs noted that these are questionable assumptions on which to build building block 2.

Commenters stated that the EPA has not fully evalua ted the transmission and gas supply infrastructure issues that may significantly impact the feasibility and amount of potential redispatch. Commenters stated the EPA failed to suppo rt its claims that sufficient natural gas supply and pipeline capacity and electricity transm ission will be available, devoting only a single page of a 224 page technical support document to th e issue.254

Commenters stated the EPA has not addressed what ad ditional natural gas infrastructure will be needed to supply the natural gas required for drama tic increases in natural gas power generation. Commenters stated that the re-dispatch of natural g as for base load will likely require construction of new natural gas facilities and infr astructure in order to track demand and maintain system reserve requirements. Commenters st ated that, in the West, this likely means significant additional environmental reviews to per mit infrastructure projects on public lands.

Commenters stated that greater reliance on variable resources and gas-fired generation is expected: The CPP will accelerate the ongoing shift toward greater use of natural-gas-fired generation and variable energy resources (renewable generation). Commenters noted that increased dependence on renewable energy generation will require additional transmission to access areas that have higher-grade wind and solar resources (generally located in remote areas). Commenters added that increased natural gas use wil l require pipeline expansion to maintain a reliable source of fuel, particularly during the pe ak winter heating season. Commenters stated that pipeline constraints and growing gas and elect ric interdependency challenges impede the electric industry's ability to obtain needed natura l gas services, especially during high-use
horizons.

Commenters stated that the Proposed Rule assumes wi thout support that the gas distribution infrastructure needed to support increased reliance on gas generation exists or will soon be built. Commenters stated this may be true in certain parts of the country, but not others. Commenters (cited Moeller House Testimony and) stated that (1) gas pipeline developers are reluctant or even unable to build pipelines without anchor customers, like the natural gas generation owners that use gas; (2) these generation owners will not commi t to the long-term contracts unless they know how they will be dispatched in the long-term; (3) g as generation facilities are uncertain of how they will be dispatched in today's market, and they do not yet know what EPA's environmental dispatch will require; and (4) this dilemma is furt her complicated if generators are in organized markets that serve multiple States: under the Propo sed Rule, generators may be dispatched at different levels (and require different levels of f uel) depending on the location of their loads and their state's specific environmental dispatch requi rements. Commenters stated that, for these reasons, the Proposed Rule may actually be dis-ince ntivizing the development of the natural gas
infrastructure that EPA assumes exists. Commenters noted that institutional considerations that affect the development of new pipelines include per mitting of new interstate pipelines by the FERC; willingness of shippers to support new inters tate pipelines by entering into long-term capacity contracts; the needs for such long-term co ntracts to secure financing; and mechanisms by which shippers' capacity rights trade in a secon dary market. Commenters included the following description, analysis and findings:

The interstate pipeline system in the United States represents firm delivery capacity that was largely built to serve, and almost completely under written by, natural gas distributors and their
connected users. Traditional firm services were tai lor-made for the requirements of natural gas distributors, and the types of pricing of those ser vices (including straight-fixed-variable and incremental pricing) have been key parts of the fou ndation for the highly competitive deregulated capacity release market. Any new pipeli ne services or prices targeted at power generators would have to take into consideration th eir effect both on traditional services for natural gas distributors and on the working of the successful deregulated interstate pipeline capacity market. Electricity generators in competit ive market areas generally elect to take255

pipeline service on a non-firm/interruptible basis and have had only a limited effect on the development of the interstate pipeline system. Comp etitive electricity generators, operating in organized regional markets, have not yet had the ne ed to plan for storage, alternative fuels, or firm delivery service on interstate pipelines. Thes e costly services would reduce their earnings. NERA does not expect new interstate pipeline capaci ty to be forthcoming for electricity markets unless electric generators are willing to lock into a term contract for firm service. It is possible that generators operating as part of a state-regula ted, vertically-integrated utility will be able to lock in pipeline capacity for durations sufficient to support financing and construction of interstate pipeline capacity. However, merchant gen erators operating in competitive markets, with no regulatory backstop to support recovery of the costs, are not expected to enter into such contracts. Regional markets with competitive genera tors are more likely to face constraints in achieving the infrastructure build needed to accomm odate the fuel mix changes triggered by the EPA's CPP requirements. These regions include most of the states in the Northeast (e.g., in a quadrant including and to the northeast of Michigan , Ohio, and Maryland) plus Illinois, Texas, and Oregon. Whether these states are actually at ri sk of being unable to meet future natural gas demands, of course, depends on the extent to which natural gas demand projected by 2020 is likely to exceed 2012 levels. We have determined th at 2012 (the most recent peak year for natural gas consumption in much of the U.S.) provid es a good indication of the proven capacity to deliver natural gas to various states.

Commenters stated the significant resource adequacy and reliability risks arising from such a wholesale change in dispatching of the generation f leet under the proposed rule are unacceptably accounted for by EPA. Commenters stated the ability to transport much larger volumes of natural gas will be a significant challenge, especially so with the age of existing natural gas infrastructure and the large amounts of new natural gas pipeline needed to support growing gas volumes. Commenters referred to a ScottMadden repor t which indicated that much existing U.S. pipeline transmission capacity is 40 years or older and will require replacement at the same time large amounts of new midstream infrastructure are n eeded. Commenters stated ScottMadden refers to a March 2014 study by the INGAA that repo rted an average of about 1,650 miles of new gas transmission line is added per year (mainli ne miles and lateral connections)., and added that about 15,500 miles of new pipe per year will b e needed in the future, with most of this being gathering line. Commenters also added new pipeline is estimated to cost $3.7 million dollars per
mile.

Commenters provided a document in support of other comments that looked at impacts on natural gas and deliveries to electric utilities sh ould rules limiting utility emissions of carbon or other pollutants result in a shift away from coal t owards using more natural gas to generate electricity. Commenters’ document stated that if su bstantially more gas is needed, then a number of changes will need to be made by both the gas and electricity industries: changes such as massive infrastructure additions, changes to nomina ting and balancing services, changes to curtailment rules, and changes to subscription leve ls on interstate pipelines.

Insufficient demonstration

Commenters stated the EPA's current assumptions of the NGCC capacity are insufficient to demonstrate there is technical plant capability and infrastructure, available gas, gas transportation, gas storage, and electric transmiss ion capacity available to sufficiently increase256

NGCC generators' historical performance. Commenters noted that cooperatives across the nation own 12,000 MW NGCC capacity with NGCC plant capacit y averaging 35% in 2012 and 27% in 2013. Commenters noted that, during the same time p eriod, only 5 co-op NGCC facilities, representing 30% of the NGCC capacity, operated at 60% capacity when natural gas was priced historically low. Commenters stated the EPA has not demonstrated that the NGCC fleet is capable of almost doubling its average performance in order to take on the demands of coal-fired re-dispatch.

Commenters stated the notion that BSER includes ope ration of gas units in sufficient number and at a 70% capacity factor to partially offset the lo st generation from shuttered coal plants is undemonstrated both as a matter of history and in t he record. Commenters stated that, by EPA's own account this country required 12 years to incre ase natural gas production by 32%, which is approximately the same rate of increase in natural gas-fired unit capacity necessary to satisfy building block 2, albeit over a much shorter period if the 2020 deadline is maintained. Commenters stated the pipeline infrastructure build -up necessary for building block 2 cannot simply be wished into existence as a matter of capi tal investment, permitting, or construction.
Commenters referenced FERC Commissioner Moeller tes timony that EPA's assumptions that there will be sufficient pipeline expansion to meet this new gas demand may prove "faulty."
Commenters added that the EPA has not demonstrated that the enormous capital required is available within the necessary period.

Regional

Commenters stated the EPA failed to consider region al issues associated with expanding interstate natural gas transportation capacity, con tractual issues associated with pipeline capacity, environmental permitting issues associated with inc reasing capacity, and possible transmission issues associated with delivery at points different from in the past. Commenters stated Building Block 2 will be difficult, if not impossible, to in corporate into many states' plans because regional market rules do not necessarily accommodat e the expansion of interstate pipeline capacity that such re-dispatch will require. Commen ters stated the process of applying for a certificate of public convenience and necessity is quite cumbersome and generally requires a three-to five-year period from the date the applica tion is submitted until the date the pipeline begins construction. Commenters stated that, to the extent a pipeline constructs facilities to provide a particular level of service, but does not have precedent agreements in place for that service level, FERC will place the pipeline "at ris k" for any cost under-recoveries associated with underutilized facilities. Commenters stated that, a s a practical matter, an applicant must have customers and financing in place before it is able to begin construction of any new natural gas transportation capacity. Commenters stated that, be cause of the regulatory requirements and significant expense associated with constructing an d operating a new interstate natural gas facility, the applicant generally requires long-ter m, 15-20 year transportation precedent agreements to be in place before it will apply for a certificate from the Commission. Commenters stated that some regional electric marke t rules prevent generating resources such as NGCC EGUs from recovering the costs associated with such long-term gas transportation contracts; the ISO New England tariff provisions fo r the forward capacity market only permit a maximum seven-year commitment period for a new capa city resource and one-year commitment period for existing capacity resource (see ISO-NE T ransmission, Market and Services Tariff section III.13.1.1.2.2.4). Commenters noted that FE RC jurisdictional rates for firm interstate257

pipeline services require customers to pay all of t he pipeline's fixed costs associated with the capacity under contract through a "reservation char ge," which is payable even if the customer rarely uses most of the capacity. Commenters conclu ded that the mismatches between electric market rules and gas pipeline rates and contracts m ake pipeline transportation capacity expansion for electric generation purposes extremely difficul t.

State-specific

Commenters expressed concern that the re-dispatch w ould force the state to run down nearly all of its coal plants. Commenters noted that Arizona h as a large amount of natural gas generation, but only 50 percent of those facilities are owned b y state utilities. Commenters also noted that most of the facilities are located in one general a rea west of Phoenix. Commenters are concerned that the EPA fails to consider existing contractual obligations, transmission capacity constraints, pipeline availability, security considerations, and air quality limitations.

Commenters stated that, with limited pipeline capac ity in Florida, the magnitude of this increase in natural gas consumption is a concern.

Commenters expressed that Hoosier Energy has experi enced a lack of natural gas availability in
times of extreme weather and under other conditions . Commenters noted that this occurred at both combined cycle and peaking facilities. Comment ers stated that setting a goal does not diminish the issue of inadequate pipelines and stor age facilities since electric utilities such as Hoosier Energy do not have control over the lack of natural gas infrastructure. Commenters
stated that the EPA must examine these constraints and adjust state goals if gas availability cannot be assured. Commenters also noted that many combine cycle facilities were not built to run such a high capacity factor and that the constr aints of the units themselves must be
considered.

Commenters expressed concern regarding the amount o f electrical generation that can be redispatched to NGCC units based on the current natur al gas supply and infrastructure in Illinois. Commenters stated that, during the polar vortex per iod last winter, affected EGUs were severely restricted in purchasing gas because the supply was prioritized for other sources, such as home heating. Commenters noted that, while actions are b eing taken to improve infrastructure, estimated completion dates are several years away a nd may not entirely address the situation.

Commenters expressed concern regarding the adequacy of pipeline capacity in Missouri. Commenters stated it is important to examine the po tential risks associated with an increased dependence on natural gas. Commenters stated that, unlike coal and fuel oil, natural gas is not typically stored on site and, as a result, real-tim e delivery of natural gas through a network of pipelines and bulk storage is critical for Building Block 2. Commenters noted that other states along interstate transmission pipelines presumably would also need additional capacity to meet Building Block 2, including Kansas, Illinois, India na, Ohio and Michigan. Commenters stated that natural gas pipelines serving Missouri were de signed for winter heating load and they do not have the capacity to serve winter natural gas heati ng load while simultaneously providing natural gas capacity to off-set displaced coal-fired genera tion. Commenters noted that, during the winter of 2014, demand for natural gas increased, resultin g in a significant amount of gas-fired generation being unavailable due to curtailments. C ommenters objected to the EPA's apparent258

assumption that natural gas pipeline capacity will be expanded and supply will be sufficient in all areas of country to meet the electric sector's need s. Commenters stated the EPA's assumption ignores the complex interrelationship between the e lectric sector and natural gas supply and pipeline capacity. Commenters stated the EPA is rel ying on the natural gas supply and pipeline industries which are not subject to the Clean Power Plan to commit to meeting the electric sectors requirements under the Clean Power Plan on the same timeline as that set by the EPA. Commenters stated that there is currently not suffi cient gas capacity to support an NGCC plant in Missouri during the winter heating season. Commente rs stated that Westar Energy was unable to acquire natural gas at any price for a period of ti me this past winter at its Spring Creek generation facility in Oklahoma due to the severely cold weather and a lack of sufficient capacity to transport additional supplies of natural gas.

Commenters stated that Nebraska does not have adequ ate natural gas supplies or pipeline
infrastructure to sustain a 70% utilization rate of existing natural gas combined-cycle plants, particularly during colder months, and the time and resources required to remedy these issues may make Building Block 2 unattainable under the co mpliance timeline of the proposed Clean
Power Plan.

Commenters expressed concern regarding the lack of a major gas pipeline in the lower half of
South Carolina. Commenters noted that the EPA seems to believe that natural gas is readily available and affordable in all parts of the countr y. Commenters noted that natural gas is not
available to certain areas. Commenters stated that lack of a major gas pipeline in the lower half of South Carolina puts the state at a very high dis advantage. Commenters stated the increased natural gas target fails to recognize that South Ca rolina's two interstate gas pipelines are at full capacity. Commenters stated that although EPA claim s it has provided South Carolina with ample flexibility to make its own choices on how to comply, the building block approach does not fully consider infrastructure constraints and s upply limitations of South Carolina particularly for natural gas.

Commenters stated that is MRES built in states wher e it has load, it would face similar infrastructure issues as if it built in Wyoming. Co mmenters noted that the MISO Gas and Electric Infrastructure Interdependency Analysis fo und that a new natural gas pipeline would cost $870 million to $1.1 billion. Commenters noted that this cost estimate is for lateral pipeline development and does not include mainline construct ion costs. Commenters stated that pipelines would not be built overnight, and sufficient time i s required to plan and build sufficient pipeline to supply the new NGCC units. Commenters noted that the construction of any natural gas line or extension may face opposition or delays which co uld result in increased costs and require additional time for permitting and construction. Co mmenters also noted that the cost associated with building of sufficient natural gas infrastruct ure should be considered in the cost assessment of the BSER in the proposed rule.

Storage

Commenters further stated that the Proposed Rule do es not examine whether sufficient natural gas storage exists to support large-scale fuel swit ching - many states do not have adequate geologic formations to store gas that is needed by electric utilities for generation as baseload power, to back up intermittent renewables, or provi de peaking power. Commenters asserted that259

the Agency needs to look at these issues and adjust its assumptions about the timetables by which states and the electric utility industry can meet the requirements of building block 2.

Commenters suggested that coal piles at the plants are a form of energy storage and this coal resource should be continued until the natural gas infrastructure is able to handle increased volumes and variable demands of power generation, a nd as a hedge against price volatility of natural gas.

Timing

Commenters stated that according to the EIA, curren tly there are approximately 300,000 miles of interstate and intrastate natural gas pipeline capa city in the U.S. Commenters alleged that the EPA asserts that pipeline capacity can be added to enable the large-scale fuel switching the Proposed Rule envisions is needed to reduce CO2 emi ssions, but the EPA's analysis fails to examine whether this significant expansion can happ en by 2020 or even 2030 given the impediments the pipeline industry faces in construc ting and expanding pipelines, barriers posed by certain restructured wholesale electricity marke ts, and differences in the business models for the electricity and gas pipeline industries. Commen ters noted that according to comments filed
with the U.S. Fish and Wildlife Service in October 2014, the INGAA anticipates that the pipeline industry would need to build approximately 2,000 mi les of pipeline each year or a total of 300,000 miles of pipelines (interstate and intrasta te) between 2014-2035 to meet anticipated natural gas demand (INGAA comments filed regarding Endangered Species Act listings determinations, but not specifically for EPA's ESPS /NSPS for power sector http://www.ingaa.org/File.aspx?id=22680).

Peak demand

Commenters stated that, while the natural gas suppl y/delivery analysis under the proposed rule only discusses averages, actual utility planning an d installed infrastructure must deliver under peak demand scenarios. Commenters referred to the N ERC's initial reliability review (Potential Reliability Impacts of EPA's Proposed Clean Power P lan, Nov. 2014). Commenters stated the NERC's review (1) challenged the CPP's gas pipeline infrastructure assumption that no major investments would be necessary; (2) cited current c onstraints in the Arizona/Nevada and New England markets; (3) raised concerns that wide disp lacement/retirements of coal-fired EGUs with gas-fired units would cause further potential bottlenecks; and (4) stated concerns that the CPP's timelines provide little time to add required pipeline or related resource capacity. Commenters added that the Department of Energy (DOE ) is funding a study of gas supply adequacy by the Eastern Interconnect Planning Colla borative (EIPC) and stated that study is designed to provide analysis in sufficient detail t o inform the planning, operations, and markets of the six EIPC Participating Planning Authorities; the final report of this study is scheduled for delivery to the DOE in June 2015.

Comment 7: Commenters stated that transmission constraints ex ist in certain areas.

Response 7: The EPA disagrees that these issues prevent achieve ment of goals. In response to additional analysis and many comments, we have modi fied the proposal and RIA; requirements260

have been postponed. The 111(d) final rule requires that states develop plans that establish emission standards for affected EGUs. We are provid ing states with substantial flexibility as to how they structure those plans to achieve the 111(d ) requirements. The flexibility includes, for example, the choice of approaches, trading, time to develop plans, additional time before the start of the interim performance period (postponed from 2 020 until 2022), and the ability to shift emission rate achievement between performance perio ds. Neither the Building Blocks nor the IPM analyses are prescriptive, and states may consi der local circumstances as they develop their plans, including system reliability, fuel diversity , other regulatory requirements and infrastructure. See sections V.A, V.B, V.D, VIII.A, VIII.C and VIII.G of the final rule preamble of the CPP and Chapter 3 of the GHG Mitigation Meas ures TSD for the CPP Final Rule supporting the final CPP.

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

Commenters disagreed with the assumption that, for NGCC units that operate at higher levels for a set period of the day, that level of operation ca n be extended and sustained without risk to natural gas pipeline capacity. Commenters stated th is assumption is not valid when capacity is unavailable for base-load generation use because of competing purchasers and inadequate existing infrastructure. Commenters stated that, ad ditional study specific to the natural gas transmission system in Arizona would be needed to d etermine what would be required to support using existing NGCC generation for base-load genera tion. Commenters stated that, while the EPA provides EIA data on current pipeline capacitie s in the U.S., the Agency provides no information on the amount of residual capacity avai lable in the current system or the capacity projected as needed to meet EPA's assumptions regar ding utilization of the current NGCC fleet at a 70% capacity factor. Commenters suggested that actual available capacity may be far below 100% of nameplate capacity due to bottlenecks in th e system. Commenters referenced a November 2014 NERC report which stated that current and planned pipeline infrastructures in Arizona and Nevada are inadequate for handling incr eased natural gas demand due to the Clean
Power Plan.

Commenters stated that natural gas pipelines in the Southeast are fully subscribed; that is, all of the pipelines' capacities are subscribed on a firm capacity basis. Commenters stated that as a result, for any existing NGCC in the Southeast need ing firm transportation capacity to increase generation, additional pipeline capacity will be ne eded. Commenters added that not all NGCCs currently maintain year-round, 24 hours a day, seve n days a week firm natural gas delivery for base-load operation. Commenters asserted that highl ighting NGCC capacity factors during small time windows' peak hours and single months does not indicate a unit's annual capacity specifically due to year-round pipeline constraints

.
Commenters stated that transmission constraints pre clude the concurrent full operation of the South Dakota wind resource (which operates at a 45% to 50% capacity factor) and Basin Electric's Deer Creek NGCC station at a 70% capacit y factor.

Commenters stated the EPA did not consider transmis sion constraints unique to New York, which limit the system's ability to transmit NGCC c apacity located upstate to high load areas in and around New York City. Commenters stated the pro posal appears to assume that both gas delivery and electric transmission infrastructure w ill be in place to support that NGCC capacity261

without adequately considering economic, reliabilit y, and technical concerns. Commenters explained that southeast New York, which includes New York City and Long Island has specific electric constraints that precl ude the transfer of the increased output of NGCC
units located "above" the constraint. Commenters st ated that one major electric system constraint is referred to as the Upstate New York/ Southeast N ew York or "UPNY/SENY" interface and noted that approximately 62% of New York's NGCC fle et is located in UPNY with the
remainder in SENY. Commenters referenced a 2014 NYI SO reliability study and stated that, because of this constraint, it is not possible to a ccess all the installed NGCC capability that is located in UPNY (NYISO's 2014 Reliability Needs Ass essment at pp. 24 and 28, available at http://www.nyiso.com/public/webdocs/markets_operati ons/services/planning/Planning_Studies/ Reliability_Planning_Studies/Reliability_Assessment _Documents/2014%20RNA_final_091620 14.pdf.)

Commenters stated that, because natural gas demand in downstate New York for space heating will increase due to a recent New York City local l aw that requires the phase-out of residential and commercial boilers that currently use heavy fue l oil, and other factors, additional natural gas supply infrastructure will be needed. Commenters st ated this raises concern about how gas infrastructure investments that are required to mee t electric load requirements may be financed, and when such financing is needed. Commenters state d that, given the relative size of New York City and its overall impact on the State's electric ity system, the EPA should consider future projections of natural gas supply and demand, and u ncertainties associated with gas infrastructure development, when evaluating the Sta te's ability to achieve 70% NGCC redispatch.

Commenters stated that both SPP and the NERC have a nalyzed the Proposed Rule and concluded that existing transmission is not suffici ent to maintain grid stability. Commenters stated that SPP concluded, based on the generator r etirements anticipated by the Proposed Rule, that it is "very clear that new generation and tran smission expansion will be necessary to maintain reliability during summer peak conditions. " Commenters stated that, particularly important for Western Farmers, and EPA's Building B lock 2 analysis for Oklahoma, SPP found the most significant transmission deficiencies in t he SPP system exist in Texas and Oklahoma.

Commenters stated that, while Missouri River Energy Services would need to replace the lost generation from the retired unit and would presumab ly do so by constructing an NGCC plant, the LRS plant site in particular, and Wyoming in genera l, lack the necessary natural gas infrastructure to replace a lost coal unit with NGC C, not to mention the lack of electric transmission availability.

Comment 8: Commenters stated that Building Block 2 is technic ally infeasible for two NGCCs it owns and operates, McWilliams and Vann.

Response 8: The EPA disagrees. In response to additional analy sis and many comments, we have modified the proposal and RIA; the establishme nt of CO2 emission reduction standards is regionally based. The 111(d) final rule requires th at states develop plans that establish emission standards for affected EGUs. We are providing state s with substantial flexibility as to how they262

structure those plans to achieve the 111(d) require ments. The flexibility includes, for example, the choice of approaches, trading, time to develop plans, additional time before the start of the interim performance period (postponed from 2020 unt il 2022), and the ability to shift emission rate achievement between performance periods. The B uilding Blocks are not prescriptive, and states may consider local circumstances as they dev elop their plans, including system reliability, fuel diversity, other regulatory requirements and i nfrastructure. See sections V.A, V.B, V.D, VIII.A, VIII.C and VIII.G of the final rule preambl e of the CPP and Chapter 3 of the GHG Mitigation Measures TSD for the CPP Final Rule supp orting the final CPP.

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

Commenters stated its NGCCs are primarily used to r egulate load, and neither of the units can support a 70 percent capacity factor year-round. Co mmenters stated that, while, the two plants have access to firm natural gas capacity of 80,000 mmBtu per day for November through March, the EPA's proposed 70 percent capacity factor would require approximately 95,000 mmBtu per day year round. Commenters stated the gas pipeline serving the two plants is a shared resource
between PowerSouth and the Southeast Alabama Gas Di strict (SEAGD) and, while the pipeline may be capable of delivering 95,000 mmBtu of natura l gas per day, PowerSouth does not have access to this additional gas because SEAGD uses th is capacity to supply heating needs for its low-income, rural residential customers. As such, B uilding Block 2 is technically infeasible for
McWilliams and Vann.

Comment 9: Commenters stated RTO scheduling procedures limit the ability to achieve a specific capacity factor.

Response 9: The EPA disagrees that this comment reflects the i ntent and requirements of the rule, which does not require specific EGU’s to achi eve specific capacity factors. In response to additional analysis and many comments, we have modi fied the proposal and RIA. The 111(d) final rule requires that states develop plans that establish emission standards for affected EGUs. The rule applies to states, not to balancing author ities, utilities, or units. We are providing states with substantial flexibility as to how they structu re those plans to achieve the 111(d) requirements. The flexibility includes, for example , the choice of approaches, trading, time to develop plans, additional time before the start of the interim performance period (postponed from 2020 until 2022), and the ability to shift emission rate achievement between performance periods. The Building Blocks are not prescriptive, and states may consider local circumstances as they develop their plans, including system reliabil ity, fuel diversity, other regulatory requirements and infrastructure. See sections V.A, V.B, V.D, VIII.A, VIII.C and VIII.G of the final rule preamble of the CPP and Chapter 3 of the GHG Mitigation Measures TSD for the CPP Final Rule supporting the final CPP.

The following are summaries of the specific public comments under this comment:263

Commenters stated two factors impede the ability of an NGCC unit to achieve a specific capacity factor: (1) natural gas pipeline and RTO schedulin g procedures are not in sync and (2), if NGCC generation is bid into either the day-ahead or the reliability unit commit (RUC) markets, the bid might not be accepted by SPP if the offer price is higher than the market clearing price. Commenters stated that, in NPPD's case, current Sou thwest Power Pool (SPP) offer/award schedules for generation bid into the market occur after the points in time when NPPD must nominate gas supply needs under pipeline timely or Evening deadlines. Commenters stated that NPPD's only option in that situation would be to no minate gas in the Intraday market, but, even assuming available firm transportation capacity for the nomination, gas may not be available intraday during periods of high demand, when the pi peline declares System Over-run Limit ("SOL") conditions. Commenters stated this latter s ituation remains likely despite recent drops in the cost of natural gas because gas still remains a n expensive fuel for NPPD. Commenters stated that, given current delivered fuel prices, the ener gy cost for NPPD's NGCC Beatrice Power Station is approximately three times that of NPPD's coal-fired Gerald Gentleman Station on a dollar per megawatt hour basis and, in these pricin g conditions, to achieve the desired 70% capacity factor, a utility would have to put NGCC u nits in what is referred to as a 'self-scheduled' status, meaning it is a price taker in the market. Commenters stated that, as a price taker in a market where all accepted bids clear at the same pr ice, which is true in SPP's and other RTO's energy markets, NPPD would have no expectation that the significant cost of NGCC generation will be recovered; indeed, it would expect that NGC C units would clear at prices lower than the cost of generation. Commenters stated that, even as a price taker, an NGCC unit may still not be dispatched by the RTO due to bulk electric system r eliability concerns. Commenters stated that, in such cases, if the natural gas nominated by the curtailed utility is sold by the gas supplier, or i s cashed out by the pipeline (possibly at a loss), th e utility could be subject to penalties for not taking nominated gas under System Under-run Limit ( "SUL") conditions.

Comment 10: Commenters stated the EPA should indicate that sta tes are allowed, in so far as concerns ESPS compliance programs, to create incent ive mechanisms to offset the cost of firm pipeline capacity or other measures to secure natur al gas deliverability.

Response 10: The EPA has provided considerable flexibility in im plementation. The 111(d) final rule requires that states develop plans that establish emission standards for affected EGUs. We are providing states with substantial flexibilit y as to how they structure those plans to achieve the 111(d) requirements. See sections V.A, V.B, V.D, VIII.A, VIII.C and VIII.G of the final rule preamble of the CPP and Chapter 3 of the GHG Mitigation Measures TSD for the CPP Final Rule supporting the final CPP.

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

Commenters stated these measures could be considere d as part of a fuel-neutral pool of credits to address market failures that have impaired the reli able, cost-effective provision of low-carbon electricity.264

Comment 11: Commenters expressed concern that a funding mechan ism does not exist to support the infrastructure necessary for the CPP.

Response 11: The EPA disagrees that natural gas markets will pre vent the achievement of the goals. In response to additional analysis and many comments, we have modified the proposal and RIA; the establishment of CO2 emission reduction st andards is regionally based. The 111(d) final rule requires that states develop plans that establish emission standards for affected EGUs. We are providing states with substantial flexibilit y as to how they structure those plans to achieve the 111(d) requirements. The flexibility in cludes, for example, the choice of approaches, trading, time to develop plans, additional time bef ore the start of the interim performance period (postponed from 2020 until 2022), and the ability t o shift emission rate achievement between performance periods. Neither the Building Blocks no r the IPM analyses are prescriptive, and states may consider local circumstances as they dev elop their plans, including system reliability, fuel diversity, other regulatory requirements and n atural gas infrastructure. See sections V.A, V.B, V.D, VIII.A, VIII.C and VIII.G of the final ru le preamble of the CPP and Chapter 3 of the GHG Mitigation Measures TSD for the CPP Final Rule supporting the final CPP.

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

Commenters stated that, without a funding mechanism to align the regulatory requirements to build new capacity with the market rules that gover n a resource's ability to recover the transportation costs on that new capacity, Building Block 2 of the proposed rule's BSER cannot be effectively implemented. Commenters stated that Congress has not vested EPA with the authority to create a regulatory program that effec tuates this objective.

Commenters stated that funding for the increase in generation and the infrastructure necessary to increase the dispatch of NGCC units to 70% capacity factor, as expected by the EPA under building block #2 of the GHG Rule, is suspect, at b est, given the existing US energy market.

Commenters stated that financing adequate pipeline infrastructure to support the demand that will remain and ultimately grow, even after the ret irement of coal-fired electric generating units occurs, is a challenge that has been neither addres sed nor considered by EPA's proposed rule. Commenters stated that, traditionally, pipelines ha ve been financed with 20-30 year contracts with natural-gas distribution companies and cited t he following: "Simply put, if plant owners don't know on a daily basis whether and to what ext ent their power plants will be called upon to run or not, they will be reluctant to sign a 20-yea r or 30-year contract to buy natural gas" [see Ark. Code section 23-4-305(3); see also Acme Brick Co. v. Arkansas Public Service Commissio n , 227 Ark. 436, 441, 299 S. W.2d 208, 211 (1957)]

Comment 12: Commenters proposed that the EPA modify the method ology used in Building Block 2 to re-dispatch coal-fired EGUs to natural g as combined cycle EGUs such that redispatch does not occur until the latter of 2020, t he end of initial book life, the end of 20-year pollution control project book life, or, for EGUs s ubject to a shutdown or natural gas conversion requirement prior to December 31, 2029, the date of such shutdown or conversion.265

Response 12: The EPA disagrees that the specific adjustment to the proposal is required. In response to additional analysis and many comments, we have modified the proposal and RIA;
the establishment of CO 2 emission reduction standards is regionally based. The 111(d) final rule requires that states develop plans that establish e mission standards for affected EGUs. We are providing states with substantial flexibility as to how they structure those plans to achieve the 111(d) requirements. The flexibility includes, for example, the choice of approaches, trading, time to develop plans, additional time before the s tart of the interim performance period (postponed from 2020 until 2022), and the ability t o shift emission rate achievement between performance periods. Neither the Building Blocks no r the IPM analyses are prescriptive, and states may consider local circumstances as they dev elop their plans, including system reliability, fuel diversity, the “useful life” of generation ass ets, other regulatory requirements and infrastructure. See sections V.A, V.B, V.D, VIII.A, VIII.C and VIII.G of the final rule preamble of the CPP and Chapter 3 of the GHG Mitigation Meas ures TSD for the CPP Final Rule supporting the final CPP.

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

Commenters emphasized that this proposal is specifi cally intended to promote the calculation of
more reasonable and achievable carbon dioxide inten sity targets and is not intended to suggest a date by which EGUs could or should be retired or ce ase burning coal. Commenters noted they were amending their recommended assumption adjustme nts under Building Block 2, consistent with comments filed by the Arizona Utilities Group on December 1, 2014. Commenters proposed the following: Re-dispatch from coal-fired EGUs to natural gas combined cycle EGUs should occur upon the later of any of the following , if re-dispatch would occur prior to January 1, 2030: (a) January 1, 2020; (b) 40 years after initi al commencement of operation; or (c) 20 years after commencement of operation of major pollution control retrofit, such as selective catalytic reduction, flue gas desulfurization, or baghouses a t any EGU if installation occurred prior to issuance of the final 111(d) rule, or after commenc ement of operation of selective non-catalytic reduction or electrostatic precipitators at an EGU owned by a small utility as defined by the Federal Energy Regulatory Commission if installatio n occurred prior to the first year of the compliance period (i.e., 2020).

Commenters explained that provision (a) establishes the earliest re-dispatch date as January 1, 2020, which is the first day of the compliance peri od; this date applies if the date under provisions 1.b or 1.c is before January 1, 2020. Co mmenters explained that provision (b) establishes the proposition that re-dispatch from a coal-fired EGU will, for goal-setting purposes only, be treated as occurring on the 40th year from initial operation, reflecting the book life and typical amortization schedule for these EGUs, as th e Environmental Protection Agency (EPA) acknowledged in the NODA (79 FR 64549). Commenters added that, as a practical matter, most coal-fired EGUs are more than 40 years old, so prov ision 1.b affects only a few EGUs in total throughout the United States.

Commenters explained that provision (c) establishes the proposition that re-dispatch from a coalfired EGU will, for goal setting purposes only, be treated as occurring no earlier than the 20th year from initial operation post installation of a major air pollution control retrofit, including selective catalytic reduction, flue gas desulfuriza tion or baghouses, for any coal-fired EGU, as long as installation occurred prior to issuance of the final 111(d) rule. Commenters stated that,266

for small utilities (defined under the Federal Powe r Act as a utility with less than 4 million megawatt-hours of sales (determined in the baseline period)), re-dispatch from a coal-fired EGU will, again for goal setting purposes only, be trea ted as occurring no earlier than the 20th year from initial operation post installation of a major air pollution control retrofit, which would include for such small utilities not only the contr ols specified above but also selective noncatalytic reduction or electrostatic precipitators for any coal-fired EGU, as long as installation occurred prior to 2020. Commenters added that, as E PA acknowledged in the NODA, 20 years is the typical amortization schedule for large polluti on control equipment retrofits (79 FR 64549). Commenters stated this proposal provides some relie f, consistent with both Section 111(d), 42 U.S.C. section 7411(d), and its implementing regula tions, 40 CFR 60.22(b)(5), and the Regulatory Flexibility Act, 5 U.S.C. section 601 et seq. and its Declaration of Purpose, for small power entities that are less able to bear the costs of pollution upgrades by including certain smaller projects that while not as significant for large entities, are significant for such smaller
entities.

Comment 13: Commenters stated that while RGGI is currently ope rating in three RTOs (New England Independent System Operator (ISO), New York ISO, and PJM), setting up a similar system in other parts of the country could be very complex and time consuming.

Response 13: The EPA disagrees that the final rule does not giv e states sufficient time develop their plans, and the EPA does not require any state to develop a system like that described. In response to additional analysis and many comments, we have modified the proposal and RIA. The 111(d) final rule requires that states develop plans that establish emission standards for affected EGUs. We are providing states with substan tial flexibility as to how they structure those plans to achieve the 111(d) requirements. The flexi bility includes, for example, the choice of approaches, trading, time to develop plans, additio nal time before the start of the interim performance period (postponed from 2020 until 2022) , and the ability to shift emission rate achievement between performance periods. Neither th e Building Blocks nor the IPM analyses are prescriptive, and states may consider local cir cumstances as they develop their plans, including system reliability, fuel diversity, other regulatory requirements and infrastructure. See sections V.A, V.B, V.D, VIII.A, VIII.C and VIII.G o f the final rule preamble of the CPP and Chapter 3 of the GHG Mitigation Measures TSD for th e CPP Final Rule supporting the final

CPP.

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

Commenters said that starting up a new system simi lar to RGGI would likely require several years of development, adding to the amount of time that would be required to implement state plans.

Comment 14: Commenters identified multiple barriers to achievin g the 2020 schedule for redispatch as well as the final implementation deadli ne.267

Response 14: The EPA disagrees the final rule does not provide s tates with time to develop their plans; the start of the performance period has been postponed until 2022. The EPA disagrees with postponing the final performance date. The 111 (d) final rule requires that states develop plans that establish emission standards for affecte d EGUs. We are providing states with substantial flexibility as to how they structure th ose plans to achieve the 111(d) requirements. The flexibility includes, for example, the choice o f approaches, trading, time to develop plans, additional time before the start of the interim per formance period (postponed from 2020 until 2022), and the ability to shift emission rate achie vement between performance periods. Neither the Building Blocks nor the IPM analyses are prescr iptive, and states may consider local circumstances as they develop their plans, includin g system reliability, fuel diversity, permitting and other regulatory requirements and infrastructur e. See sections V.A, V.B, V.D, VIII.A, VIII.C and VIII.G of the final rule preamble of the CPP an d Chapter 3 of the GHG Mitigation Measures TSD for the CPP Final Rule supporting the final CPP

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

General

Commenters stated there are significant problems wi th the calculation of Building Block 2 for Arkansas and requested that: (1) the emissions goal be recalculated to account for several concerns; and (2) the timeframe for implementation and interim and final goals be extended to allow for appropriate planning and to soften the ec onomic impact on consumers. Commenters supported the concerns expressed in the joint comme nts of the Arkansas Department of Environmental Quality and Arkansas Public Service C ommission, including accounting for the Pine Bluff Energy Center, EPA's use of nameplate ca pacity instead of summer-rated capacity, air permit limitations, natural gas delivery constraint s, and electric transmission limitations.
Commenters stated that all of these issues need to be fully reviewed and addressed by EPA in the
final rule.

Commenters stated the EPA has not sufficiently cons idered barriers, which include operating constraints, permit limitations, contractual commit ments to out-of-state service, the need for NGCC availability to support RE, and infrastructure limitations and the EPA's failure to consider these factors renders its Building Block Two analys is insupportable.

2020 is too aggressive

Commenters generally stated the Proposal's schedule for re-dispatch by 2020 is unreasonable.

Commenters stated that, while AEPCO could seek to b uild a new NGCC EGU and assuming that siting and transmission issues could be overcome in time, it is unlikely that a new resource could be brought online prior to 2020.

Commenters stated the EPA failed to adequately cons ider whether sufficient natural gas and electricity transmission infrastructure exists, or can be developed in time, to accommodate the system re-dispatch and coal unit retirements assume d by the agency. Commenters stated the impacts associated with retiring 70,000 MW of gener ation as projected by EPA are significant268

and will severely affect the reliability of electri c service in this country. Commenters stated that sufficient replacement capacity cannot be built in time to meet the 2020 interim targets.

Commenters stated that achieving such dramatic incr eases in NGCC utilization effectively would require a fundamental redesign of the entire electr ic grid. Commenters stated that meeting EPA's state goals through increased re-dispatch of existi ng NGCCs in lieu of coal would, in many cases, require a system redesign, including the bui lding of new transmission lines and new EGUs, which would take a much longer time frame to be completed than EPA allows for, particularly given that the interim compliance peri od begins in 2020, only three years, at the most, after a state could have a final, approved co mpliance plan. Commenters stated that making the appropriate infrastructure and system changes t hat will be necessary to achieve increased utilization of existing NGCC units in certain areas will take longer than EPA's proposed guidelines currently allow.

Commenters stated that a significant increase in ge neration from existing NGCCs is needed in each of the four states Southern Company maintains retail operations, which will likely need to occur by 2020 and in a seamless manner. Commenters maintained that achieving a 70 percent capacity factor from existing NGCCs in Alabama, Flo rida, Georgia and Mississippi will require an increase in natural gas consumption of approxima tely 600 billion cubic feet ("Bcf") by 2020. Commenters noted that the Southern Company was the third largest electric generation user of natural gas in the country in 2012, utilizing appro ximately 588 Bcf, and that the implications of EPA's Building Block 2 determinations for Alabama, Florida, Georgia, and Mississippi are equivalent to doubling Southern Company's 2012 natu ral gas consumption. Commenters said that the EPA has ignored the significant natural ga s pipeline infrastructure expansion needed to support implementation of Building Block 2. Comment ers indicated that Southern Company currently holds about 2.5 Bcf/day of firm natural g as transportation to manage its natural gasfired resources, and that to secure that firm trans portation, Southern Company participated in almost 20 pipeline expansion projects, with each on e taking an average of 3 years to complete with the longest one taking 5 years. Commenters sta ted that Alabama, Florida, Georgia and Mississippi will need approximately 2.5 Bcf/day of additional firm transportation to achieve EPA's 70 percent capacity factor goal, and that thi s additional pipeline infrastructure will be costly and cannot be constructed in the required ti meframe. Commenters added that these expansions will be complicated by the increase in n atural gas demand from LNG exports and the industrial and transportation sectors. Commenters a sserted that the EPA did not acknowledge the fact that significant additional pipeline capacity would be needed, nor did it factor in the cost of the additional pipeline infrastructure.

Commenters discussed the amount of time required to complete new pipeline projects.
Commenters referenced an ICF International effort w hich compiled a list of gas pipeline projects for the years 2005-2014. Commenters noted that sinc e 2005 there were 331 expansion, lateral, or reversal (ELR) projects completed. Commenters noted that projects took a maximum of 10 years to complete with a mean of 1.37 years. Commenters n oted that there are 71 completed new pipeline projects that took a maximum of 10 years t o complete and a mean of 2.32 years.

Commenters stated the EPA's assumption that the pow er system could accomplish this wholesale shift in the dispatch order by 2020 is unreasonable in light of the significant barriers and risks that will limit operators' abilities to make such a significant shift from coal to natural gas in just a269

few years. Commenters stated the infrastructure and supply issues cannot be corrected between
now and 2020 or 2030. Commenters stated that EPA ha s not evaluated the ability of pipeline and transmission systems to manage such a major change in fuel supplies within the rule's short compliance timetable.

Commenters recommended that changes be made to the rate at which Building Block 2 is deployed as part of the goal-setting process. Comme nters stated that, while many states would be able to rapidly increase the utilization of existin g NGCC facilities, others may require additional time because of infrastructure constraints, charact eristics of existing in-state generation facilities

, or because of their load centers' locations in the electric or gas transmission system. Commenters stated that procuring adequate natural gas supplies to sustain a high level of utilization year round could mean, in the case of some states, build ing new pipelines or increasing the capacity of existing ones. Commenters stated that, because o f the way the goal computation formula is structured, ramping up renewable energy and energy efficiency levels progressively lowers the annual rates starting in 2020 and reaching the fina l goal in 2029. Commenters stated that, in contrast, the two other building blocks, have no im pact on annual rates between 2020 and 2029 because the goal computation formula raises efficie ncy levels of coal plants and utilization of NGCC facilities to their final target levels in 202 0. Commenters stated that, by this approach, the EPA implicitly "front loads" emission rate reductio ns associated with Building Blocks 1 and 2 under the proposed rule. Commenters stated that, on average, across all states, two-thirds of all proposed reductions are reflected in the calculated 2020 emission rate, with the remainder spread over the period 2020-2029. While commenters agreed with EPA's conclusion that, over time, existing fleets have the technical capability of re aching a 70 percent capacity factor, commenters agreed with stakeholders who are recommending to EP A that changes be made to the rate at which Building Block 2 is deployed as part of the g oal-setting process.

Commenters stated that such a large increase in nat ural gas usage would also require vast expansion of Florida's natural gas pipeline infrast ructure, which could not be completed as quickly as EPA's model projects natural gas demand increasing. Commenters stated inadequate pipeline infrastructure, coupled with the retiremen t of practically all coal-fired generation, also produces significant reliability concerns for Flori da.

Commenters stated the EPA's Regulatory Impact Analy sis, which projects a four to eight percent increase in pipeline capacity by 2020, fails to con sider increased natural gas demand for local distribution companies for residential use and cons umption to support the commercial and industrial sectors. Commenters stated that, while i t is feasible for additional infrastructure to be built, this will require appropriate time that is n ot sufficiently provided for in EPA's proposal especially with respect to the interim goal that be gins in 2020, further supporting the need for additional time to facilitate planning for an order ly transition.

Commenters stated that, even if it was determined t o be cost effective and provide a lower carbon footprint, gas supplies and the infrastructu re to bring it to new Nebraska natural gas generation facilities cannot be added in a timely m anner to comply with the Plan as proposed.

Commenters stated the Clean Power Plan provides ina dequate time to add required pipeline or related resource capacity by 2020. Commenters state d the EPA did not analyze the effect of increased use of natural gas nationally. Commenters stated that such national use for baseload270

electricity generation could lead to increased mark et dislocations, such as seen in the winter of 2013-2014. Commenters referred to a NERC report whi ch indicated that increased natural gas use will require pipeline expansion and that additi onal pipeline capacity will be needed in Arizona, Nevada and the New England states.

Commenters stated that, in order to replace the loa d formerly served by displaced generation from all of its coal-fired EGUs, Tri-State will be forced to purchase power from other generators at great cost or to construct new generating capaci ty altogether (which would not be possible in the timeframe set by the Proposal), despite Tri-Sta te's significant investments in its current generating fleet. Commenters stated the EPA's assum ption that such power purchases or new construction could be reasonably implemented in the Proposal's timeframe (or, indeed, at all) demonstrates a notable lack of understanding of pow er system economics, physics, and operations.

Commenters referred to the NODA (79 FR 64548) and s tated the Proposed revisions affecting the "2020 to 2029 Glide Path" for Block 2 requireme nts provide little relief from the stringency of EPA's interim standards. Commenters supported co nsideration of natural gas pipeline expansion or transmission improvements that are nee ded to support more use of existing natural gas-fired generation, but stated this does not addr ess the underlying concerns about feasibility of complying with Block 2 in its entirety, the effects that switching from coal to gas will have on states' reliability, the ability of states to meet varying electricity demands in an affordable manner, and of course, the fact that EPA does not h ave the CAA authority to implement this Block to begin with.

Commenters stated the EPA should examine whether ad ditional pipeline capacity would be needed for a state to meet the high utilization rat es of NGCC units by the start of the program in 2020, and by what date new or expanded pipelines co uld reasonably be permitted, sited, and constructed. Commenters stated that, given the time frame for submittal of state compliance plans and EPA approval, new gas supply will not be able to be in place by 2020. Commenters stated that several states also have a significant fraction of their existing NGCC fleet located in regions where there is not adequate transmission to move the electricity to where it will be needed to replace generation from the reduced utili zation of the state's coal-fired units. Commenters stated that building out the transmissio n grid is a very lengthy, costly effort and the Proposed Rule imposes building block 2 at the start of the compliance program.

Commenters added that increasing generation from ex isting NGCC units also may require electric transmission upgrades and expansions but, as NERC has noted, a transmission project can take 10 or more years to complete, from project identification to final certification and energization (citing Initial Reliability Review at 20). Commenters indicated that it may take even longer if a project crosses federal or tribal lands . Commenters asserted that these infrastructure constraints will challenge states' ability to achie ve significant changes in dispatch before - and even after - 2020. Commenters noted that recognizin g infrastructure challenges and the need to make investments, the EPA provides some time for ot her reductions measures, namely RE and EE to ramp up, but provides no such flexibility for equally important changes in dispatch. Commenters stated that as more natural gas goes int o the production of electricity, the natural gas infrastructure may not be able to meet the natu ral gas demand during periods of high energy demand (winter heating season). Noting that additio nal natural gas pipeline infrastructure is271

currently being built, Commenters pointed out that there is growing public opposition to new natural gas pipelines. As an example, Commenters st ated that Spectra Energy has proposed a 465-mile, $3.5 billion pipeline and compressor stat ion (the Sabal Trail Pipeline) which is planned to run through parts of South Georgia, and Green Law, Flint River Keepers and the local community are opposed to the pipeline and have chal lenged Spectra Energy and FERC officials on the proposed route and site for the pipeline and pumping station, with scores of negative comments from standing room only public information meetings. Commenters concluded that growing public opposition and obstruction to new na tural gas pipelines and pumping stations may prevent adequate natural gas infrastructure fro m being built within the time frame proposed in the CPP to meet a 70% dispatch rate for NGCC by 2020.

Commenters disagreed with the Proposal regarding pi peline capacity expansion in South
Carolina. Commenters referenced the GHG Abatement M easures TSD (at 3-18) and stated the proposal assumes that pipeline capacity in the Sout heast can be increased by 61 percent based on the Southeast Energy Information Administration (EI A) estimate of pipeline capacity expansion in the region. Commenters stated this expansion is not possible in South Carolina during the time frame given by the EPA for compliance. Commenters s tated that the EIA data relied upon by
EPA shows that while other states did see increases in pipeline capacity during the EPA selected period (2005-2010), the actual capacity increases i n South Carolina were zero. Commenters stated that, because South Carolina has two interst ate gas pipelines which are both at full capacity, to achieve the targeted increase in natur al gas utilization, additional pipelines or expansion of existing pipelines would be necessary. Commenters stated that typical planning, permitting and construction schedules for new pipel ines are approximately 5 years, a time frame which would be beyond the initial compliance period as proposed by the EPA. Commenters noted that Duke Energy, Piedmont Natural Gas, and D ominion recently announced a joint project to build a 550-mile natural gas pipeline fr om West Virginia to North Carolina which is not expected to be operational for a full 4 years a nd which still requires FERC approval. Commenters stated the EPA has not given adequate co nsideration to the cost of such expansion and indicated the Duke pipeline project will cost b etween $4.5 and $5 billion. Commenters stated the Proposal's implementation date of 2020 is arbit rary, given the difficulty of making these significant changes in power supply by 2020 and by the fact that the NGCC will have to be implemented in tandem with renewable generation.

Commenters stated that it is not clear, and the adm inistrative record does not demonstrate, that the states in which SCPPA's generation and transmis sion assets are located will be able to develop sufficient additional transmission and pipe line capacity by 2020, the year in which the EPA assumes Building Block Two will be fully implem ented. Commenters stated that increasing NGCC capacity factors to the levels assumed by the EPA will likely require additional
investments in transmission infrastructure and natu ral gas pipeline capacity in many parts of the
West. Commenters stated that these kinds of investm ents in transmission and pipeline infrastructure, which typically require numerous, s ignificant federal and state permits, rights-ofway, and other regulatory approvals, will be costly and lengthy. Commenters cited a NERC estimate that it takes three to five years to plan, permit, and build additional pipeline capacity. Commenters added that environmental permits to addr ess water and endangered species issues, in particular, could prove difficult to obtain in s ome parts of the West.272

Commenters stated the EPA needs to account for the timeframes to develop and permit the necessary infrastructure for new NGCC. Commenters e xpressed concern that the 70% utilization rate calls into question the costs and time associa ted with the upgrades and expansions of natural gas pipeline and transmission facilities that will be needed and it also ignores the regulatory and financial challenges of getting new gas infrastruct ure built. Commenters requested the EPA to
examine the current state of infrastructure and rea listic projections of the time and cost to upgrade or construct natural gas pipeline and trans mission facilities needed to eliminate or reduce specific state and regional constraints that impact the 70% assumption.

Commenters expressed concern about the aggressive c ompliance timetables established by the Proposed Rule and the implicit assumptions about th e feasibility of an unprecedented expansion in construction and generation from NGCC facilities and associated natural gas infrastructure. Commenters stated it is not realistic to expect tha t sufficient natural gas transportation and distribution systems would be in place by 2020 to a ccommodate the substantial shift in generation envisioned by the Proposed Rule. Comment ers stated that, though companies like Caterpillar certainly would respond to increased na tural gas infrastructure demand, the EPA fails to account for non-market delays that are likely to arise as this infrastructure is advanced. Commenters stated that permitting requirements acro ss various levels of government, local opposition, anti-infrastructure NGO campaigns, and other unforeseen factors will likely slow the
build-out of the infrastructure needed to meet the increased natural gas demand created by the Proposed Rule.

Commenters stated the assumptions in the block 2 an alysis fail to take into account the time, the cost, and the amount of infrastructure needed to be built to continue to meet the reliability
demands of the utilities and the customers. Comment ers added that Minnesota's "Buy the Farm" law requires that when utilities cross agricultural land, the utility must buy the entire tract of lan d
if the farmer wants out of the land. Commenters sta ted this cost adds onto to the typical $1.5 million to $2 million per mile investment in a tran smission line.

Commenters stated that, in the case of Nevada, a tr ansition to 70% utilization of natural gas resources and shutdown or retirement of large amoun ts of existing baseload capacity is not feasible by 2020. Commenters stated that, in Nevada , the assumption that there is "unused gas capacity" available to replace the coal/fossil gene ration is inaccurate and is a direct result of EPA's utilization of an annual capacity factor, ins tead of a peak capacity factor. Commenters
stated this scenario is a reason for EPA to conside r the elimination of the proposed interim glide path goals, or at a minimum, allowing all Building Blocks to be phased in over the full compliance period. Commenters stated that granting additional time to shift away from higher carbon intensity fuel sources on a less disruptive implementation schedule can still achieve the 2030 target for emission reductions, yet serve to e nsure reliability and minimize consumer impacts.

Commenters stated that infrastructure and supply is sues cannot be corrected between now and
2020 or even 2030.

Commenters agreed with stakeholders who suggested t o EPA during the comment period that the re-dispatch of NGCC units contemplated under Buildi ng Block 2 cannot reasonably be expected273

to occur on day one and supported the recommendatio n put forth in the October 28th NODA that Building Block 2 should be phased in similar to Bui lding Blocks 3 and 4.

Commenters stated, that, in addition to the develop ment of new transmission, the permitting and construction of natural gas pipelines that are nece ssary for re-dispatch to NGCCs could take many years. Commenters stated that new pipeline con struction takes, on average, three to five years, although it can take more time if the projec t faces environmental permitting challenges or public opposition. Commenters stated the EPA has no t adequately considered the impact of these
infrastructure constraints on states' abilities to increase NGCC utilization to 70 percent.

Commenters stated the EPA should consider infrastru cture constraints that could hinder such a large increase in NGCC generation over the limited timeframe between now and the start of the first compliance period. Commenters stated these co nstraints include plant-level infrastructure constraints, lack of transmission lines, and inadeq uate gas supply, transport, and storage.
Commenters noted the EPA also must consider the cos ts of overcoming these infrastructure
constraints and stated that new 345 KV transmission lines cost $2.3 million per mile, without substation costs. Commenters stated new natural gas pipelines cost nearly $4 million per mile (See Christopher E. Smith, US pipeline operators si nk revenue growth into expansion, Oil & Gas Journal (Sept. 2, 2013), available at http://www.ogj.com/articles/print/volume-111/issue9/special-report-pipeline-economics/us-pipeline-ope rators-sink-revenue-growth-intoexpansion.html). Commenters stated that, despite th e significance of these costs, EPA has not considered them in its BSER analysis. Commenters st ated, for example, one Class of '85 member
cannot increase the utilization of one of its effic ient NGCCs because the transmission will not disperse all of the surrounding wind energy. Commen ters stated that, if the owner attempted to run the plant more, it would violate the Federal En ergy Regulatory Commission's market power rules prohibiting uneconomic production. Commenters cited a NERC report stating that significant transmission constraints must be overco me to support the re-dispatch envisioned by EPA, and doing so will require much longer than the five years leading up to 2020:

Long lead times for transmission development and co nstruction require long-term system planning-typically a 10-15-year outlook.... Given t he significant changes and locations anticipated to occur in the resource mix [as a resu lt of EPA's Proposal], it is likely that additional new transmission, or transmission enhancements, wil l be necessary in some areas. New transmission lines will be required to transport th e amount of renewable generation coming online, particularly in remote areas, and that crea tes additional timing considerations. Further, as replacement generation is constructed, new transmis sion may be needed to interconnect new generation. Mitigating transmission constraints ide ntified from the proposed EPA regulations in a timely way, consistent with [the Proposal's] targ ets, presents a potential reliability concern.

Commenters stated the EPA's Building Block 2 analys is does not account for the infrastructure challenges associated with shifting generation from one fuel type to another, in the timeframes contemplated by the Proposed Rule. Commenters state d that natural gas is susceptible to supply
constraints and extreme weather conditions such as the 2014 polar vortex. Commenters stated a NERC reliability study found higher than usual forc ed electric outages during the vortex, with outages concentrated at natural gas-fired units. Co mmenters stated re-dispatch could exacerbate these grid disruptions. Commenters stated that a NE RC study found that increased reliance on natural gas-fired generation (1) would require grea ter electric transmission from NGCC units to274

distribution networks and end-users, (2) would like ly necessitate development of new
transmission lines or transmission line enhancement s in certain areas, (3) would require permits from several state and federal agencies, and (4) co uld take anywhere from 5 to 15 years to construct, depending on voltage class, location, an d labor availability. Commenters stated these realities collide with the interim targets beginnin g in 2020.

Commenters suggested more time is needed than the p roposal allows for necessary pipeline and transmission upgrades in Arizona. Commenters stated that, while the Proposed Rule would provide little time to add required pipeline or rel ated resource capacity by 2020, the lead time to permit, design, and construct new transmission line s in Arizona is approximately 10 to 12 years based on recent APS experience. Commenters provided the following statements supporting their position.

• Comments sent by the Southwest Power Pool to the Mi ssouri Public Service

Commission stated that the planning and constructio n of transmission upgrades can take up to eight and a half years and cost up t o approximately $2.3 million per mile for new 345 kilovolt transmission lines, exclu ding substation costs.

• NERC stated that a construction timeline for a new high-voltage transmission line can range from five to fifteen years, depending on the voltage class, location, and availability of highly skilled construction crews.

• NERC described how the current and planned natural gas pipeline infrastructure in Arizona is inadequate for handling the increased gas demand due to the Proposed Rule.

• The assessment of the transmissions system's short falls was independently confirmed by the PACE Global study which concluded: The lack of transmission import capacity limits load serving entities from d isplacing the retired units (coal) with the existing NGCC units.

• According to NERC, building additional pipeline inf rastructure investments can take three to five years to plan, permit, sign cont ract capacity, finance, and build.

• APS also referred to the comments by FERC Commissio ners, as summarized in UARG's comments, which argue that the EPA inadequat ely accounted for economic and physical limitations on capacity expan sions and transmission.

Commenters stated that, because it generally takes three to five years to permit, finance and build additional pipeline capacity, the first interim emi ssions reduction goals in 2020 may be too
ambitious.

Commenters stated the EPA's presumption that buildi ng block 2 can be implemented by 2020 is unrealistic and suggested Building Block 2 be phase d in over the compliance timeframe. Commenters stated that, without further evaluating the implications on reliability, it must be assumed that additional natural gas capacity will b e needed to comply with the rule. Commenters stated the need for new natural gas generation can be estimated by looking at the difference275

between the maximum three-year annual average capac ity factor of 37% and the fleet average since 2005 of 28%, which is equivalent to approxima tely 260 MW of capacity. Commenters stated that, assuming this capacity was used to fil l rapid and short-term load needs, new NGCC or simple cycle combustion turbine (CT) capacity wi ll have to be built as replacement capacity; this is equivalent to approximately 13 new 100 MW C Ts operating at 20% capacity factor. Commenters stated that, since building any new CT o r NGCC capacity will require at least five to seven years, it is clearly impossible for this c apacity to be operational by 2020--given that it is very unlikely the state will have an approvable pla n prior to 2019. Commenters stated that EGU outages for equipment installations have to be coor dinated by the independent system operator (ISO) and this planning and approval process, along with any necessary permitting, also cannot occur by 2020.

Commenters stated that, given the high cost, compli cated siting and permitting processes for natural gas pipeline, storage and other necessary i nfrastructure, the timeline proposed in the CPP for increasing reliance on NGCC units is unrealisti c.

Commenters stated the EPA's proposed schedule is to o aggressive to allow the most optimal solutions to emerge. Commenters stated that the EPA failed to consider that the development of incremental infrastructure projects can have advers e socio-economic, environmental, and land use impacts. Commenters stated this development wil l take many years to complete. Commenters suggested the EPA work with states devel op a measured and reasonable implementation schedule, and minimize overreliance on natural gas.

Commenters stated that the EPA's historical example s of increased dispatch to NGCC generation do not support its conclusion that full implementat ion of BB2 by 2020 is feasible. Commenters referenced the proposal (79 FR 34857, 34862-63) and the GHG Abatement Measures TSD (3-10 to 3-19), and stated the EPA appears to rely primar ily on historical experience with NGCC generation increases. Commenters stated the EPA is calculating that NGCC generation in 2020 could increase by approximately 47 percent from tod ay's levels. Commenters stated the 81 percent historic ramp rate (2005-2012), however, sh ould not be measured against today's levels. Commenters stated that, because State plans will no t be approved until the middle of 2017, at the earliest, it is not reasonable to assume that the e ntities responsible for compliance with state plans will undertake the substantial investments re quired for compliance until those plans are finalized. Commenters stated that, if full implemen tation of Building Block 2 by 2020 is assumed, states will have at most 2.5 years to achi eve re-dispatch. Commenters stated that, measured against the appropriate time frame, the ra mp rate EPA is proposing is much higher than the historical rate it cites in support: whil e the historical increase of 81 percent over seven years amounts to a ramp rate of 10 percent per year , the 47 percent increase that would result from compliance with BB2 over at most 2.5 years amo unts to a ramp rate of 18.8 percent per year. Commenters added that, in Arizona, where a 95 percent increase in NGCC generation is assumed under BB2, the ramp rate would be higher st ill: at least 38 percent per year. Commenters stated that, because the NGCC starting p oint is now higher than it was in 2005, the amount of the increase in NGCC generation correspon ding to any particular percentage increase will be higher now than it was then. Commenters sta ted that the amount, rather than the percentage, of the increase provides a better point of comparison for purposes of determining the system's capacity for change based on historical ex perience: while the 2005-2012 NGCC276

generation increased at a rate of approximately 54 GWh per year, the 47 percent change required by BB2 amounts to approximately 180 GWh per year, o ver three times higher.

Commenters did not agree that the proposal's compli ance schedule provides flexibility and time for investment in additional natural gas and electr ic industry infrastructure if needed (79 FR 34857). Commenters referenced a November 2014 NERC report and stated that in Arizona current and planned pipeline infrastructures are in adequate for handling increased natural gas demand due to the CPP. Commenters stated that past shifts from coal to NGCC generation may have reflected low hanging fruit since the principl e of least-cost dispatch dictates that operators would have shifted generation to NGCC where the cos ts of transmission and gas delivery system upgrades were lowest. Commenters stated that the fi rst shifts therefore would have occurred where the existing transmission and fuel delivery i nfrastructure was already adequate. Commenters stated that infrastructure improvements, such as natural gas pipelines, will be needed to meet future project requirements, which w ill be costly and require 10 to 15 years to develop. As an example of infrastructure needs, com menters described two EGUs that were converted from coal to natural gas with nameplate c apacity of 1,100 MW that currently cannot operate because the gas transmission line that serv iced them in the past is no longer in gas service but is now in petroleum service (citing inf ormation obtained during a verbal conversation with representatives of Consumer's Energy). Comment ers stated that significant infrastructure development will likely be required and will requir e capital and an extensive time frame, and that the EPA proposal does not allow adequate time for t hese infrastructure improvements.

Commenters expressed concern that new infrastructur e will require up to 4 or more years (for generation) to 10 or more years (for transmission) to complete grid and utility system planning, engineering, permitting, environmental and public reviews, construction, and startup timelines.
Commenters noted that Intermountain West and Great Plains have numerous large baseload coalfired power plants sited in remote locations served by dedicated mines as fuel sources and stated many facilities have limited or no access to natura l gas infrastructure. Commenters stated this brings new infrastructure challenges in terms of gr eater need for access to natural gas pipelines and new or expanded transmission lines, as well as increasing amounts of renewable generation.

Commenters asserted that there is far too little ex isting natural gas infrastructure in South Dakota to make the development of additional natural gas-f ired power plants feasible in the time allowed under the Proposed Rule. Commenters stated the buil d-out of such pipelines and transmission lines is still extremely slow and expensive and the re are numerous obstacles to such development, including obtaining proper rights-of-w ay, clearing state and local permitting hurdles, overcoming local opposition, etc.

Commenters requested that the EPA remove the 2020 i nterim target from any final standard because the necessary time for potential modificati ons and additions to the existing natural gas infrastructure is not present in the CPP proposal. Commenters encouraged the EPA to recognize that Michigan's infrastructure must support electri c generation and still provide its citizens with natural gas for home heating purposes. Commenters d escribed a recently completed natural gas pipeline project, stated that it is likely that oth er projects of this nature will be necessary to support a high NGCC dispatch scenario, noted that p rojects that need to acquire new right of way access attract a great deal of public interest, and require significant time to develop prior to any construction activities, and stated the current pro posed timeline simply does not allow for the277

proper build out of the infrastructure to accommoda te EPA's accelerated dispatch of NGCC plants. Commenters referred to Consumers Energy's r ecently completed natural gas pipeline project where 24 miles of 36 inch pipe was installe d next to an existing natural gas pipeline. Commenters state the "1200B Project" was undertaken in order to complete a 90 mile pipeline corridor that better allows Consumers Energy to sup port our gas storage fields and provide our customers with affordable gas and also supports pip eline integrity and safety requirements. Commenters stated this 24 mile project, representin g ~ 0.1% of the Consumers Energy distribution pipeline, took over 400,000 person hou rs to complete and spanned two construction seasons at a cost of almost $120 million dollars9, and Consumers Energy already held right of way access to the property.

Commenters recommended that EPA extend the start of the compliance period (e.g., 5 years after EPA approval of a state's compliance plan) to mitig ate the constraints of building block 2.
Commenters stated that the timeframe that EPA has a llowed for this building block does not recognize the extended period of design, permitting , and construction that would be required to increase the utilization of existing NGCCs. Comment ers referred to the Pace Global Study and stated that, in order to make the necessary new cap acity additions by 2020, the siting and air permitting activity would have to be completed by 2 017 so as to allow construction to begin.
Commenters stated that affirmative commitments cann ot be made today because uncertainty over the curtailment mechanism, the associated MISO guidelines, the level of coal derate, and
also because the extent to which units will be at-r isk will not be resolved until at least 2017 (and possibly later) when state plans under the CPP are to be finalized. Commenters stated this means that it may simply be infeasible to add the require d capacity to compensate for derates and at-risk units by 2020. Commenters stated it is unlikely tha t new infrastructure would be available to support the ramp up of natural gas fired units by 2 020, thereby putting pressure on states and
utilities to achieve more drastic emission reductio ns in later years of the interim compliance period to comply with the interim average emissions goal.

Commenters stated that, in order for the City's two natural gas combined cycle (NGCC) units to achieve and maintain a 70 percent capacity factor u nder Building Block #2, the City would be required to sell a significant portion of their out put off-system. Commenters stated that significant transmission investment on the City and adjacent systems would need to be made to allow for this level of export from the City's syst em and it is doubtful that this level of transmission could be constructed in time to suppor t the interim CO2 targets.

Commenters stated that the major shift in generatio n to NGCC over the next five years is infeasible for many existing units because of techn ical limitations, gas pipeline infrastructure constraints, and/or regulatory limits. Commenters s tated that gas pipeline construction and upgrades require permits and approvals at the feder al, state, and local levels that can take five years or more to secure and put in place. Commenter s stated it is unlikely that new infrastructure would be available to support the ramp up of natura l gas fired units by 2020, thereby putting pressure on states and utilities to achieve more dr astic emission reductions in later years of the interim compliance period to comply with the interi m average emissions goal. Commenters referenced a 2014 Energy Ventures Analysis, Re-disp atching Gas Combined Cycle Units, and stated the pipeline infrastructure in the Western U nited States will limit the availability of increased NGCC generation.278

Infrastructure--pipelines

Commenters stated the EPA's timeline does not take into account the time required to address
infrastructure concerns.

Commenters stated that, by requiring the transition from coal to NGCC, utilities will need to upgrade the existing pipeline infrastructure and co nstruct new NGCC generation facilities. Commenters stated that, since the construction proj ects could have environmental impacts based on the sites and scope of facilities requiring cons truction, the CPP should be required to address these impacts from an environmental and economic ba sis and determine if the reductions in CO2 emissions off-set or are justified based on the imp acts and costs. Commenters stated that, while the CPP has modeled plant closures and the amount o f natural gas generation that will be required by the rule, the EPA should take the next step and model the additional plants that will be constructed and pipeline improvements that will be required to meet existing plant capacity
factors and determine the environmental and economi c impact of the projects.

Commenters stated the EPA has not addressed the con cerns that have been raised by FERC that gas pipeline adequacy should be considered from a r egional perspective, not just a national perspective, due to existing constrains on this sys tem (Written Testimony of FERC Acting Chairman Cheryl A. LaFleur Before the Committee on Energy and Commerce Subcommittee on Energy and Power United States House of Representat ives (July 29, 2014), at p. 4).

Commenters stated that building block 2 has not bee n adequately demonstrated because redispatch from coal-fired units to NGCC units in ord er to achieve a 70 percent annual capacity factor of NGCC units is not feasible - even though the nation likely has an adequate supply of natural gas to meet the increased demand that will result from implementing building block 2, there is insufficient natural gas infrastructure to transport the natural gas to NGCC plants. Commenters indicated that this problem is not hypot hetical; it is a reality, as evidenced by the events that took place this past winter, when natur al gas-fired facilities experienced significant problems obtaining a consistent, affordable supply of natural gas to run their units. Commenters asserted that increasing the capacity factor of NGC C units to 70 percent will only exacerbate the problem. According to the commenters, the EPA ackno wledges that the existing natural gas
infrastructure is insufficient to meet demand when it is most needed, but erroneously claims that the proposal's compliance schedule provides flexibi lity and time for investment in additional natural gas infrastructure (79 FR 34858). Commenter s noted that states must begin to achieve emission decreases by 2020 to meet their respective interim goals, and opined that this does not allow for enough time to build the infrastructure n eeded to implement building block 2.

Commenters asserted that the EPA has not adequately addressed in the record these significant barriers that exist to ramping up the use of natura l gas and renewables in the electricity generating sector by 2020 and 2030. Commenters note d that in order to meet the EPA's interim goals between 2020 and 2030, this capacity realisti cally needs to be in place by 2020.
Commenters stated that the EPA has not demonstrated how the sector will be able to ramp up natural gas and renewable capacity in time to meet the deadlines in the Proposed Guidelines given the many years needed to plan, permit and bui ld the infrastructure to support these forms of generation.279

Commenters stated that the Agency suggests that pip eline infrastructure will have sufficient time to expand if necessary to accommodate Building Bloc k 2 because the Proposed Guidelines "provide for flexible implementation that will perm it efficient scheduling of infrastructure upgrades as needed" (GHG Abatement Measures TSD at 3-16). Commenters presume that the EPA is suggesting that states may delay full implem entation of Building Block 2 because compliance with the proposed state interim goals is based on average emissions from 2020 to 2029; however commenters stated that the "flexible implementation" timeline the EPA claims to have provided states is largely illusory, particula rly with respect to Building Block 2.

Commenters noted that tor most states, re-dispatch under Building Block 2 accounts for the most significant emission reductions of any building blo ck, and EPA calculated the proposed state goals with the assumption that Building Blocks 1 an d 2 would be fully implemented by 2020 (79 Fed. Reg. at 34905-06; Goal Computation TSD at 18 ( noting that in calculating state goals, only "the RE and EE assumptions change for each year fro m 2020 through 2029")). Commenters stated that delaying full implementation of Buildin g Block 2 in order to allow for necessary infrastructure development would significantly incr ease a state's emissions in early years of the 2020 to 2029 compliance period, forcing the state t o achieve more drastic emission reductions in later years in order to comply with the interim goa l on average. Thus, the commenters believed that most states will need to implement necessary i nfrastructure improvements to accommodate Building Block 2 by 2020 or very soon thereafter. A ccording to the commenters, this timeline is likely infeasible, given that gas pipeline projects often require a decade to complete, in part because the timeline for environmental permitting c an be lengthy.

Commenters stated that although significant gains h ave been made in the past several years in locating new sources of natural gas, little has bee n done to improve the infrastructure needed to connect this new gas to power plants. According to the commenters, INGAA predicts that the natural gas industry will need to construct 2,000 m iles per year for the next 20 years of new gas
transmission mainlines and laterals to meet demand (citing The INGAA Foundation, Inc.,
"Jobs& Economic Benefits of Midstream Infrastructur e Development: US Economic Impacts Through 2035," at ES-1 (Feb. 15, 2012), available a t http://www.ingaa.org/File.aspx?id=17744; also The INGAA Foundation, Inc., "North American Mi dstream Infrastructure through 2035: Capitalizing on Our Energy Abundance," at 38 (Mar. 18, 2014), available at http://www.ingaa.org/Foundation/Foundation-Reports/ 2035Report.aspx). Commenters stated that INGAA and other industry groups also stated re cently that more than 338,000 miles of pipeline will need to be constructed between 2014 a nd 2035 (citing Comments of American Petroleum Institute, Association of Oil Pipe Lines, International Association of Geophysical Contractors, Interstate Natural Gas Association of America, Utility Air Regulatory Group, and Utility Water Act Group on Three Endangered Species Act Critical Habitat Proposals of the U.S.
Fish and Wildlife Service and the National Marine F isheries Service Published on May 12, 2014, at 5 (Oct. 9, 2014), available at http://www.ingaa. org/File.aspx?id=22680). For perspective, commenters added that there were about 306,000 mile s of gas pipeline in use in the United States at the end of 2008 (citing EIA, "Estimated Natural Gas Pipeline Mileage in the Lower 48 States, Close of 2008," available at http://www.eia.gov/pub/oil_gas/natural_gas/analysis _publications/ngpipeline/mileage.html).

Commenters stated the pipeline and infrastructure a vailability assumptions by EPA are
unrealistic and the time frames set forth in the Pr oposal will not allow for the development of280

pipeline infrastructure needed to meet the high cap acity demand necessary for baseload generation.

Commenters stated that, in addition to the developm ent of new electric transmission, the permitting and construction of natural gas pipeline s that are necessary for re-dispatch to NGCCs could take many years. Commenters referenced the NE RC Initial Reliability Review and stated that new natural gas pipeline construction takes, o n average, three to five years.

Commenters stated the EPA has failed to adequately evaluate the redirection of power given the current grid availability and resource location, co nsequences of such a significant increase in natural gas consumption, and the timeframe that nec essary infrastructure improvements will require. Commenters stated that increased transport ation capacity also requires compression and pumping infrastructure and working gas storage capa city. Commenters stated that, with the Proposed Rule's projected increase in demand for na tural gas from 25-32 states, the current infrastructure upgrades and increased capacity will only increase more. Commenters stated that, since the required natural gas buildout would occur in the same period, it is very likely that the United States suppliers would not be able to handle the numerous simultaneous projects. Commenters concluded that building this volume of n ew natural gas is not feasible by the Interim Goal, possibly not even before the Final Go al.

Commenters stated that, while the EPA has assumed t hat sufficient natural gas pipeline
infrastructure is available to deliver the fuel nee ded for NGCC units to ramp up to a 70 percent capacity factor, there is no support for this assum ption in the record. Commenters referenced a NERC report and stated that, for many existing NGCC units, there is insufficient pipeline infrastructure to support operating year-round at a 70 percent capacity factor. Commenters stated these infrastructure limitations are exacerbated by the fact that the proposed state goals are calculated assuming that states will fully implemen t Building Block 2 by 2020, giving states and utilities only a few years or less in which to expa nd gas and transmission infrastructure as needed to reach the target level. Commenters noted that, w ith regard to pipeline capacity for Tri-State's NGCCs, Tri-State has not had an issue with getting natural gas to either the Rifle or J.M. Shafer Generating Stations; however, this may not be the c ase during the winter. Commenters noted that during past winters, pipelines were fully subscribe d and experienced winter constraints.

Commenters stated that, while interstate natural ga s pipelines are permitted by FERC based on "firm" demand for natural gas, power plants typical ly purchase natural gas on an "interruptible"
basis. Commenters stated the EPA failed to consider the impact of the potential large increases in interruptible natural gas demand on the opportunity to build new natural gas infrastructure. Commenters stated the EPA failed to adequately cons ider the time it takes to build the additional natural gas infrastructure necessary to achieve the target capacity factors set in Building Block 2. Commenters stated that, according to the current sc hedule, EPA will be approving, or disapproving, state plans between 2017 and 2019 and compliance with the proposed guidelines begins in 2020. Commenters stated that, presuming a state plan is approved, there will be one to three years to come into compliance with the state plans. Commenters stated EIA estimates that an interstate natural gas pipeline takes approximat ely three years to complete between announcement and completion. Commenters noted there may be additional time necessary to identify the need for additional pipeline and other prior planning actions by the pipeline operator281

and, in individual circumstances, due to localized sitting and permitting issues, construction may take even longer.

Commenters stated there is not enough existing NGCC in this country to make up for the forced reductions in coal generation. Commenters stated th e gas supply and infrastructure in this country are not available or reliable enough to ser ve all gas generation that will be needed. Commenters stated this leaves a significant gap bet ween energy that can be generated and remain in compliance with the CO2 goals and energy that mu st be generated to continue to supply reliable electricity to the population.

Commenters stated that, by the summer of 2017 pipel ines will have the capacity to deliver into Peninsular Florida approximately 5.6 billion cubic feet per day, although not all this capacity is deliverable to all major load centers and generatio n locations. Commenters stated that the siting and construction of incremental pipeline capacity a nd delivery laterals will be necessary to accommodate dispatch of these resources. Commenters stated this development will take many years to complete, cost Floridians hundreds of mill ions of dollars, and place Florida in a dubious position with an overreliance on a single fuel whic h creates reliability deterioration and cost
increases.

Commenters stated that the natural gas infrastructu re is not adequate in Georgia to support current demand and a 70 percent dispatch rate for N GCC. Commenters indicated that although it has been demonstrated that a 70% dispatch rate can be achieved in peak hours, this scenario is based on base loads being achieved by other EGUs - if 70% dispatch of NGCC becomes part of the base load generation, it would reduce the avail able amount of standby, peak demand, and emergency based power. Commenters noted that this p roposal comes after extreme winter weather conditions hit the state in January of 2014 and caused record-setting winter electricity demands across north Georgia at the same time that natural gas demand for residential heating peaked. Commenters asserted that with the proposed 70% dispatch target, such future demands may have to be met with less efficient natural gas simple cycle turbines which would put additional stress on natural gas residential heatin g supplies.

Commenters stated that, without any certainty as to whether the necessary pipeline capacity exists or will exist, EPA should reconsider Buildin g Block 2. Commenters stated that, not only is gas pipeline capacity already strained during peak demand periods, but it remains uncertain whether additional, sufficient gas pipeline infrast ructure will be built, either in the near or longterm future, to allow the levels of re-dispatch pro jected by EPA. Commenters stated the EPA has not adequately evaluated whether the current nation al gas pipeline capacity is sufficient to handle the increased supply of gas that this Building Bloc k would require. Commenters referred to NRECA's comments that the EPA has failed to properl y account for the substantial growth that will be required in the existing gas pipeline infra structure and also referred to INGAA, which predicts that just to meet existing and forecasted demand (not including that increased demand caused by the Proposal) over the next twenty years, the U.S. and Canada will need about 850 miles per year of new gas transmission mainline and over 800 miles per year in new laterals to and from power plants and processing facilities. Co mmenters stated the EPA has failed to account for the FERC process, or the myriad of othe r federal, state and local environmental statutes that affect the ability to permit such fac ilities. Commenters concluded that the notion that282

all of this new capacity can be planned, designed, permitted and installed by 2020 is arbitrary and capricious.

Commenters stated the EPA failed to give adequate c onsideration to potential infrastructure challenges from significantly increasing NGCC utili zation. Commenters stated natural gas pipelines have limited carrying capacity and in man y parts of the country natural gas is utilized for both electricity generation and home heating. C ommenters stated substantial, coincident increases in natural gas utilization in the power s ector could strain limited pipeline capacity. Commenters stated that, because existing NGCC facil ities do not share locations with the coal facilities they are expected to replace, additional electric transmission infrastructure could be needed to ensure that reliability can be maintained and electricity can reach consumers.

Commenters stated that during the 2014 Polar Vortex our nation's natural gas supply and existing infrastructure to transport gas to electric markets was strained to the breaking point. According to the commenters, assuming additional output as a res ult of a 70 percent CF from these units during another event of this magnitude would most c ertainly put large swaths of the United States at risk of unmet electricity demand, potenti ally creating brownouts or blackouts. Commenters asserted that a more appropriate target would be in the low 40 percent range for CF
of NGCC units.

Commenters stated the CPP requires significant proj ects not available in 2012 or before, and cannot be considered "adequately demonstrated". Com menters stated it is inaccurate to assume that permitting a new pipeline can occur over a sho rt time frame since pipeline expansions take years to plan, engineer, procure, and approve throu gh federal, state, and local agencies/jurisdictions. Commenters stated the propo sed rule is essentially requiring expansion projects which have not yet been proposed or permit ted.

Commenters expressed concern that the EPA analysis does not address the length of the regulatory approval process for the siting of new p ipelines.

Commenters stated that, even if existing NGCC units are capable of running at 70 percent or greater capacity factors, gas pipeline capacity may not be sufficient to provide the gas volumes needed to operate at these high capacity factors, e specially in the short term before additional
infrastructure can be built. Commenters stated the lack of available natural gas infrastructure will limit the availability of natural gas for all consu mers, including NGCC power plants and will make it difficult for NGCC power plants to achieve the capacity factors EPA assumes.

Commenters stated the proposed rule does not recogn ize the significantly long lead-time that permitting and building new natural gas pipeline ca pacity can take. Commenters stated that most interstate pipeline projects arc severely capital i ntensive, require ten years or more long-term contracts and can routinely take more than five yea rs to permit and build. Commenters stated that, in order for pipeline capacity constrained st ates such as Arizona to utilize more gas, new pipeline projects would need to be constructed. Com menters stated that the long-term firm capacity on Arizona's two major pipeline systems is nearly subscribed, and Arizona has limited access to additional firm natural gas pipeline capa city.283

Commenters stated that new pipeline infrastructure will take a significant amount of time and money to site and build, while States and utilities are up against EPA's compliance deadlines. Commenters stated there are many moving parts in th is plan to assuring sufficient gas pipeline and supply to gas turbines and sufficient transmiss ion from generators that need to fall into place
without a hitch to meet EPA's timeline. Even with s ufficient gas supplies, commenters stated the EPA timelines are too tight to assure adequate tran sportation and storage for periods of high demand as natural gas pipelines still have limited capacity and infrastructure available to offer flexible operating services to power plant customer s on a firm basis.

Infrastructure--transmission

Commenters suggested the EPA's timeline does not ta ke into account the time required to
address infrastructure concerns.

Commenters stated that officials at the Southwest P ower Pool have noted that major new transmission projects can take up to 8 1/2 years. C ommenters stated grid operator urges EPA to delay carbon plan implementation by 5 years.

Commenters stated the EPA should allow for time to study existing generation mixes and transmission constraints anticipated by the final r ule in order to modify the transmission system to eliminate the need to operate higher emitting ge neration to maintain system stability. Commenters stated the CPP will displace coal genera tion with NGCC generation and result in voltage/frequency instability in their service area , which could require the dispatch of simple cycle natural gas plants to stabilize the system or to meet load in areas of transmission congestion. Commenters stated that the emission rat es of simple cycle natural gas generation are significantly higher than NGCC and rival that of ba se loaded coal. Commenters stated that frequent Transmission Load Reduction (TLR) events h ave required the reduction of generation from renewable generation sources, NGCC and coal to stabilize the system. Commenters stated the requirement of the CPP to generate electricity using NGCC and renewable sources without time to study the impacts to the transmission syste m will create even more reliability and system efficiency problems.

Commenters stated the EPA should allow that, upon a demonstration that significant transmission upgrades are reasonably necessary for a state to operate its NGCC fleet at the average annual capacity utilization rate within the Final Rule, and that no reasonably sufficient alternative is available to gain the same carbon re ductions, its goal or interim goal should be adjusted to account for the time needed for such up grades. Commenters noted that the dispatch of EGUs within Arkansas is controlled by two region al transmission organizations which plan transmission systems to ensure reliability, and tha t this planning requires complex modeling studies, regional cost allocation proceedings, stat e approval proceedings, and ultimately, construction, a process which can take four to seve n years in order to plan, approve, and construct significant transmission facilities.

Commenters, quoting EPRI's comment letter, argued t hat changes in the change in generation will almost certainly require development of new tr ansmission to ensure operational reliability, but scheduling outages of existing facilities would be difficult if simultaneous upgrades across284

many systems are need such that time lines for comm issioning of new transmission facilities may be delayed.

Commenters stated that growth in demand for natural gas from electricity generation and other markets is expected and this increased demand will have an impact on the availability and price of natural gas supply and transportation. Commenter s stated that this growth in demand, coupled with the proposed restrictions on coal-fired and oi l-fired generation throughout the U.S., will strain the ability of natural gas suppliers and pip elines to meet this growing demand.
Commenters stated the result will be an increase in natural gas price volatility and a decrease in availability, ultimately leading to substantially h igher commodity costs and electric rates for
Floridians.

Commenters stated the EPA has conducted a limited a nalysis of whether the current system can handle any changes that become necessary as a resul t of changes in the amounts and locations of generation. Commenters stated that transmission sys tems are modeled and designed for the current configuration of generation plant locations , thus, significant changes in how much generation various plants are providing or plant re tirements will cause power flow changes that could negatively impact the transmission system. Co mmenters stated that mitigating any system problems caused by these power flow changes could r equire constructing new substation(s), transmission line(s), and/or transmission line(s) i mprovements. Commenters noted a recent example on the Georgia Integrated Transmission Syst em ("ITS") involved a coal plant retirement
that caused thermal overloads of a transmission lin e and low voltages; addressing these issues required a new 230/115 kV substation and transmissi on line upgrade that cost approximately $20 million. Commenters stated that, in addition to the high costs for such projects, they often have long lead times, due to planning, design and constr uction requirements, including necessary
environmental reviews. Commenters stated the EPA ha s not adequately accounted for and addressed these considerations in its proposed 2020 start date for state interim goals.

Commenters stated the EPA failed to account for log istical issues, including: how transmission costs will be divided among producers and consumers ; acquiring rights-of-way from landowners to increase transmission capacity; and receiving la nd and environmental permits to implement these changes. Commenters stated that each of these issues requires a substantial amount of time, making it questionable that transmission (and pipel ine) capacities will be sufficient to meet the schedules set forth in the Proposal. Commenters sta ted that delays can be particularly acute for changes in cooperative-based distribution and trans mission facilities, as the provisions of the National Environmental Policy Act are often trigger ed due to the enhanced Federal connections.

Commenters expressed concern that, even after a pla nt is constructed, there is no assurance that the natural gas transmission and distribution and e lectric transmission infrastructure required to properly distribute power from the plant would be a vailable. Commenters stated that, in the past, independent power producers in Louisiana experience d unfavorable results when they sited generation prior to establishing necessary transmis sion, and it is unlikely that LUS or any other municipal entity could receive sufficient project f inancing if transmission was not guaranteed.

Commenters stated that the analysis the EPA conduct ed of the existing electric transmission networks is procedurally inadequate and significant ly underestimates the time required to modify transmission systems and the complexities involved. Commenters stated the targets and timelines285

required in the Proposed Rule do not accommodate th e timelines and regulatory realities involved in expanding electric transmission capacit y. Commenters stated that modifying the electric transmission infrastructure is a complex, costly, and time consuming process that involves many state and federal agencies, electric utilities, and the public. Commenters stated that, due to cost, entities are unlikely to risk th e expense of expanding electricity transmission capacity if the electricity is required to be displ aced by energy efficiency in a few years.

Commenters stated that, once the EPA accepts state implementation plans under the proposed rule, it will take about two or more years for gene ration and transmission entities to analyze the potential requirements of their systems due to all the different possible combinations under the EPA's proposal and subsequently plans for additiona l electric transmission must be developed and analyzed in an open regional planning process t hat usually takes an additional two years. Commenters stated that every change requires new an alysis, and the building resources market can change while the analysis is being conducted.

Commenters stated that, in the best circumstances, a four- to five-year planning period will be necessary before an approved transmission plan can be achieved and the transmission construction process can begin; yet this optimistic timeframe may be inadequate for a State to meet EPA's proposed goals. Commenters stated some p rojects take 10 years to build, while others never get built, such as the Potomac-Appalac hian Transmission Highline (PATH) project, which was proposed to address numerous electric rel iability concerns forecast for the MidAtlantic region in the mid-2000s but was suspended in 2011. Commenters stated that large projects like the Alaska pipeline can take decades of discussion and planning, and can require a decade to permit and construct once a route is chos en while less controversial and smaller pipeline capacity can be built within a year or so if transportation costs justify construction and permits are obtained in a timely manner.

Permits

Commenters expressed concern that both transmission lines and natural gas pipelines require many layers of permitting and years of regulatory a pprovals, often at federal, state and local levels. Commenters believed that the Proposed Rule is unrealistic in assuming that this infrastructure will be in place by 2020 for states to begin implementing all four building blocks. Commenters noted that a large number of permits, co nsultations and approvals are needed from multiple government bodies to get a new transmissio n line permitted and constructed - the timeline for a transmission project depends on real estate availability (negotiating rights-of-way or exercising eminent domain authority), environmen tal permitting requirements, public opposition and regulatory approval. According to co mmenters, a relatively simple project that will not traverse an environmentally sensitive area , require the exercise of eminent domain, or involve significant public opposition can take up t o 3 years prior to construction, and more complicated projects that will traverse federal lan ds, environmentally sensitive areas, or will generate public opposition may take as much as 10 y ears to complete.

Commenters stated that the EPA must allow for const ruction of new generation. Commenters indicated that the CPP provides states with at most 2 years and at minimum 6 months before the beginning of the compliance period, which the comme nters believed is wholly inadequate where286

new generation and required supportive infrastructu re is necessary given permitting and construction of new transmission and pipeline infra structure can take more than 10 years.

Commenters stated that many permits may be required for a new transmission line or natural gas pipeline, which may include the following: an Envir onmental Assessment or Environmental Impact Statement (required under both federal and s tate law, in some cases), if the project involves significant state or federal government ac tion of any kind; a Section 404 permit from the Army Corps of Engineers if dredge or fill mater ial will be placed in "waters of the United States;" Section 7 consultation with the U.S. Fish and Wildlife Service under the ESA if the project has the potential to impact threatened or e ndangered species; a Special Use Authorization under the National Forest Management Act if the pro ject will traverse federal lands managed by the U.S. Forest Service; a right-of-way grant under the Federal Land Policy and Management Act from the U.S. Department of Interior Bureau of Land Management (BLM) if the project traverses federal lands managed by BLM; a state wat er quality permit (if required by a state water quality statute); fish, game, and other wildl ife related permits, if the project will divert
natural flow of water bodies or otherwise affect fi sh and game; Section 106 National Historic Preservation Act consultation if the project might impact cultural or historic resources; a rightof-way lease agreement; and an air quality permit i f disturbed acreage will exceed certain thresholds (citing California Public Utilities Comm ission, "Federal, State, and Local Permitting Processes Likely to be Required for Electric Transm ission Projects" (June 2009), http://www.cpuc.ca.gov/NR/ rdonlyres/D896C1 EA-BD35-4BC8-83C8- 32BAE959BF/0/GenericTransmissionLinePermit.pdf.)

Commenters added that the Utah Office of Energy Dev elopment has estimated that a typical schedule for siting, permitting and constructing a new transmission line in that state could take up to 7 years, assuming the line is at least 100 mi les long, crosses federal lands, and requires a federal environmental impact statement. (See Utah O ffice of Energy Development, Guide to Permitting Electric Transmission Lines in Utah, at iii, Fig. ES-1 (Aug. 2013), available at http://energy. utah.gov/download/reports/PermittingGuide_Final%200 80913%20(cd%20ver).pdf.), and in Colorado, siting transmission lines can take even l onger because local governments (counties and municipalities) have jurisdiction over the siti ng of transmission lines and each may impose different permit or other authorization requirement s and conditions.

Commenters stated the EPA does not address the time needed to complete critical project tasks before pipeline construction can begin, such as an extensive public involvement process, regulatory proceedings before local committees and commissions, obtaining rights-of-way, acquiring permit authorizations, conducting environ mental assessments, and procuring bank financing. Commenters stated these activities are a necessary part of any major energy infrastructure project and must be accommodated in EPA's projected timelines for achievement of emissions reductions under at 111(d) program.

Commenters also stated that in order to take advant age of the abundance of shale gas resources, new pipelines will be needed to transport these nat ural gas supplies to regions of the country that propose to build new, lower-emitting NGCC units. Co mmenters noted that if the pipelines will cross federally-owned lands, approval of permanent rights-of-way from federal land managers must be obtained and, because there is no streamlin ed process for obtaining such federal287

approvals, their approval can take years, which cou ld impede the ability to expand the network of natural gas pipelines to deliver gas for power g eneration.

Commenters stated that it can take 3 to 6 years to permit and build new pipelines (citing Initial Reliability Review at 10). Commenters indicated tha t the GAO report lists other applicable
statutes to include the National Environmental Poli cy Act, the Clean Water Act, the Endangered Species Act, the National Historic Preservation Act , the Rivers and Harbors Act of 1899, the Clean Air Act, the Migratory Bird Treaty Act, the S afe Drinking Water Act and the Wilderness Act, with permitting agencies that include FERC, EP A, U.S. Corps of Engineers, Bureau of Indian Affairs, Bureau of Land Management, Departme nt of Wildlife and Fisheries, Forest Service, DEQ and a host of other federal, state and local agencies as well as tribal and local
governments.

Commenters stated that increased operation of the N GCC plants could have practical implications, including permitting issues, engineer ing and design limitations, natural gas pipeline restrictions, availability and price volatility, an d transmission limitations.

Commenters stated that, if the federal government w ants states to shift to cleaner sources of electric generation, such as natural gas, it must e xpedite the process of approving Environmental Impact Studies so the necessary pipeline infrastruc ture can be built. Commenters stated that, without such an initiative, the Federal government is simply setting the states up to fail.

Commenters stated that planning, permitting, and co nstructing such infrastructure takes time and is expensive, and that the EPA does not appear to h ave taken this factor into account in the proposed rule, and instead implicitly assumes no la g time in its model for bringing natural gas pipelines online. Commenters asserted that the EPA failed to study existing natural gas transmission constraints, contractual arrangements, and other factors including unit design or age of equipment that could limit the feasibility, reli ability, or sustainability of running individual units at such high capacity factors. Commenters con cluded from this that to comply with the proposed rule, and bring in the amount of natural g as required by the rule, will take much more time than is contemplated by the proposed rule, whi ch creates particular risks to Texas because of the disproportionate impact that Building Block 2 has on Texas's interim emissions rate. According to the commenters, the proposed rule assu mes the entire re-dispatch is accomplished beginning in 2020, resulting in approximately 77% o f Texas's final emissions reduction be achieved by 2020. Commenters contended that the tim e between the adoption of a final rule and the compliance deadline of 2020 is insufficient to assess, plan, construct, and operate the
infrastructure that such a dramatic shift in electr icity production will require. Commenters stated that the EPA offers no analysis on the possible imp acts of requiring increased use of natural gas generation. Commenters indicated that existing tran smission constraints may preclude some EGUs from operating their natural gas plants in acc ordance with the Building Block 2 requirements. Additionally, commenters stated, with the dramatic increase in natural gas use in Texas (and throughout the country) resulting from t he proposed rule, there will be a need for additional gas pipeline infrastructure. Commenters stated that a GAO report analyzed public records of interstate gas pipeline permitting proce sses (as FERC does not collect such data) and noted that, "for those projects that were approved from January 2010 to October 2012, the average time from pre-filing to certification was 5 58 days; the average time for those projects that began at the application phase was 225 days." Commenters added that the GAO report did288

not have data for the time frames required to obtai n intrastate gas pipeline permits. Commenters noted that interstate permitting must comply with v arious federal laws, including the National Environmental Policy Act, the Clean Water Act, the Endangered Species Act, and the National Historic Preservation Act, and the GAO report goes on to state: "[b]oth the interstate and intrastate pipeline permitting processes are comple x in that they can involve multiple federal, state, and local agencies, as well as public intere st groups and citizens, and include multiple steps" (Id. at 12).

Time to ensure grid reliability

Commenters stated that available transmission and t he transmission planning process present constraints on re-dispatch.

Commenters stated that a NERC CPP report found that the timeline EPA proposes does not provide enough time to develop the resources that a re needed to ensure grid reliability by 2020. Commenters stated that, even where systems are conn ected and integrated, there is not an unlimited ability to move flows between regions, an d the proposed rule does not account for the restrictions that will necessarily come into play, given the aggressive goals and timeline contemplated under the Clean Power Plan.

Commenters referenced a November 2014 NERC report a nd stated that a wholesale shift in the dispatch order away from coal-fired units (almost a ll of which provide baseload power) to NGCC units (which typically provide peak or interme diate load power) will create significant electric reliability issues in many parts of the gr id. Commenters referenced comments of
Southwest Power Pool and stated that the transmissi on and pipeline systems in many parts of the country may not be capable of handling the increase d demands on their capacity that will accompany a large increase in NGCC generation. Comm enters stated that many parts of the country rely on NGCC units to provide peak generati on on short notice during periods of high demand, or to accommodate system emergencies and, i f these units begin to operate as baseload units while other baseload units are retired, the e lectric grid could be at greater risk of blackouts or price spikes during periods of high demand or un expected interruptions from one or more large generating sources. Commenters stated these u nits also will be less available to balance intermittent RE generation, thus potentially raisin g the overall costs of integrating the higher levels RE that the Proposed Rule would require. Com menters stated the EPA's cursory analysis of the reliability and cost impacts in the Proposed Rule fails to adequately consider these factors, and appears to assume-without evidence-that suffici ent transmission and pipeline capacity will materialize within the next few years.

Commenters stated that cost allocation issues will need to be addressed, rights-of-way must be acquired from landowners, and permits must be obtai ned. Commenters stated that public opposition and lawsuits seeking to stop or move pla nned transmission are also common and can add substantial delay and expense to transmission p rojects. Commenters stated that it is not yet
clear what modifications to transmission infrastruc ture may be required to support a re-dispatch of existing NGCC capacity to achieve a 70% or great er capacity factor, but those changes will also need to be addressed through regional planning processes and may also take up to five to 10 years to complete once identified. Commenters state d that there are more problems with siting289

new transmission now than ever before, so lead time s for those proposed new facilities could be even longer.

Comment 15: Commenters stated the EPA has not adequately consi dered the time involved in the permitting process and the impact this will hav e on infrastructure development.

Response 15: The EPA disagrees that we have not adequately consi dered regulatory constraints and time for implementation in the 111(d) final rul e. In response to additional analysis and many comments, we have modified the proposal and RIA; th e start of the performance period is postponed. The 111(d) final rule requires that stat es develop plans that establish emission standards for affected EGUs. We are providing state s with substantial flexibility as to how they structure those plans to achieve the 111(d) require ments. The flexibility includes, for example, the choice of approaches, trading, time to develop plans, additional time before the start of the interim performance period (postponed from 2020 unt il 2022), and the ability to shift emission rate achievement between performance periods. Neith er the Building Blocks nor the IPM analyses are prescriptive, and states may consider local circumstances as they develop their plans, including system reliability, fuel diversity , permitting and other regulatory requirements and infrastructure. See sections V.A, V.B, V.D, VII I.A, VIII.C and VIII.G of the final rule preamble of the CPP and Chapter 3 of the GHG Mitiga tion Measures TSD for the CPP Final Rule supporting the final CPP.

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

Commenters stated that significant amounts of new t ransmission infrastructure will be needed to accommodate Building Block 2, particularly in areas where load has been served by coal-fired EGUs and NGCC units are located a great distance aw ay. Commenters stated that permitting, design, construction, and commissioning of new gene rating facilities can take many years-- particularly when including the time needed to cond uct required meteorological surveys. Commenters stated the timeframes required to constr uct the new transmission and generation that will be needed to support Building Block 2 sug gest that compliance with the Proposal would be impossible. Commenters stated that, because EPA failed to consider the numerous limits on the ability of existing NGCC units (individually an d collectively) to increase utilization to a 70 percent capacity factor, the Agency has not demonst rated that its proposed Building Block 2 target is achievable. Commenters provided the follo wing additional comments regarding TriState's transmission infrastructure experience.

• Siting and permitting transmission is a complex and controversial process that requires a large number of permits, consultations, and approvals from multiple federal, state, and local government bodies and pri vate parties before construction even begins. The timeline for a transmission projec t depends on completion of planning studies and technical analysis, real estat e availability (negotiating rightsof-way or exercising eminent domain authority), pro curement of long lead time290 equipment, environmental permitting requirements, p ublic opposition, regulatory approval, and opportunities for tie-in outages. A r elatively simple project that will not traverse an environmentally sensitive area, req uire the exercise of eminent domain, or involve significant public opposition wi ll take up to three years prior to construction. More complicated projects that wil l traverse federal lands, environmentally sensitive areas, or will generate p ublic opposition may require 10 years or more to complete. In some cases, utilities have been forced to completely abandon projects, including Tri-State's abandonment of the San Luis Valley Calumet-Comanche project.

• Tri-State's 200,000 square mile service territory overlays federal, state, tribal, and private lands, and any transmission projects are su bject to regulatory approvals
from the various entities involved before construct ion can proceed. Delay in approval from any of these stakeholders can delay o r ultimately prohibit construction of a transmission project. These appro val processes are unpredictable.

• At the federal level, implementation of the Nationa l Environmental Policy Act can present delays for environmental impact review, as can new species and critical habitat listings under the Endangered Spec ies Act and the creation of new national monument designations or "exclusion" areas through wilderness areas.

• Locating transmission facilities on tribal land can involve substantial uncertainty and high costs.

• Within Tri-State's service territory, state approva l processes differ significantly, and in Colorado and other states, local governments have jurisdiction over siting and permitting processes on private lands. The Unit ed Power 115 kV Transmission Improvement Project required 10 years to obtain preconstruction approval for only 15 miles of transmission line. Th e project consisted of three phases. In Phase II, one local jurisdiction insiste d on implementing an underground configuration, requiring an appeal to t he Colorado Public Utilities Commission (CPUC) and an action in federal district court for the project to proceed. In Phase III, a dispute between two involv ed jurisdictions that could not agree on a buildable preferred route had to be reso lved by the courts before the project could move forward. Phase III is currently under construction.

• The Nucla-Sunshine 115 kV project endured a 13-yea r pre-construction process. The project crossed federal lands, necessitating an environmental impact statement under the National Environmental Policy A ct and three records of decision. The project also required approval from t wo local jurisdictions, one of which demanded utilizing underground transmission l ines. Tri-State appealed to the CPUC. The case ultimately went to district cour t but was settled.

• The development process for the Gladstone-Walsenbu rg 230 kV Transmission Line project in New Mexico and Colorado began in 19 97 and did not end until
2006. Various New Mexico landowners refused Tri-Sta te access to their land for291 the purpose of pre-construction surveys and other w ork. Ultimately, the New Mexico Supreme Court resolved this dispute in Tri-S tate's favor after years of litigation.

• The county permitting process in Colorado required two years. Tri-State spent another year to acquire necessary land rights, whic h involved a condemnation process with uncooperative landowners.

• The San Luis Valley-Calumet-Comanche 230/345 kV pro ject received a Certificate of Public Convenience and Necessity fro m the CPUC approving the project but had to be abandoned, as configured, due to opposition from a private landowner. The project was needed for reliability f or Tri-State's operations and was a combined project with Xcel Energy, which was planning on using the line to enable the transmission of solar power out of th e San Luis Valley. The owner of a large parcel of land in a location key to the project's route successfully lobbied the federal government to obtain a conserva tion easement on his property, which not only resulted in a prohibition against co nstruction of the transmission line but also resulted in the solar generation not being built because there was no way to transmit the energy.

• None of these projects are outliers. They reflect m any of the common obstacles that utilities often face to obtain approval for tr ansmission projects, particularly in areas of the West in close proximity to federal and tribal lands. It is unreasonable for EPA to simply assume that the transmission and pipeline infrastructure necessary to implement Building Block 2 can be deve loped in a more expeditious
timeframe.

Commenters stated the assumptions in the block 2 an alysis fail to take into account the time, the cost, and the amount of infrastructure needed to be built to continue to meet the reliability
demands of the utilities and the customers. Comment ers stated that new NGCC units require additional electric transmission, which requires su bstantial time. Commenters described in some detail the Minnesota CapX 2020 project, the largest expansion of the high voltage transmission line in the region in over three decades, and state d that, while CapX initiated the Minnesota regulatory proceedings in 2007, it will have taken a total of eight (8) years to move from the initial regulatory process to energizing the lines, and this for a group of projects that were reliability and wind-generator outlet driven where all of the utilities in the region backed the project.

Commenters stated the Proposed Rule also fails to t ake into account the fact that, if a combined cycle plant which was designed to operate intermitt ently to support wind generation is repurposed to run as a baseload plant, it may well be necessary to upgrade the transmission system to accommodate the new baseload function. Co mmenters referred to the CapX transmission upgrade and noted the project has take n over a decade from design through construction. Commenters stated the Proposed Rule o verlooks this issue in calling for higher capacity factor output of natural gas EGU's into an electric grid not designed for those units to be
baseload units. Commenters stated the Final Rule ne eds to take this into account to give Minnesota the flexibility to ramp up its required c arbon reductions. Commenters stated that, with292

the Final Rule being issued in mid-2015, history sh ows transmission facilities will not be online
until 2026 or later.

Commenters stated the EPA has not considered the ti me involved in the normal FERC regulatory siting process. Commenters stated the transition to gas-fired generation envisioned in BB2 is intrinsically tied to an increase in construction o f pipelines to transport that gas. Commenters expressed concern that, in setting the CO2 reductio n goals in the CAA Section 111(d) proposed rule, the EPA did not sufficiently account for the two-year average time it takes for an application to process through FERC. Commenters sta ted this two-year period is in addition to the time spent developing a proposal and preparing an application as well as the time for the actual construction of the pipelines themselves. Co mmenters urged the EPA to take pipeline construction timelines into consideration in design ing BB2 goals. Commenters provided the following related information.

• Under Section 717f(c) of the Natural Gas Act of 193 8, the Federal Energy Regulatory Commission (FERC) is authorized to issue certificates of "public convenience and necessity" for "the construction or extension of any facilities ... for the transportation in interstate commerce of na tural gas." Companies seeking to build interstate natural gas pipelines must firs t obtain certificates of public convenience and necessity from FERC. The Energy Pol icy Act of 2005 (EPAct) designates FERC as the lead agency for coordinating "all applicable Federal
authorizations" and for National Environmental Poli cy Act (NEPA) compliance in reviewing pipeline certificate applications. There are no statutory time limits, however, within which FERC must complete its certif icate review process.

• The regulatory process for certification of interst ate gas pipelines varies depending on whether or not the pipeline developer opts to enter the voluntary pre-filing process before formally applying for a p ipeline certificate, pursuant to 18 CFR 157.21. The pre-filing process involves a se t of specific activities including a study of the project sites, stakeholder identification and an open house for affected parties. Concurrently, FERC Staff part icipates in the open house and publishes, pursuant to 40 CFR 1508.22, in the Feder al Register a Notice of Intent for Preparation of an Environmental Assessment or a n Environmental Impact Statement that opens a public comment period. FERC may also consult with stakeholders and hold public meetings and site visi ts in the proposed project area. The pre-filing process requires a written request t o FERC's Office of Energy Projects and commences seven to eight months before the filing of a certificate application.

• Whether or not the developer participates in the pr e-filing process, a developer must formally file an application with FERC in orde r to receive a certificate of public convenience. This application requires the s ubmission of a description of the pipeline, route maps, construction plans, sched ules, lists of other statutory and regulatory requirements from other agencies, enviro nmental reports analyzing route alternatives and the potential impacts on the environment, cultural and aesthetic resources, geology and land use. If the a pplicant did not pre-file, FERC then begins the environmental review process that i ncludes many of the same293 steps of the pre-filing process. In either case, an environmental assessment is typically prepared and a more extensive environment al impact statement is also required where impacts are determined to be signifi cant. FERC's decision whether to grant or deny a pipeline certificate is based on a determination of whether the pipeline would be in the public interest. The compl icated regulatory review process for gas pipeline certificates is illustrate d below:

• The FERC process of pre-filing, filing and review c an be lengthy. There are no statutory time limits within which FERC must comple te its certificate review process. The pre-filing time frame is between seven and eight months.

• A review of approved major interstate gas pipeline projects in the Mid-Atlantic region indicates that the average time from filing of the application to issuance of an order is thirteen months. Similarly, major intra state gas pipeline projects in Pennsylvania alone averaged fourteen months from fi ling of the application to issuance of an order. Therefore, from pre-filing to receipt of a certificate, a developer spends an average of twenty to twenty-fou r months solely in the regulatory review process.

Comment 16: Commenters asserted states will not be able to mee t the 2020 deadline given that a state's proposed compliance plan may not be appro ved by the EPA until 2018.

Response 16: The EPA disagrees that we have not adequately cons idered regulatory constraints and time for implementation for the 111(d) final ru le. In response to additional analysis and many comments, we have modified the proposal and RI A; the start of the performance period has been delayed. The 111(d) final rule requires th at states develop plans that establish emission standards for affected EGUs. We are providing state s with substantial flexibility as to how they structure those plans to achieve the 111(d) require ments. The flexibility includes, for example, the choice of approaches, trading, time to develop plans, additional time before the start of the interim performance period (postponed from 2020 unt il 2022), and the ability to shift emission rate achievement between performance periods. Neith er the Building Blocks nor the IPM analyses are prescriptive, and states may consider local circumstances as they develop their plans, including system reliability, fuel diversity , other regulatory requirements and infrastructure. See sections V.A, V.B, V.D, VIII.A, VIII.C and VIII.G of the final rule preamble of the CPP and Chapter 3 of the GHG Mitigation Meas ures TSD for the CPP Final Rule supporting the final CPP.

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

Commenters stated new gas supply will not be able t o be in place by 2020 given that a state's proposed compliance plan will not likely be approve d by EPA until 2018.

Commenters stated that, besides the inordinate cost burden, there is the additional issue that the replacement of coal-fired capacity and energy will be extremely difficult (if possible at all) and unnecessarily expensive to accomplish by January 1, 2020. Commenters stated that, under the294

SIP development schedule imposed by EPA, it could b e as late as July 2018 (with allowed extensions) before it is clear what a regional SIP might require. Commenters asserted a state SIP could be expected to be in place not earlier than J uly 2016 with an indefinite period of uncertainty following the issue of the SIP for EPA review and approval (or issuance of a FIP). Commenters stated that, assuming the Clean Power Pl an is finalized and all legal issues are resolved by July 1, 2016 and the SIPs/FIPs impactin g generating resources are approved on July 1, 2017, only two and a half years would remain to plan, permit, procure, and construct a generating unit. Commenters stated that a schedule this tight would be difficult for any entity to achieve. Commenters stated it is particularly impra ctical for electric cooperatives, which must satisfy a bevy of time-consuming requirements in or der to obtain RUS financing. Commenters suggested the following timetable would need to occ ur for developing a natural gas combined cycle plant:

• June 2, 2015- Rule has been issued. Legality is sti ll in doubt, but final EPA requirements are known. Proceed with analyzing gene ration requirements and alternatives (power procurement, self-build, joint ownership, etc.) and site selection. Begin participating in SIP process. Note : all efforts and funds expended during this period will be of no value if the Rule is found not to have any legal
basis.

• July 1, 2017- Final SIPs issued and compliance requ irements are defined. Begin preliminary design process required for permitting.

• January 1, 2018- Begin permit application process. Expect application approval process to take 12-18 months (or longer if the stat e permitting agency is swamped with permit applications as a result of the CPP).

• July 1, 2018- Begin 30-week (minimum) financing pro cess. This process could be
extended due to stranded assets.

• January 1, 2019- Begin estimated 8-12 month plant d esign, equipment procurement, and construction contracting process.

• January 1, 2020- Commence construction- 18-24 month s until COD

• October 1, 2021 -Commercial operation commences.

Commenters noted that all of the dates above reflec t what would be considered normal circumstances and the duration of required actions could be extended significantly due to a glut of equipment and construction orders driven by comp liance requirements and forced unit retirements regionally and nationwide. Commenters s tated the information provided above clearly demonstrates that the retirement of RPS-2 b y 2020 is impractical for LUS.

Commenters recommended that EPA extend the start of the compliance period (e.g., five years after EPA approval of a state's compliance plan) to mitigate the constraints of building block 2. Commenters stated this major shift in generation to NGCC over the next five years is infeasible for many existing units because of technical limita tions, gas pipeline and electric transmission295

infrastructure constraints, and/or regulatory limit s. Commenters stated that, even if existing NGCC units are capable of running at 70% or greater capacity, gas pipeline capacity or transmission infrastructure may not be sufficient t o provide the gas volumes needed to operate at these high capacity factors, especially in the shor t term before additional infrastructure can be built. Commenters stated that gas supply infrastruc ture constraints may be further exacerbated during extreme weather events such as the past wint er's Polar Vortex when larger than normal gas supplies needed for space heating reduce the ga s available for generation.

Commenters stated the significant shift to natural gas from coal would require significant investment in gas pipeline infrastructure to accomm odate the increased demand for natural gas
and investment in new electric transmission enhance ments to address reliability concerns associated with the changing the location and mix o f generation resources. Commenters stated infrastructure upgrades, most notably gas pipelines and electric transmission lines, require permits and approvals at the federal, state, and lo cal levels that can take five years or more to secure and put in place. Commenters stated the time frame that EPA has allowed for this building block does not recognize the extended period of des ign, permitting, and construction that would be required to increase the utilization of existing NGCCs. Commenters stated it is unlikely that new infrastructure would be available to support th e ramp up of natural gas fired units by 2020, thereby putting pressure on states and utilities to achieve more drastic emission reductions in later years of the interim compliance period to com ply with the interim average emissions goal.

Comment 17: Commenters stated that electric system constraints need to be evaluated in the context of an integrated whole, including for examp le, acknowledging that the location of generation is important due to transmission system constraints and grid losses, the presence of

"seam" issues in multi-state environments and other issues arising from the way the electrical generating system/market operates.

Response 17: The EPA disagrees we have not considered system rel iability, balancing and the integrated utility power sector for the 111(d) fina l rule. These issues can be considered by implementing authorities. In response to additional analysis and many comments, we have modified the proposal and RIA; the establishment of CO2 emission reduction standards is regionally based, and the start of the performance period has been postponed. The 111(d) final rule requires that states develop plans that establ ish emission standards for affected EGUs. We are providing states with substantial flexibility a s to how they structure those plans to achieve the 111(d) requirements. The flexibility includes, for example, the choice of approaches, trading, time to develop plans, additional time before the s tart of the interim performance period (postponed from 2020 until 2022), and the ability t o shift emission rate achievement between performance periods. Neither the Building Blocks no r the IPM analyses are prescriptive, and states may consider local circumstances as they dev elop their plans, including system reliability, fuel diversity, the need for ancillary services, ot her regulatory requirements and infrastructure. See sections V.A, V.B, V.D, VIII.A, VIII.C and VIII .G of the final rule preamble of the CPP and Chapter 3 of the GHG Mitigation Measures TSD for th e CPP Final Rule supporting the final

CPP.296

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

Area-specific issues

Commenters disagreed with the EPA's statement that "Re-dispatch for GHG abatement purposes would require one net MWh of a lower emitting techn ology displacing one net MWh of generation from higher emitting technology" (GHG Ab atement Measures TSD at 3-6). Commenters stated that megawatts are not directly e quivalent from a legal perspective, as the courts have already decided, as well as from a tech nical and operational perspective. Commenters stated the location of the generation is important in replacing net megawatts due to transmission system constraints and grid losses. Co mmenters stated the EPA inappropriately assumes that an NGCC with excess capacity exists in a location identical to the coal generation it replaces. Commenters stated that, because the City of Tallahassee has limited transmission import and export capability, the City cannot re-di spatch its excess NGCC capacity, when it is available, to provide replacement power for coal fi red generation at other locations within Florida. Commenters suggested the EPA reevaluate an d present data that shows this is "adequately demonstrated".

Commenters recommended the EPA conduct an analysis of the interactions between Building Block 2 and the PJM-MISO seam and incorporate those findings into the structure of the final rule. Commenters stated that mandating specific uni t dispatch decisions on a state-by-state basis presents significant seam issues for states like Oh io and Indiana, where multiple regional transmissions organizations (RTOs) manage the dispa tch of electricity units located in different parts of the state. Commenters referred to a PJM re port on capacity imports and exports to and from the Midcontinent Independent System Operator, Inc. (MISO) and stated that that reliability requires the capacity construct and system planning to be consistent with actual grid operations (PJM/MISO Seams Coordination and Capacity Deliverab ility, presentation by PJM at FERC Meeting. June 20, 2013, http://www.ferc.gov/industr ies/electric/indus-act/rto/pjm.pdf.). Commenters stated the dispatch decisions required b y Building Block 2 are precisely the sorts of planning changes that will make efficient seam coor dination increasingly difficult. Commenters stated that, in the case of Indiana, there are mult iple RTOs that manage the dispatch of electricity generated within the state. Commenters stated a PJM report on capacity imports and exports to and from the MISO explains that "reliability requir es the capacity construct and system planning to be consistent with actual grid operations." Comm enters stated the dispatch decisions required by Building Block 2 are precisely the sorts of plan ning changes that will make efficient seam coordination increasingly difficult.

Commenters stated the EPA does not take into accoun t the methods utilized to dispatch EGUs under the FERC-approved SPP integrated market syste m. Commenters stated the EPA incorrectly assumes that the absence of existing NG CC EGUs in Kansas will not impact the energy produced by affected Kansas EGUs. Commenters stated that, for the states in which SPP members are located it will be necessary to establi sh some offer curve "adder" to the cost
structure of lower-cost resources in order to accom plish the EPA average re-dispatch of energy production for NGCC EGUs to 70% within those states . Commenters stated that, as a result, the dispatch of coal-based and other gas-based Kansas E GUs will be reduced substantially, and the price of energy purchased from SPP will increase su bstantially for Sunflower's members and
their consumer-owners. Commenters stated that Sunfl ower has modeled the net effect of this re-297

dispatch to identify an approximately 25% reduction in the utilization of Holcomb 1 (Sunflower's 360 MW coal-based EGU) compared to the base case. C ommenters stated the ultimate utilization of Holcomb 1 may approach a 35% capacity factor min imum load for the technology.
Commenters stated the economic model results indica te the effects of this NGCC re-dispatch will result in an approximate 65% increase in the p rice of all energy purchased from the pool 3

. Commenters noted that these effects on Sunflower me mber-owners and their consumer-owners
occur all the while there are no NGCC facilities lo cated in Kansas. Commenters stated that, because EPA has done a separate analysis of each of its building blocks in each individual state it effectively ignores these kinds of real integrated market impacts on Kansas ratepayers.

Evaluate as an integrated whole

Commenters stated that the EPA's expectation of 70% re-dispatch of natural gas capacity for the purposes of determining state goals is unreasonable because the dispatch of power is controlled by various RTOs. Commenters stated RTO dispatch is done with the express purpose of maintaining grid reliability in the most economical manner possible, and that artificial and inflexible dispatch goals are not a reasonable vari able to introduce to these systems. Commenters suggested that the EPA has not adequately accounted for how market rules in a market based system may complicate re-dispatch and that the EPA should not assume that limiting operation of coal-fired EGUs will force re-dispatch consideri ng the complicated economics that will inevitably develop when the four building blocks ar e combined. Commenters stated the EPA should direct states in RTO regions to work with RT Os, utilities and pipelines to determine the level of dispatch that can be reasonably achieved a nd allow states to modify their targets (if necessary) to reflect the achievable level of dispa tch.

Commenters stated the EPA's conclusion that NGCC ut ilization rates can reach 70 percent in every state is faulty because the EPA's analyses do not take into account required changes in system dispatch control, system balancing and relia bility responsibilities, existing energy and fuel supply contracts, transmission rights or trans mission service reservations.

Commenters asserted that in many cases, achieving s uch dramatic increases in NGCC utilization effectively would require substantial changes in ho w the natural gas industry and organized wholesale electricity markets operate, both of whic h are outside the scope of the proposed guidelines and EPA's general authority under the CA A. Commenters added that while the NODA points to discrepancies and limitations of the proposed guidelines, none of the new proposals provide credible solutions. Commenters ex pressed the opinion that the NODA's proposals would add subjective elements and would e xacerbate some problems by grossly overestimating fuel switching potential in the stat es.

Commenters said that meeting EPA's state goals thro ugh increased re-dispatch of existing NGCCs in lieu of coal would, in many cases, require a system redesign, including the building of new transmission lines and new EGUs, which would ta ke a much longer time frame to be completed than EPA allows, particularly given that the interim compliance period begins in 2020, only 3 years, at the most, after a state coul d have a final, approved compliance plan.

Commenters stated that many different types of syst em constraints may make it impossible or unreasonable for state NGCC fleets to dramatically increase their utilization rate. Commenters298

referred to a 2010 CRS report (Stan Mark Kaplan, Di splacing Coal with Generation from Existing Natural Gas-Fired Power Plants, CRS, Jan. 2010) which concluded that the ability of existing natural gas plants to displace coal genera tion depends on many factors, including: the amount of excess capacity in the natural gas fleet; the operating patterns of coal and gas plants and the system's degree of flexibility to change th em; the ability of the transmission system to deliver power from existing gas plants to loads ser ved by coal plants; and the ability of the natural gas supply industry to deliver larger amoun ts of natural gas where it is needed. Commenters stated the CRS report demonstrates the i mportance of evaluating the electric power system as an integrated whole that comes with vario us locational constraints. Commenters stated that an assessment of the "excess" natural gas gene rating capacity is not enough; rather, limitations such as the location of each plant in t he electric grid and plant position vis-a-vis
nodes and load must be considered. Commenters state d that each portion of the system, while to some extent interrelated, is unique, with specific resources designed to fill specific needs; thus, the tailored nature of the system makes one-size-fi ts-all solutions problematic.

Commenters stated that the current methods of load dispatching and future reserve margins and transmission loading need to be assessed for this r evolution that would be only 6 years away.

Commenters stated that, despite having the physical potential to run at higher utilization rates, some plants are unable to achieve higher utilizatio n rates when in actual operation. Commenters stated that NGCCs that have been designed to operat e as intermediate or peaking units with lower capacity factors, may not be technically able to increase their utilization to 70 percent.
Commenters stated that it is not clear that EPA fac tored these situations, or the impacts of increased NGCC utilization on "must run" resources, into its re-dispatch analyses. Commenters stated EGU and electric system constraints may make increased NGCC utilization unachievable in the timeframe stipulated by the EPA. Commenters cited a 2010 Congressional Research Service (CRS) report as concluding that the ability of existing natural gas plants to displace coal generation depends on many factors, including:

• The amount of excess capacity in the natural gas fl eet;

• The operating patterns of coal and gas plants and t he system's degree of flexibility to change them;

• The ability of the transmission system to deliver p ower from existing gas plants to loads served by coal plants; and

• The ability of the natural gas supply industry to d eliver larger amounts of natural gas where it is needed.

According to commenters, the CRS report demonstrate s the importance of evaluating the electric power system as an integrated whole that comes with various locational constraints; an assessment of the "excess" natural gas generating c apacity is not enough. Commenters stated that physical (infrastructure) and operational limitatio ns, as well as the location of each plant in relation to other generation facilities and load, m ust be considered. Commenters indicated that
these locational limitations matter as much as unit size or technical capabilities, and gave the example that some NGCC units that theoretically cou ld run at higher capacity factors will299

necessarily be hindered by transmission constraints . Commenters added that for coal-based generation to be able to be replaced by increased p roduction from existing NGCCs, the natural gas units would have to be located in proximity to the coal plant. According to the commenters, CRS conducted a proximity analysis and concluded, b ased on locational constraints alone, that "[e]xisting NGCC plants near coal plants may be abl e to account for something on the order of 30% or less of the displaceable coal-fired generati on and CO2 emissions," and that this limitation should be factored into any plans to replace coal w ith natural gas (CRS Report at 17).

Commenters stated that equally important is whether the two units are dispatched by the same transmission operator. According to the commenters, this concern was raised by Montana Public
Service Commissioner Kavulla when he noted that two plants in the same state can be dispatched by different entities, which means that the two pla nts would "not share a dispatch signal that would allow one plant's increased operations to res ult in the lower dispatch of a plant operating
in a different market."

Commenters stated that there are other system const raints that can make it difficult to displace coal with existing natural gas-based generation. Co mmenters noted that it is possible that increasing the capacity factor of existing NGCC uni ts would involve the closure of coal-based "must run" resources that could put reliability at risk. Commenters also indicated there may not be enough actual NGCC spare capacity to achieve the necessary levels of fuel switching that are included in the proposed guidelines. Commenters gav e the example that Arizona and other states with units that do not run much in the winter, but run at maximum capacity during the hot summer months, will find it very difficult to compl y with the interim targets. According to the commenters, in explaining this situation, the Direc tor of the Arizona DEQ pointed out that "electricity generated at a facility in the winter cannot offset the need for electricity during the peak demands experienced in the middle of the summe r." Commenters explained that due to the extreme temperature fluctuations in Arizona, the EP A cannot assume that all capacity from natural gas units is available to be dispatched to replace coal generation - while such capacity may be available to displace some coal generation d uring winter months, this "excess" capacity will be needed to meet summer peak demand. Commente rs added that increasing existing NGCC generating capacity may also not be possible due to conflict with ozone attainment plans and unit-specific run-time limitations in NGCC permits in areas such as Southern California that are non-attainment for some criteria air pollutants.

Commenters added that the EPA has not addressed the effect that increased existing NGCC capacity factor will have on the other Building Blo cks - existing coal and gas units do not operate in a vacuum and are part of a complex, inte grated electrical system so that shifting the way these units are operated and dispatched will ha ve impacts on other forms of generation and how they contribute to the electrical system.

Commenters stated an assessment of the excess natur al gas generating capacity is not enough. Commenters stated that physical constraints are not uncommon in the delivery of natural gas during very cold months as the transmission to Empi re's natural gas generation facilities has been interrupted by frozen compressor stations. Commente rs stated that, even when all natural gas pipeline infrastructure is operating properly there are numerous instances where even firm transport contracts get curtailed during extreme we ather events. Commenters stated that while Empire experienced recent curtailments on the natur al gas pipeline to its generators and had to300

burn oil as an emergency backup, not all NGCC's are equipped with the ability to use oil backup. Commenters stated new infrastructure and long-t erm firm transportation contracts will be needed to meet the 70 percent CF computation for th e states. Commenters stated that natural gas EGUs are dispatched only when it is economical to d o so, as a back-up to RE, and if needed to meet load requirements while ensuring system reliab ility. Commenters stated the ability of existing natural gas plants to displace coal genera tion depends on many factors, and demonstrates the importance of evaluating the elect ric power system as an integrated whole that
comes with various locational constraints. Commente rs supported the four recommendations submitted by the SPP in their comments to the Propo sed Rule to address reliability inadequacies: (1) a series of technical conferences jointly spon sored by the EPA and FERC; (2) completion of a detailed, comprehensive and indepen dent analysis of the impacts the Proposed Rule will have on the reliability of the nation's b ulk electric system; (3) extension of the proposed schedule for compliance in order for the n ecessary electric and gas infrastructure to be identified and constructed; and (4) adoption of a r eliability safety valve.

Commenters stated the EPA needs to more fully analy ze the interaction between and among electric generation, wholesale electricity markets and the natural gas and Commenters stated the
EPA did not take into consideration time constraint s required to physically realign the natural gas supplies and transmission and distribution infrastr ucture needed to accommodate the 2030 requirements when assessing the 70 percent capacity ability of the NGCC fleet. Commenters
stated the EPA did not take into consideration the time required to finance, permit, and construct adequate generation and transmission infrastructure and new NGCC EGUs and should allow additional time needed to meet compliance. Commente rs stated the EPA should take into consideration the planning and construction of elec tric transmission upgrades which will be required as part of the solution to comply with the Proposed Rule. Commenters stated the SPP indicates these upgrades could take up to eight and one half years and cost up to approximately $2.3 million per mile for new 345 kV transmission l ines, excluding substation costs.

Work with power regulators

Commenters stated the EPA should work proactively w ith electric power regulators to ensure that adequate pipeline capacity is available for th e expanded dispatch of gas-fired generation. Commenters agreed with the EPA that natural gas pip eline capacity, with feasible amounts of expansion, can meet the needs of increased natural gas use to reduce carbon pollution. Commenters noted that the EPA has found average mon thly fleet-wide NGCC utilization rates have reached 65%, showing that the pipeline system can currently support these rates consistent with the increased use of natural gas as BSER for a n extended period (79 FR 34863). Commenters agreed with the EPA's observation that p ipeline and transmission planners have repeatedly demonstrated the ability to methodically relieve bottlenecks and expand capacity (79 FR 34864). Commenters stated the EPA should work pr oactively with entities such as FERC and ISOs on issues such as gas-electric market coordina tion and the use of firm pipeline capacity by natural gas generators. Commenters stated that, for instance, market rules may unduly hamper the use of natural gas generation, such as the fail ure to allow the recovery by natural gas generators of firm pipeline transportation costs.

Commenters encouraged the EPA, before it proceeds w ith a final rule, to consult with federal and state agencies with greater expertise in operat ion of the country's natural gas transmission301

system (e.g., FERC and the United States Department of Transportation Office of Pipeline Safety) to gain a greater understanding of the infr astructure expansion needs associated with application of Building Block 2, such as trunklines , compressor stations, and peaking storage facilities, and the timelines necessary to complete such projects. Commenters stated this understanding is fundamental to establishing the te chnical feasibility of Building Block 2. Commenters expressed concern that the high proporti on of federal, state, and tribal lands in the Western U.S. represent unique challenges to timely completion of new energy-related projects.

Commenters stated that, given the warranted concern s from the region's top energy officials on over-dependence on natural gas, the EPA must work w ith others and allow those with the expertise and authority to propose changes related to the dispatch of electricity. Commenters stated that, since New England states are not likel y to take a path that would place their utility customers at risk, the state goals should be change d to reflect the actual natural gas constraints. Commenters stated that, according to the Independen t System Operator for New England (ISONE), the factors contributing to natural gas fuel a vailability issues are inadequate infrastructure, unreliable fuel arrangements, limited storage, and out of sync markets. Commenters stated that, under the EPA's model, New England as a whole is pr ojected to have no remaining oil or coal resources, which would be highly detrimental to the region's reliability as well as customer rates.

Commenters requested the EPA to work with reliabili ty experts, states, and industry stakeholders to undertake a detailed, comprehensive analysis of potential reliability impacts of the CPP before
it is finalized.

Commenters stated the EPA's final guidelines must c onsider the role that FERC, NERC, RTOs/ISOs have in assessing technical feasibility a nd reliability implications of Building Block 2. Commenters stated that, due to the interconnecte d nature of the electric and natural gas systems, the EPA should allow states sufficient tim e to complete regional studies to assess the adequacy of infrastructure systems to support incre ased natural gas use for electric generation.

Commenters stated that NREA members feel it is impe rative that EPA consult with Federal Energy Regulatory Commission (FERC), North American Electric Reliability Corporation (NERC) and Regional Transmission Organizations to d etermine the impacts on reliability, cost stabilization and national security issues. Comment ers stated the NERC, the Midcontinent Independent System Operator (MISO) and Southwest Po wer Pool (SPP) have reviewed the proposal and have expressed significant concerns ab out reliability. Commenters stated a major concern in Nebraska regarding reliability is the ne ed to meet consumer loads primarily with natural gas and renewable generation. Commenters st ated a lack of sufficient pipeline infrastructure to increase the supply of natural ga s and the time constraints with modifying existing plants and building new plants render it i mpossible to meet the deadlines in the EPA Proposal.

Regional feasibility studies

Commenters stated the EPA should conduct a state-by -state study to determine the time required to finance, permit, construct and commission new NG CC EGUs taking into account what NGCC units can burn oil in order to reach the 70 percent capacity goal in Building Block #2.
Commenters stated that the CPP will result in incre ased costs. Commenters stated each state in302

every region needs to perform a robust natural gas feasibility study in order to determine what is achievable through re-dispatch of units, and the as sociated costs. Commenters stated the EPA
should take other environmental concerns into consi deration when establishing NGCC capacity factors and the economic analysis for the Proposed Rule. Commenters stated the EPA did not, but should, take into consideration the costs and p roject delays for right-of-way obtainment and for the construction of natural gas supply pipeline s and transmission infrastructure to accommodate the Proposed Rule computations. Comment ers stated commodity costs associated with supply and demand economics will escalate due to more than doubling the amount of natural gas used for electricity production.

Commenters referenced a reliability impact assessme nt of the EPA's Proposed Rule within the SPP region, using as its baseline the generator ret irements that EPA has projected will result from implementation of the Proposed Rule. Commenter s stated the assessment's findings make it very clear new generation and transmission expansio n will be necessary from a reliability perspective: after incorporating the EPA's assumpt ions into power-grid models that assessed how compliance with the Proposed Rule would impact reliability within the SPP region, the models could not progress without additional genera tion. Commenters stated the conclusion of the report indicates that, if the compliance period begins before adequate generation and infrastructure can be added, the SPP region will fa ce a significant loss of load and violations of regulatory reliability standards. Commenters stated that, according to the impact assessment, SPP's transmission system could face severe overloa ds that will lead to cascading outages. Commenters stated that, in general, the report indi cates not enough time is allowed to compensate for projected generation unit retirement s, nor to build the transmission infrastructure necessary to maintain system reliability.

Emergencies

Commenters stated that, although the EPA indicates consideration is given in the flexibility of state plans to accommodate emergencies, the stringe ncy of the interim and final goals for this building block creates a shift in a direction that cannot be reclaimed during emergencies. Commenters stated that, during the extremely cold w eather experienced earlier this year the SPP determined the activation of oil-fired generating u nits was required in addition to our coal-fired and natural gas-fired generation in order to provid e reliability on a system-wide basis. Commenters stated that during a reliability event d ispatch options do not consider emission reductions; there are times when the performance of individual plants, even those that emit CO2 at a higher rate, must be considered in the context of grid reliability. Commenters stated the delivery of electricity is extremely complex and th e system must be built to withstand extreme
weather.

Commenters stated that a presumed ability to activa te NGCC at 70 percent utilization does not offer the diversity needed to respond to common occ urrences, let alone emergency situations. Commenters stated that overdependence on any one en ergy source such as natural gas will not allow adequate response capabilities in emergencies . Commenters stated the electric generation system has become increasingly dependent on the ope ration of the natural gas system and the natural gas system is also dependent on electricity for its ability to deliver natural gas from the well-head to the consumer. Commenters stated that, in the event of grid failure, both systems could be disrupted. Commenters asserted that each s tate, along with the RTOs in that state, must303

be able to have the time to fully assess the option s available during extreme weather and emergency events and maintain robust diversity in g eneration options.

Commenters stated that Empire and other owners of N GCC EGUs will need to continue to have alternate fuel capability in the regions in which t hey operate to allow for contingencies. Commenters stated that natural gas supply deficienc ies and historical price volatility experienced by Empire continue to drive the decision to maintai n fuel diversity in our generation mix. Commenters stated that a significant reliance on na tural gas creates additional risks as it is impracticable and geologically impossible to locall y inventory the fuel for our fleet. Commenters
stated there will be events which cause deliverabil ity issues and in some cases shortage of the commodity due to circumstances of risk that exist t oday. Commenters stated that, during a recent natural gas supply shortage issue, fuel oil, which is traditionally a significantly higher priced fuel, became a better economic decision than the ut ilization of natural gas or market power.

Comment 18: Commenters generally stated that more analysis is n eeded, such as plant-level impacts, state-specific actions, pipeline growth ra te, population growth, storage, high pressure, variability of loads, and limitations in rural area s.

Response 18: The EPA disagrees that we have not considered syste m constraints and demand in the development of the 111(d) final rule. Additiona l analysis can be considered by implementing authorities. In response to additional analysis and many comments, we have modified the proposal and RIA; the establishment of CO2 emission reduction standards is regionally based. The 111(d) final rule requires that states develop plans that establish emission standards for affected EGUs. We are providing states with substan tial flexibility as to how they structure those plans to achieve the 111(d) requirements. The flexi bility includes, for example, the choice of approaches, trading, time to develop plans, additio nal time before the start of the interim performance period (postponed from 2020 until 2022) , and the ability to shift emission rate achievement between performance periods. Neither th e Building Blocks nor the IPM analyses are prescriptive, and states may consider local cir cumstances as they develop their plans, including system reliability, fuel diversity, deman d growth, other regulatory requirements and infrastructure. See sections V.A, V.B, V.D, VIII.A, VIII.C and VIII.G of the final rule preamble of the CPP and Chapter 3 of the GHG Mitigation Meas ures TSD for the CPP Final Rule supporting the final CPP.

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

Aging pipelines need to be analyzed

Commenters stated the EPA must consider the hazards posed by aging pipeline infrastructure. Commenters cited a US DOT report showing the age di stribution of US pipeline infrastructure, referred to a recent National Transportation Safety Board (NTSB) report which stated that "The aging natural gas infrastructure is a major concern for the state", and described the impacts from a pipeline rupture that occurred on December 11, 20 12. Commenters stated that, for these reasons, they have very serious questions about whe ther the state's and nation's aged pipeline304

infrastructure can support a 70 percent capacity fa ctor for new NGCC units, or even the 65 percent alternative proposed by EPA. Commenters sta ted that critical issues include reliability problems for the electricity grid; delivery problem s for residential, commercial and industrial customers during periods of extreme cold; public sa fety problems from the explosive nature of compressed natural gas; and the environmental hazar d from uncontrolled releases of methane.

Analyze interactions between the Building Blocks

Commenters also stated that the EPA's inclusion of re-dispatch to NGCC units at 70 percent in the proposed BSER may also eliminate needed flexibl e generation to balance intermittent generation resources that are low-carbon emitting, causing additional impacts to the system as whole. According to the commenters, both FERC and E PRI have noted an increased and growing need for flexible generation capacity at th e national level for balancing and regulation, particularly in the morning and evenings, due to ra pid changes in solar and wind generation.
Commenters indicated that the EPA's inclusion of re newable generation in the proposed BSER through building block 3 will increase the need for flexible generation sources to balance renewable sources; therefore, eliminating NGCC unit s as flexible units by requiring their
conversion to use as base load sources should be an alyzed further. Commenters stated that NERC, whose data EPA used in its technical feasibil ity analysis for this block, issued comments on the proposed guidelines warning that the timing and stringency proposed in this block might cause reliability issues. Commenters recommended th at the EPA analyze the proposed BSER for all relevant interactions between the building bloc ks and adjust the proposal where necessary to ensure the entirety of BSER is technically feasible and can be achieved at a reasonable cost without negative reliability impacts.

Commenters stated the EPA must consider the need fo r added load-following capacity due to the installation of additional renewable energy under b uilding block 3.

Analyze local needs

Commenters expressed concern that, although the EPA states that it is not concerned with infrastructure adequacy on the whole, the Agency fa iled to analyze whether local changes in the generation mix will require pipeline installation o r capacity expansion. Commenters stated that, while coal deliveries are quite flexible in timing and transportation options, natural gas depends on available pipeline capacity in the distribution system and at each facility in real time. Commenters stated regional infrastructure limitatio ns will complicate and can delay increased reliance on natural gas. Commenters stated planning , permitting, contracting, financing, and building this infrastructure if needed will delay f ull implementation of the CPP.

Commenters stated that, because existing NGCC facil ities do not share locations with the coal facilities they are expected to replace, additional electric transmission infrastructure could be needed to ensure that reliability can be maintained and electricity can reach consumers.
Commenters stated the EPA has not accounted for the se challenges in making its blanket assumption in building block two.

Analyze operational constraints305

Commenters stated that uncertainty exists regarding the EPA's proposal to operate these NGCC
units as a base load resource and how loss of this flexibility could affect other aspects of system operations. Commenters stated that a significant im pact on pipeline infrastructure could occur if the proposed Clean Power Plan results in the increa sed need for simple cycle combustion turbines to support flexible operations that can no longer be supported by NGCCs. Commenters stated that, if simple cycle combustion turbines ar e relied on more significantly because of the EPA's proposal, then additional pipeline infrastruc ture may be necessary, especially if the need grows in the winter and there is a need for increas ed firm pipeline capacity.

Commenters stated many operational constraints shou ld be more fully considered by EPA, including system reliability requirements, natural gas utilization for peak load, planned and unplanned pipeline outages, market drivers, and tra nsmission constraints, all of which have the potential to make the targeted increased utilizatio n of natural gas plants less likely in the near

term.

Commenters the EPA has not provided a full assessme nt that considers the following factors and must do so prior to finalizing the rule: (1) the EP A must consider that, since operating NGCC units at a high capacity factor leaves less open ca pacity that can be used to react quickly to demand swings and peak loads and other reliable gen eration, such as coal-fired EGUs, cannot ramp up as quickly as NGCC units, load following mu st be accomplished with new NGCC capacity or simple cycle combustion turbines (CTs) and (2) the EPA must remember that it is not the average annual load demand peaks and swings tha t must be allotted for; it is the maximum capacity that may be needed in any one hour to main tain electric reliability.

Commenters stated that the significant resource ade quacy and reliability risks arising from such a wholesale change in dispatching of the generation f leet under the proposed rule are oversimplified by the EPA and did not receive suffi cient analysis by the EPA. Commenters also stated that the EPA did not sufficiently analy ze the impact of changing the operation of "load following" natural gas units to running them in base-load operation, which would make such units unavailable for managing generation from renewable resources (particularly wind) as they are often utilized today. Regarding the EPA's analysis, commenters supported several comments by EPRI on the rule: (1) cautioned about i ncreasing natural gas plants to a 70% capacity factor because there is little long term e xperience with operating at that level; (2) questioned assumptions that natural gas production could ramp up to meet the large increase in supplies needed to operate in this fashion, the mar ket price of natural gas, availability of pipeline infrastructure, and firm pipeline capacity; (3) que stioned the relationship of gas capacity factors to gas prices: "Reinforcing the dependency of gas p rice to capacity factor; natural gas prices are currently forecasted to be relatively low, history has demonstrated the price of natural gas to be highly volatile, and multi-year forecasts have cons istently been inaccurate; establishing a mitigation goal based on an assumption of persisten t low natural gas prices is not a reliable or dependable approach to estimating capacity factors for NGCC (natural gas combined cycle) plants over a long period; and (4) noted the extrem e cold weather in January 2014 and expressed concern about electric system reliability in future instances.

Commenters stated that there are a number of challe nges to the natural gas industry in meeting the electric gas loads. Commenters stated that Buil ding Block 2 poses major regional challenges306

that the Proposed Rule fails to recognize and addre ss. Commenters described several of these
issues:

• High pressure requirements, where consistent fuel p ressure is necessary for the

generator to meet operational and environmental req uirements. Newer, larger, combustion turbine/combined cycle units are less to lerant of variations in pressure
than older units. While the electric utilities cont inue to increase their pressure requirements to improve their overall fuel efficien cy, the increased requirements can impair overall pipeline flexibility and respons e capability.

• The variability of electric gas loads. More problem atic for the gas industry than seasonal electric gas load variation are daily and weekly variations (i.e., nonratable-take issues). Daily variation is particular ly difficult for pipelines to accommodate because they were initially designed fo r steady hourly load profiles (i.e., 1/24 of the daily consumption requirement ea ch hour). Pipelines are thus unlikely to be able to provide the fuel necessary t o meet daily peak electricity demand. Peak demand will thus have to be met by coa l-fired or nuclear-powered units. If coal-fired units are prevented from being dispatched or are required to close under the Proposed Rule, then implementing th e Rule presents significant risks of power failure at peak times.

• System flexibility to accommodate intermittent rene wables.

• Large electric utility loads. Loads are as large as or larger than many local distribution company (LDC) loads and, in some cases , exceed the capabilities of smaller diameter pipelines and, these electric util ity loads mostly occur at a single point, whereas almost all the LDC loads are served over multiple city gates. Natural gas suppliers are significantly limited or simply not present in many of the rural areas where electric cooperative baseload facilities are located. Natural gas supply pipelines may be hundreds of miles away from where additional electric generation may be required to serve cooper ative rural service areas. Even where pipelines are available, the availability of firm gas supplies at a reasonable price is an ongoing uncertainty.

Infrastructure needs analysis

Commenters questioned whether it is feasible for st ates to meet the proposed required emissions reductions because, for example, building block two increased utilization of combined cycle natural gas plants presupposes that pipeline and ot her infrastructure is adequate or can be built to enable plants to operate at 70 percent capacity fac tors.

Commenters stated that the EPA also must provide a legitimate justification for its assumption that supplemental electricity transmission and gas pipeline construction "can reasonably be expected" because the Proposed Rule relies on new t ransmission and pipeline construction to satisfy Building Block 2's infrastructure requireme nts, the infrastructure required for Building Block 2 must be in place by 2020, and the IPM does not consider construction of new electricity transmission or gas pipelines, thus underestimating overall costs of compliance with the307

Proposed Rule (IPM Documentation at 2-10 to 2-11, 1 0-37 to 10-38). Commenters indicated that such an analysis should consider the time required for the transmission and pipeline permitting and construction necessary for compliance - electri city transmission planning and construction can take 5 to 15 years (NERC Report at 20) and perm itting can be particularly onerous in the West where transmission or pipeline often must run across federal and tribal lands and siting and permitting alone can take 10 years or more. Comment ers added that the specific permits and rights-of-way needed for transmission design and co nstruction cannot be obtained until the studies required by RTOs and/or ITOs are completed according to the Open Access Transmission Tariff for the transmission operators, which can be complicated if the construction extends across multiple states in a region or if in terregional planning is required.

Commenters stated the EPA has not fully analyzed an d supported the feasibility of the level of re-dispatch required. Commenters stated that addres sing reliability problems either through modification of the bulk transmission system or con struction of new generating units requires that transmission studies be performed. Commenters stated these studies - and any identified upgrades - optimistically take approximately two ye ars to complete. Commenters stated that, for larger transmission projects that may be necessary to accommodate large additions of renewable generation are more difficult and time consuming to evaluate, permit and construct, seven to ten years is a more likely time frame for such projects , putting aside any consideration of the potential need to study and build many transmission projects simultaneously as all states and RTOs attempt to meet infrastructure needs under Cle an Power Plan compliance.

Commenters expressed concern that by selecting only a narrow range of available data, the EPA's derived estimate of growth in the natural gas pipeline (GHG Abatement Measures TSD, page 3-18, Table 3.5) is not "extremely conse rvative", but rather overly ambitious. Commenters stated the EPA is picking select years ( 2005-2010) to justify its conclusion. Commenters referred to their own analysis which app lied several linear regression analyses on
the same dataset available from the EIA and also ex panded upon the EPA's analysis, utilizing the full dataset (1994-2013). Commenters stated that, f rom 2005 to 2010, the period selected by U.S. EPA, this growth rate more than doubled compared to the period 1994-2007. Commenters concluded the 21% growth in this period is not full y representative and is certainly not conservative. Commenters stated that, most concerni ng, is the apparent decline in capacity observed for years 2011 to 2013, which calls into q uestion whether the pipeline capacity can sustain the growth projected by the EPA. Commenters urged the EPA to consider the full range of available pipeline capacity data, examine more c losely the apparent slowdown in growth observed in recent years, and derive a more represe ntative estimate of growth potential of the natural gas pipeline system. Commenters stated the EPA does not have the expertise to determine fuel market impacts or the ability to det ermine if individual states need to, or can, expand infrastructure. Commenters stated the EPA is treading into a domain, control of the electricity generating market, in which it has neit her expertise nor authority to regulate in this

manner.

Commenters stated that, in its Proposed Rule, the E PA failed to account for increases in NGCC consumption just from existing generation sources. Commenters stated this additional gas transportation capacity needs to be established bef ore NGCC can meet its current demands and future proposed 70% capacity target. Commenters sta ted that, currently, the United State and Canada are already in need of additional natural ga s pipelines to provide adequate transportation308

for existing generation sources. Commenters stated INGAA estimated that the United States and Canada already need 28,900- 61,600 miles of additio nal natural gas pipelines through 2030 --this is before considering any necessary increase in tra nsportation needs from the Proposed Rule.

Commenters stated additional evaluation is needed t o ensure this increased demand can be accommodated. Commenters stated, given the length o f time it takes for new permitting and construction, it appears unlikely that sufficient n ew infrastructure could be developed over such a short period of time, given anticipated constraints such as federal land approvals, endangered species considerations, and/or public opposition.

Commenters referenced the NODA (79 FR 64543) and st ated EPA should have corrected its analysis for infrastructure improvement before deve loping its ambitious and unrealistic block 2 goals. Commenters stated that, to perform a compreh ensive study of the natural gas pipeline system to determine the feasibility of supporting i ncreased natural gas consumption would take at least six months to a year in duration and shoul d have been done by the EPA to support the proposal. Commenters stated the comment period of 1 20 days on the original proposal was not sufficient time to perform a comprehensive study no r was the remaining 30 days sufficient to provide the additional information requested in the NODA (79 FR 64548).

Commenters stated that assumptions of high dispatch rates should be removed until the EPA (working as a supporting player with entities such as FERC, NERC, MISO or other Regional Transmission Organizations and individual states th at have primacy regulating reliability and system stability) sufficiently evaluates the impact on existing infrastructure from proposed Building Block #2. Commenters stated the assumption that high NGCC capacity factors are possible on an annual basis is problematic from a r eliability and system stability perspective.

Commenters stated that the EPA failed to fully eval uate existing natural gas supply and electric transmission constraints, contractual arrangements, or the timing and feasibility of necessary gas supply or transmission grid infrastructure improvem ents or expansion, each of which may limit the feasibility, reliability, and sustainability of units collectively operating at such high capacity factors. Commenters added that timing consideration s are also of significant concern with regards the time to plan, design, approve, and cons truct any necessary pipeline and transmission infrastructure. Commenters asserted that evaluating these types of issues in more detail would offer a more credible assessment of potential natur al gas supply concerns than the qualitative conclusions that EPA made in the proposed rule. Com menters stated that the EPA failed to identify or fully evaluate potential constraints wi thin or impacts to the electric transmission system that may limit the feasibility, reliability and sustainability of NGCC units collectively operating at higher capacity factors, instead provi ding minimal qualitative justification.
Commenters noted that the EPA references EIA and EE I reports of "planned" transmission projects, but offers no context as to whether these "planned" projects will address any specific issues related to the increased dispatch of NGCC un its. Commenters stated that the EPA should thoroughly review the current state of the existing natural gas supply network and related contractual arrangements to determine if the system can readily support an increased utilization
of the entire NGCC fleet and/or what infrastructure challenges must be addressed, by investigating the following issues:309

Natural gas pipeline transmission infrastructure is typically not built on speculation. FERC requires that pipelines demonstrate market need, mo st commonly shown through the execution of a sufficient level of long-term service contract s, before approving either expansions of existing infrastructure or development of new infra structure. Pipeline and storage infrastructure capacity is sized to meet the contractual demand of firm customers, with little or no reserve capacity. Because the pipelines are sized to accomm odate the needs of firm shippers, many pipelines are fully subscribed. Competition determi nes which natural gas pipeline will serve new load. There is no natural gas transmission pipeline equivalent to the electric industry's RTOs. The Interstate Natural Gas Association of America, the trade association that advocates regulatory and legislative positions of importance to the pipeline industry in North America, has stated, "the competitive model has worked well in t he past and will continue to work well into the future." This competitive model may not, in fac t, result in the most expedient, economic and holistic national expansion of the natural gas pipe line infrastructure. The availability of existing
infrastructure and the construction of new infrastr ucture is locational. Economic access to sufficient, reliable delivery capacity will be loca tion-specific. Each NGCC that has already been built may have enough pipeline infrastructure in pl ace to meet its needs if it has made a Firm Transportation capacity commitment for its full req uirements. If it has not, then additional pipeline infrastructure may be needed to support a 70% capacity factor. The siting of new gasfired electric generation will need to balance the cost and timing of both natural gas pipeline and electric transmission system expansion. Incremental costs for Firm Transportation and balancing services unique to electric generation loads may no t result in the economic dispatch of NGCC's up to 70% capacity factor. However, if the units ar e dispatched at a 70% or greater capacity factor, the reservation charges associated with Fir m Transportation Service (FTS) could be more efficiently utilized. Currently, the RTO model doe s not allow the cost of FTS to be included in the bid/offer. Consequently, it is estimated that l ess than 50% of the nation's gas-fired electric generation is served by FTS as the electric generat ors have no ability to recover this cost from the RTO. The EPA's proposed timeline may not be suf ficient to increase existing NGCC plant capacity factors to as much as 70%. If new infrastr ucture is necessary, it could take up to three years from Service Agreement execution until initia l natural gas deliveries. Regulatory and environmental approvals, engineering design, easeme nt acquisition and construction have discrete timeframes that allow only minimal flexibi lity by location. Furthermore, electric generating utilities will not be able to make the c ommitment for Firm Transportation service until the proposed rule is finalized and the state plan is approved. If additional NGCC capacity is needed the utility will also need Certificate of Pu blic Convenience and Necessity approval from the governing state public service commission befor e it will be in a position to subscribe for Firm Transportation. Increased demand for pipeline infra structure across the country to comply with the final requirements could increase competition f or construction labor and materials. Significant expansion is already occurring througho ut the northeast and the demand for limited resources is being stretched. Additional pressure o n these resources could increase costs and delay completion of projects by the required to sup port compliance with the final rule.

Commenters stated the EPA has not adequately demons trated that the natural gas pipeline and electricity transmission networks can support aggre gate operation of the NGCC fleet at up to a 70% capacity factor on average, either as they curr ently exist or with modifications that can be reasonably expected in the time frame for complianc e with this rule. Commenters stated NERC must consider reliability but complete reliance on a single baseloaded fuel is not practical. Commenters stated that oil backup would be necessar y at a minimum. Commenters stated that310

oil firing is higher CO2 and higher wear and tear o n NGCC units, meaning less availability. Commenters suggested that the EPA further evaluate and understand the dynamics of natural gas transmission in enough detail to confidently claim that there are no pipeline constraints anywhere
in the nation.

Commenters stated the EPA failed to take into accou nt the lack of necessary infrastructure that must be in place in order to have an adequate natur al gas supply and fails to account for the lack of adequate storage. Commenters stated that, if a 7 0% capacity factor is required to meet building block 2, it will be necessary for a natura l gas operator to be able to have storage to provide the flexibility for necessary operations. C ommenters stated the EPA has not provided evidence that extended periods of high capacity fac tor operation of NGCC generation can occur under periods of peak natural gas demand in the win ter. Commenters stated that the EPA relies on data during peak hours when constraints on pipel ines or electricity transmission networks are most likely. Commenters stated that, in Iowa, howev er, peak electricity demand typically occurs in the summer when there is a large air-conditionin g load, but the peak natural gas consumption occurs in the winter when there is a large building heating load. Commenters stated Iowa will prove a good test case for the building of a natura l gas pipeline as the necessary franchise requirements are negotiated through the IUB during the next few months. Commenters stated that, during the 2014 legislative session, much dis cussion was had and attempts made to limit the
use of eminent domain for transmission lines and it is expected that the same issues will arise during the next legislative session in regard to th e proposed crude oil pipeline. Commenters stated that potential legislation limiting or imped ing the process could prevent or substantially hamper the building of necessary natural gas pipeli ne infrastructure.

Natural gas demand forecast

Commenters did not agree with the EPA's estimate th at significant growth in natural gas demand (1.2 trillion cubic feet, a 14% increase) can be ex pected prior to 2020. Commenters stated that, if finalized, the proposed rule would increase natural gas demand by approximately 22% by year 2020, with occasional short-term spikes higher than this amount. Commenters referred to a report prepared for Dow by Charles River Associates which predicts that the increase in natural gas demand for the electric utility sector will be an additional 1.8 trillion cubic feet by 2020 (a 22% increase), and an additional 3.8 trillion cubic feet by 2030. Commenters stated the same report predicts that natural gas demand within the industrial sector could increase by an additional 1.8 trillion cubic feet per year over th e next decade and stated the EPA has
underestimated this increase in the industrial sect or.

Plant level analysis

Commenters stated that the EPA's analysis of the el ectricity and gas infrastructure required to support massively increased NGCC generation must be robust. Commenters asserted that a robust analysis would consider plant-level infrastr ucture constraints, justify assumed infrastructure improvements and analyze gas supply and storage requirements. Commenters stated that EPA's re-dispatch analysis should consi der plant-level electricity transmission and gas pipeline constraints. Commenters noted that the EPA acknowledges that re-dispatch may be limited by plant-level infrastructure constraints, but presumes that existing transmission and pipeline infrastructure will be sufficient and that any necessary supplemental infrastructure311

construction "can be reasonably expected" based on prior and planned transmission and pipeline projects, that the Agency contends that adequate in frastructure exists by pointing to nationally aggregated miles of transmission and pipeline from prior and planned projects without regard to the projects' location or purpose, and that the Age ncy cites to 21 percent average regional pipeline capacity growth from 2005 to 2010 as evide nce that pipeline capacity will not constrain Building Block 2 re-dispatch. Commenters asserted t hat these national and regional analyses do not consider plant-level infrastructure constraints and that the EPA's assertions suffer from substantial analytical deficiencies.

Commenters stated that the EPA's assertions assume future growth based on past actions, but the EPA has provided no support for such a projection n or does EPA explain why it believes the planned infrastructure investments it cites will pr oceed as scheduled when studies have questioned their completion in light of siting and permitting issues. Commenters further stated that the EPA does not explain how the 21 percent re gional average it cites is representative of the capacity increase possible for individual regions. According to the commenters, the Proposed Rule acknowledges the importance of adequate region al capacity, but of the four regions considered here, three had increases of less than 1 0 percent and the remaining region had an increase of over 60 percent (citing GHG Abatement M easures TSD at 3-17 to 3-19). Commenters asserted that the EPA should explain how a 21 percent increase is representative for all 4 regions.

Commenters stated that the EPA's failure to conside r plant-level infrastructure constraints led the Agency to overestimate available NGCC capacity. As an example, commenters offered that the Proposed Rule determined Arkansas' available NGCC c apacity based on nameplate megawatts of a number of existing merchant plants that operated at a very low capacity factor in 2012 due in large part to transmission constraints. Commenters added that the EPA similarly presumes redispatch can occur in the New England, Arizona, and Nevada while according to NERC "current and planned pipeline infrastructures in [these area s] are inadequate for handling increased natural gas demand due to the CPP". Commenters concluded th at had EPA considered plant-level infrastructure constraints concurrently with its de termination of NGCC capacity and the appropriate NGCC re-dispatch capacity factor, the a ssumed capacity from a number of plants would necessarily have been decreased.

Commenters stated that the EPA should analyze plant -level infrastructure constraints during peak periods. Noting that the EPA cites to a 60 per cent average national capacity factor during peak periods (15 to 20 percent above the average an nual capacity factor) as demonstrating that adequate infrastructure exists to support a 70 perc ent re-dispatch capacity factor, Commenters asserted that the EPA provides no explanation for h ow a 60 percent average peak capacity factor supports a 70 percent re-dispatch capacity factor, and the national average peak capacity factor does not inform a plant-level infrastructure constr aint analysis. Commenters added that the EPA's argument that plant-level infrastructure cons traints at peak times can be overcome through emissions averaging is also unavailing because coal plants, the generation source to which EPA's averaging suggestion likely refers, cannot serve as peaking plants, and many states are prohibited from operating coal plants during the peak summer s eason because doing so would make compliance impossible with averaging.

Regional analysis312

Commenters stated the EPA's IPM analysis does not t ake into account region-specific technical issues. Commenters stated that, in particular, give n the remote location of Arizona's existing coal units, it is anticipated that shutdown of these uni ts may result in issues surrounding voltage and system stability. Commenters stated that, in the ab sence of a detailed transmission analysis, given Arizona's demonstrated lack of flexibility, E PA would be unable to assess what units are necessary for the reliability of the electric grid.

Commenters stated the EPA failed to recognize and a nalyze unique circumstances the natural gas supply infrastructure. Commenters stated that, alth ough the infrastructure has previously been adequate to support peaks demands and for extended periods of time, the system is not adequate
to continue to do so into the future. Commenters st ated the EPA failed to consider the differences in the gas supply infrastructure across the county and noted that the natural gas infrastructure is vastly different in the West compared to the easter n infrastructure, as illustrated in Figure 6. Commenters added that Figure 6 is a map of the U.S. showing interstate and intrastate pipelines, along with the general direction of gas flow throug hout the U.S.

Commenters stated the EPA must perform additional e valuation, in light of several factors and in context of the generation system operating as a who le, and make the needed adjustments to the proposal prior to finalizing its rule. Commenters s tated the EPA has not demonstrated that operating all combined cycle generation at 70% capa city factor, and leaving other fuel types to respond to intermittent and peak demand, will not s everely and adversely affect electric reliability or reserve capacity needs. Commenters s tated the EPA must also account for the loss of hydroelectric generation during prolonged drough ts or due to the elimination of dams for ecological reasons.

Rerun IPM

Commenters stated the EPA must model the proposed r ule in its entirety with NGCCs operating at a 70% capacity factor. In fact, commenters state d the IPM runs conducted by EPA only indicated 50% utilization of NGCC capacity (includi ng new units). In performing this analysis, commenters stated EPA assumed that electricity coul d flow unconstrained within the major generation regions. Therefore, commenters added, EP A did not conduct modeling that adequately assesses electric reliability impacts.

Storage capacity analysis

Commenters stated that the EPA also should analyze whether gas storage capacity can support the level of re-dispatch that Building Block 2 requ ires because gas storage plays an important role in balancing pipeline flows, serving as a redu ndancy to enhance reliability and offsetting price volatility. Commenters alleged that the EPA h as not analyzed the consequences of redispatch on storage capacity. According to the comm enters, the IPM model does consider storage capacity, but the EPA's reliance on the IPM is restricted to the IPM's cost impact analyses (79 Fed. Reg. 34,864-65). Commenters concl uded that EPA cannot therefore rely on the IPM to support its re-dispatch feasibility analysis

.

Commenters recommended that, in the final rule, the EPA analysis fully consider the availability of storage and associated interstate delivery capac ity and include additional stakeholder313

perspectives and concerns related to operation of t he bulk power system with increased reliance on natural gas. Commenters stated, MISO has begun s tudying the regional issues of natural gas and electric system interdependency and may be in a better position to assess potential constraints and impacts to reliability. Commenters also noted that the ability of the nation's natural gas infrastructure (pipeline, storage, mark ets) to deliver dramatically increased amounts of natural gas where and when it is needed by elect ric generators is also an issue of serious concern for electric regulators including the FERC and the NERC.

Commenters stated that, while fuel can be and routi nely is stockpiled at coal plants, natural gas units are dependent on pipelines which are subject to disruptions through such foreseeable
circumstances as extreme cold. Commenters stated th is vulnerability makes the undemonstrated likelihood that EPA's assumptions are correct even more parlous.

Comment 19: Commenters suggested state-by-state analyses are n eeded and provided some state-specific comments.

Response 19: The EPA disagrees. The Agency believes the analyses for the final rule are adequate, and the average prices for infrastructure used in the analyses are appropriate for the purpose, though we understand that individual proje cts exhibit a wide range of cost. Additional analyses may be considered by implementing agencies . In response to additional analysis and many comments, we have modified the proposal and RI A; the establishment of CO2 emission reduction standards is regionally based. The 111(d) final rule requires that states develop plans

that establish emission standards for affected EGUs . We are providing states with substantial flexibility as to how they structure those plans to achieve the 111(d) requirements. The flexibility includes, for example, the choice of approaches, tr ading, time to develop plans, additional time before the start of the interim performance period (postponed from 2020 until 2022), and the ability to shift emission rate achievement between performance periods. Neither the Building Blocks nor the IPM analyses are prescriptive, and s tates may consider local circumstances as they develop their plans, including system reliabil ity, fuel diversity, other regulatory requirements and infrastructure. See sections V.A, V.B, V.D, VIII.A, VIII.C and VIII.G of the final rule preamble of the CPP, Chapter 3 of the GH G Mitigation Measures TSD for the CPP Final Rule supporting the final CPP and the Regulat ory Impact Analysis of the final CPP.

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

State-by-state analyses

Commenters suggested the EPA should analyze what in dividual pipeline systems are prepared to support in order for each state to meet a 70% utili zation goal. Commenters suggested the EPA should account for state-specific electric system o peration and infrastructure constraints that limit the feasibility of relying on Building Block 2 as a major compliance strategy.

Commenters cautioned the EPA regarding the limits o f relying on nationwide summary statistics and past performance to draw conclusions about the ability to support the increased utilization of NGCCs with underutilized pipeline capacity. Comment ers stated that a more intensive314

examination of regional natural gas markets and ant icipated changes in pipeline flows over the course of implementation of the Clean Power Plan wo uld be necessary to analyze the amount of off-peak pipeline capacity that actually would be a vailable to support the increased utilization of
NGCCs. Commenters stated this also should include a n examination of pipeline connections with individual generators, because generators migh t be affected by localized capacity constraints and utilization patterns even if capaci ty was available on the broader regional level. Commenters stated the Energy Information Administra tion regularly examines changes in interregional pipeline capacity (i.e., the ability to tr ansport natural gas between regions), although this does not include an examination of the availability of capacity within a region to serve a particular pipeline delivery point.

Commenters stated the EPA should develop building b lock 2 based on what has already been achieved by the NGCCs in each state, rather than wh at has been achieved at the regional level. Commenters stated the EPA should adopt a bottom-up approach, letting individual states implement building block 2 using unit-specific info rmation from within their respective states. Commenters stated this would allow the building blo ck to accurately reflect both what a state has accomplished to date and what it can actually achie ve in the future. Commenters stated this approach also recognizes what EPA has already ackno wledged in its June 2014 proposal: that each state is starting in a different place and the refore must have a unique reduction goal. Commenters stated a state-specific, bottom-up appro ach would recognize states that took early action, like Wisconsin, have less they can reasonab ly achieve when compared to those that have done little. Commenters stated the EPA must prove t hat the various constraints will not limit the capacity factor applied in building block 2 for the vast majority of NGCCs in the country; i.e., the limit must either be set specifically for each state, or be set nationally based on the achievable capacity factor for the most constrained state.

State- and area- specific comments

Commenters expressed concern that, while Arkansas r eceives almost zero credit for nuclear and hydroelectric power plants that produce no greenhou se gas emissions, the proposal assumes Arkansas's natural gas-fired power plants can opera te at 70 percent capacity. Commenters stated this significant increase in electricity generation from natural gas-fired power plants is unprecedented in Arkansas, and noted serious reserv ations whether it can be accomplished without expensive upgrades to pipeline and electric ity transmission infrastructure.

Commenters stated the EPA should re-formulate its a nalysis of natural gas availability to account for potential supply constraints in Indiana, and EP A should include in its analysis a robust model
of the effect a nationwide increase in the demand f or natural gas will have on pipeline capacity in
the short-term. Commenters stated the EPA assumes t hat necessary gas pipeline infrastructure can be added in time to support reliable operation of gas units at higher capacity factors, but did no analysis of the current supply constraints for e xisting NGCC units. Commenters stated the EPA made allowances in the computation of state goa ls for shortfalls in fossil fuel supplies, but only for states where the sum of coal, oil, and nat ural gas resources fell short of the natural gas required to sustain a 70 percent capacity factor at existing NGCC plants. Commenters stated that coal, oil, and natural gas are dis-analogous for th e purpose of estimating resource availability, insofar as a state may possess large supplies of on e and very limited supplies of another.315

Commenters noted that Indiana produced 826.8 trilli on Btus of coal in 2012, but only 8.9 trillion Btus of natural gas that year.

Commenters questioned the EPA's estimate of the cap ital costs of constructing new pipeline laterals of $1 million per mile of pipeline built ( 79 FR 34875). Commenters stated that the Columbia Pipeline Group just announced plans for th e construction of a 160 mile natural gas pipeline to transport natural gas from Ohio and Wes t Virginia to North Carolina, at a cost of $10.9 million per mile. Commenters also referred to Atlantic Coast Pipeline, LLC, which has proposed a 550-mile pipeline that will run from Wes t Virginia through Virginia, then south through North Carolina at an expected cost of $9.1 million per mile.

Commenters stated the magnitude of increased utiliz ation of NGCC in 2020 is based on 2012 generation, which is in turn based on 2012 demand; however, the actual amount of NGCC capacity available in 2020 will depend on 2020 dema nd and EPA's current approach does not account for any load changes that will occur betwee n 2012 and 2020. Commenters stated NV Energy is projecting more than a 10% increase in lo ad between 2012 and 2020 on its system. Commenters stated EPA's failure to take this growth into account underestimates the demand conditions that the utility will experience in 2020

.
Commenters stated that, while the EPA projects the NGCC units to operate at levels very similar to those observed in 2012 under both the regional a nd state compliance options that is unlikely, given the historically low price of natural gas in 2012. Commenters stated that, while IPM projects 6 of Ohio's 26 existing NGCC units operati ng at above 70% capacity and all 3 units at the Dresden Energy Facility are projected at 86% ca pacity in 2025, whether these units can receive the natural gas to operate at this level is not a factor that is considered by the IPM
model.

Commenters stated that, given the increased demand upon natural gas supplies that will result from this proposed rule, there is uncertainty as to whether sufficient pipeline capacity and infrastructure to ensure an uninterrupted supply of electricity will be available. Commenters stated that more evaluation of actual resource capa city and resource adequacy in the Western
Interconnection is needed to understand what effect s the proposed rule will have on natural gas supply and delivery.

Commenters recommended that EPA allow a reasonable time period for entities such as WECC and NERC to ascertain how the proposal impacts reso urce adequacy and reliability in California and other western states to determine if the assump tions in Building Block 2 should be adjusted. Commenters noted that, while the coal-fired generat ing units in Nevada would be replaced by NGCC units, it is not clear whether the increase in NGCC use would be considered replacement energy for coal-fired EGUs in Nevada or, in part, a s replacement energy for LADWP's share of Navajo Generating Station, which is located in Ariz ona. Commenters noted the WECC has begun a phased study process that will continue thr oughout 2015 to provide an analysis of potential impacts of EPA's proposed Clean Power Pla n to the Western electric generation and transmission industry. Commenters stated that preli minary WECC results indicate that a state's decisions made regarding Clean Power Plan complianc e can "drastically impact grid operations, system resiliency, and potentially, compliance oppo rtunities for a neighboring state" (EPA Clean Power Plan Phase 1 - Preliminary Technical Report, WECC Staff, September 19,316

2014). Commenters stated NERC has begun a similar phased study process and came to a
similar conclusion that more studies would be neede d to understand the full ramifications of the proposal on electric reliability. Commenters urged EPA to work with NERC, WECC, states and regional transmission organizations to adopt a more realistic view of the potential for re-dispatch that considers stranded costs and the reliability o f the grid, and to adopt a more reasonable phased-in time table for re-dispatch that does not threaten the reliability of the regional grid nor impose undue stranded costs on states' electric rat epayers. Commenters stated this review would determine whether adjustments to a state's goal are appropriate.

Commenters requested the EPA examine the impacts of these transmission systems constraints and address how they impact the prospect of achievi ng 70% utilization within the time required. Commenters stated that, with respect to the transmi ssion systems that deliver the electricity from the EGUs, the RTOs have operational control over al l federal-jurisdictional transmission facilities. Commenters stated that, if there are co nstraints on the transmission system controlled by PJM that would be exacerbated if AMP's AFEC NGCC were dispatched, PJM will not dispatch or will curtail the output of AFEC. Commen ters stated that, whether EGUs run may not be limited to price signals, but rather, physical c onstraints on the transmission system and, of course, natural gas delivery constraints that are b eyond either the EGU or the state's control. Commenters stated that, given the myriad physical a nd market constraints that apply to EGUs, the 70% percent utilization rate for natural gas pl ants assumed in Building Block 2 is unrealistic within the timeframes envisioned by the rule propos al.

Commenters stated that individual NGCC units may no t be able to achieve higher utilization rates due to the particular configuration of the un it. Commenters explained, for example, that South Carolina's Columbia Energy Center facility, w hich supplies steam and power directly to its onsite customer while selling the remainder of its output as electricity to the electric grid, currently it is only contracted for less than one h alf of the firm gas required to run at a 70% capacity factor. Commenters stated this facility is managed as a merchant facility that, in part, sells power out of state; consequently, it is very possible that even if these units are able to obtai n enough gas to increase their capacity factor signif icantly, they would not replace generation from any of South Carolina's coal units to the levels as sumed by EPA under building block two.

Commenters stated it is not clear whether or not th e infrastructure will be in place for South Carolina to increase the use of natural gas to meet the entire emission reduction goal. Commenters stated that it appears the EPA measured natural gas availability by only factoring in natural gas units available at the time of the base line.

Commenters stated that, for South Dakota, the assum ptions that existing NGCC units can increase generation to achieve a 70% capacity facto r and that the increase in NGCC generation will displace generation from in-state steam units are not practical or reasonable or based on sound analyses. Commenters stated the EPA did not a nalyze several critical unit, state and interstate specific information including but not l imited to: grid stability and reliability, NERC critical infrastructure protection, long term power supply contracts, contractual relationships between NGCC units and steam units including units owned by multiple parties, gas and electric transmission capacity, electric transmission rights , gas and electric transmission equipment upgrades and/or changes, natural gas availability, natural gas supply contracts, dependable unit capacity, and units dispatched by different RTOs. C ommenters recommended the EPA re-317

analyze Building Block 2 by involving plant owners, RTOs, Balancing Authorities, FERC, NERC, WECC, states and other stakeholders to determ ine the feasibility and limitations of Building Block 2 for each state including considera tion of the interstate relationships between generation and loads. Commenters stated the basis o f EPA's analysis regarding the feasibility of implementing Building Block 2 is not detailed, accu rate or reasonable.

Commenters suggested that additional analysis is ne eded. Commenters stated that although NGCC units are designed to be dispatchable and may be able to operate as priority base load generation, these units are most often used to serv e peak and intermediate load, due to their ability to ramp up and down quickly to meet dynamic demand changes over time. Commenters
described the two TVA NGCC facilities located in Te nnessee, and noted that in 2012 the two operated at an average of 47 percent capacity accor ding to the EPA's data. Commenters indicated that like most NGCC plants across the nation, NGCC plants in Tennessee fulfill a load-following role, but the proposed BSER would require a fundame ntal shift to base load generation for these units. According to the commenters, it is unclear w hether, and to what extent, this is feasible. Commenters cited the TVA's comments as stating that most of its NGCC facilities appear capable of running at a 70 percent capacity factor with sufficient maintenance; however, the existing affected coal-fired EGUs may not be able t o provide the flexible operational capabilities that NGCC units are currently providing. Commenters stated that in other words, while the NGCC units may, theoretically, be able to do the jo b of coal units, TVA, itself, is uncertain as to whether the coal units can do the job of the NGCC u nits and that is what EPA's proposed BSER requires. Commenters asserted that fundamentally sh ifting the way TVA operates and dispatches
NGCC and coal affected units could result in unecon omic dispatch and higher cost for TVA
ratepayers.

Commenters stated that, prior to finalizing the rul e, FERC and EPA must work with each of the Regional Authorities to ensure that the 70% utiliza tion for that state is achievable. Commenters asserted that, for states in which the emissions ra te goal is so strongly tied to NGCC unit dispatching, it is critical that FERC ensure that t he rule will not have any detrimental effect on grid reliability and electricity transmission prior to rule finalization. Commenters expressed concern with the following statement made on page 3 4835 of the EPA's proposal: "Once the final goals have been promulgated, a state would no longer have an opportunity to request that the EPA adjust its CO2 goal." Commenters stated the EPA's rigid application of the BSER building blocks across the nation is inappropriate given the unique unit fuel mix/resource availability in each state. Commenters noted that, for the state of Texas, BSER Block 2 accounts for approximately 45% of the EPA-assessed emissions reduction requirements and stated that, in this circumstance, if no solution could be obtained by FERC for achieving the Building Block 2 NGCC utilization goal while maintaining electricity reliability and affordability, Texas would be placed in the difficult position of finding emissio ns rate improvements that would account for a significant portion of the required emissions reduc tion.

Commenters stated the EPA must adequately account f or potential losses of current generation
sources. Commenters stated this includes the retire ment of nuclear generation. Currently, commenters stated, significant nuclear generation w ill be retired in 2030 and 2033 in Wisconsin.
Commenters stated the EPA also must consider that s ome NGCC capacity has been built to meet specific load profiles and must remain available fo r this purpose; for example, Wisconsin's Port Washington NGCC facility was built to replace coal- capacity and meet large, sudden demand318

changes caused by electric arc metal furnaces in th e area. Commenters stated it is important facts and nuances about the EGU fleet, such as this one, that EPA's proposal fails to recognize and calls into question the thoroughness and basis of E PA's rule.

Commenters stated the EPA did not adequately assess natural gas pipeline capacity and storage. Commenters noted that natural gas storage capacity became overextended in Wisconsin in 2012 and 2013, with resulting price increases and supply shortages, and stated that dispatch of NGCC to a 70% capacity factor is estimated to increase W isconsin's natural gas consumption by 12.6%.
Commenters stated the EPA has not shown that the su pply and storage infrastructure for natural gas would be available to support such an increase in consumption. Commenters provided the following additional points.

• First, prior to the release of EPA's proposal, the Midwest Independent System Operator (MISO) identified constraints that need to be addressed in order to maintain natural gas supply for electric generation in the region; these constraints do not appear to have been considered by EPA (Novem ber 2013, MISO Summary Document Phase III Gas Infrastructure Analysis, Mid west Independent System Operator). In its own analysis, EPA projects only a 4 to 8% increase in pipeline capacity serving Wisconsin in the foreseeable futur e; this is clearly at odds with the 12.4% anticipated demand increase. In addition, in assessing pipeline capacity, EPA did not consider that the existing in frastructure supporting simple cycle turbines and new NGCC units will have to be u pgraded in order to replace the load and peaking capacity of the existing NGCC capacity.

• Second, storage capacity for natural gas has remain ed relatively flat. There are some additions to storage capacity coming online, b ut these are relatively small in the context of total system capacity and also are l ocated far from Wisconsin. Adding storage capacity is a costly endeavor which is dependent on geological formations and access; it cannot simply be added as needed. In addition, Wisconsin has no potential natural gas storage capa city because the appropriate geology does not exist in the state. EPA does not c onsider these factors in its proposal.

• Finally, there are fuel availability factors that a re not directly related to physical infrastructure, but will be driven by a market for fixed-load support. EPA must consider that utilities may have to procure long-te rm contracts for storage capacity in order to ensure a reliable fuel supply. At this time, it is unclear how these factors will affect electric reliability; how ever, there certainly will be a cost impact. One Wisconsin utility currently in the plan ning stages for a new NGCC has relayed that reliable transportation, storage a nd no-notice service could cost $12 million per year for a 500 MW plant. In additio n, a new or upgraded connection would cost approximately $2-3 million do llars and the lateral feed $2.5 million per mile.319

Comment 20: Commenters suggested additional analysis is needed , such as consideration of sustainability and maintenance.

Response 20: The EPA disagrees that we inadequately considered system issues in development of the 111(d) final rule. Additional analysis may be considered by implementing authorities. In response to additional analysis and many comments, we have modified the proposal and RIA;
the establishment of CO 2 emission reduction standards is regionally based. The 111(d) final rule requires that states develop plans that establish e mission standards for affected EGUs. We are providing states with substantial flexibility as to how they structure those plans to achieve the 111(d) requirements. The flexibility includes, for example, the choice of approaches, trading, time to develop plans, additional time before the s tart of the interim performance period (postponed from 2020 until 2022), and the ability t o shift emission rate achievement between performance periods. Neither the Building Blocks no r the IPM analyses are prescriptive, and states may consider local circumstances as they dev elop their plans, including system reliability, fuel diversity, other regulatory requirements and i nfrastructure. See sections V.A, V.B, V.D, VIII.A, VIII.C and VIII.G of the final rule preambl e of the CPP and Chapter 3 of the GHG Mitigation Measures TSD for the CPP Final Rule supp orting the final CPP.

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

Commenters suggested a longer term analysis is need ed, including consideration of sustainability
and maintenance concerns. Commenters recommended th e EPA reconsider the level included within proposed BSER from building block 2 after an alyzing longer term performance for a greater percentage of the NGCC fleet as well as the need for maintenance and other operational considerations relevant to a base load power genera tion source. Commenters stated the EPA's conclusions as to the technical feasibility of incr easing NGCC capacity factors to 70 percent consistently over the interim goal period of 2020-2 029 (79 FR 34862) is not adequately supported by information in the docket, including t he EIA and NERC data that EPA uses in its analysis. Commenters referenced an October 2014 EPR I report and stated that, while the data utilized by EPA suggests that some NGCC facilities with adequate fuel supply and infrastructure have demonstrated the ability to get up to a 70 per cent capacity factor over shorter periods of time (annually and/or monthly), whether that level can be achieved and maintained consistently by a large percentage of the fleet over the longer term is not demonstrated through the information EPA includes to support the proposed gu idelines.

Commenters stated the assumption that an NGCC unit can sustain a 65 percent, 70 percent, or 75 percent utilization rate over a decade based on dat a that otherwise suggests highly variable monthly averages, and without consideration of main tenance and down-time for operational constraints, is not reasonable. Commenters stated i t is not supported by the actual demonstrated
utilization of the national fleet of NGCC units whe n market conditions would favor their use more so than other generation resources. Commenters referenced a September 2014 EIA report and noted that, during the period of the 2014 Polar Vortex, a time when natural gas supplies had to be curtailed and/or redirected from many sources , the capacity factor reported across the national fleet during that period was much lower th an 64.5 percent at 44.8 percent in January 2014 and 41.2 percent the following month.320

Commenters stated that if, as EPA assumes, the incr eased utilization of NGCCs needed for the states to achieve the proposed goals could be accom plished without increasing such units' utilization rates during peak hours, then it is lik ely that significant compliance can be achieved via increased utilization of existing natural gas i nfrastructure. Commenters expressed concern that, while there is less demand for interstate nat ural gas pipeline capacity during off-peak months, pipeline operators typically schedule maint enance during these periods in order to minimize the effect on firm transportation customer s. Commenters stated that, consequently, the amount of available pipeline capacity may be reduce d because the pipeline operator has temporarily withdrawn facilities from service to pe rform maintenance. Commenters stated that, while pipeline operators are careful not to affect the ability to meet the needs of firm shippers when maintenance is being performed, the capacity a vailable for interruptible shippers may be
limited.

Commenters stated that the shift in natural gas pip eline flows attributable to the shale gas revolution may create additional underutilized pipe line capacity that could be used to serve gasfired generators operating at increased capacity fa ctors. Commenters stated that, in some cases, the abundance of natural gas and the shift in the l ocation of natural gas relative to consuming markets has resulted in diminished capacity utiliza tion along some pipeline corridors. Commenters added that, because the flow of natural gas has increased along other pipeline corridors, there will be less underutilized pipelin e capacity available along those corridors to support the increased utilization of NGCCs. Comment ers noted that the initiation of liquefied natural gas exports and the demand for natural gas to supply new and re-opened petrochemical facilities along the Gulf of Mexico will result in greater year-round utilization of existing pipeline capacity in that region. Commenters stated that, since many pipelines were designed to deliver sufficient natural gas to meet the LDCs' pe ak day winter heating loads, for much of the year some portion of the LDCs' entitlement to firm service3 is underutilized and this pipeline capacity can be re-sold by the LDC in a secondary m arket for pipeline capacity. Commenters stated that during off-peak months it is likely tha t pipeline capacity will be available in the secondary market to deliver the natural gas that wi ll be needed to increase the utilization of
NGCCs.

Commenters stated that it is important to note that under the open access requirements prescribed by the Federal Energy Regulatory Commission (FERC), interstate natural gas pipeline capacity must be available on a not unduly discriminatory ba sis. Commenters stated that priority for access to pipeline capacity is dictated by the qual ity of service that a shipper chooses to subscribe (e.g., firm transportation versus interruptible tra nsportation). Commenters stated that, as a result, the fact that a shipper wishes to transport natural gas to an NGCC for purposes of compliance
with the Clean Power Plan would not cause its trans portation to take priority over another shipper wishing to transport natural gas, to be use d for some other purpose, if that other shipper subscribed to higher priority pipeline service.

Comment 21: Commenters stated the EPA should use modeling to d etermine how NGCC generation offsets other generation throughout the electric supply system.321

Response 21: The EPA disagrees that our modeling is inadequate. We believe the modeling we performed for the 111(d) final rule appropriate. In response to additional analysis and many comments, we have modified the proposal and RIA;the establishment of CO2 emission reduction standards is regionally based. The 111(d) final rul e requires that states develop plans that

establish emission standards for affected EGUs. We are providing states with substantial flexibility as to how they structure those plans to achieve the 111(d) requirements. The flexibility includes, for example, the choice of approaches, tr ading, time to develop plans, additional time before the start of the interim performance period (postponed from 2020 until 2022), and the ability to shift emission rate achievement between performance periods. Neither the Building Blocks nor the IPM analyses are prescriptive, and s tates may consider local circumstances as they develop their plans, including system reliabil ity, fuel diversity, other regulatory requirements and infrastructure. See sections V.A, V.B, V.D, VIII.A, VIII.C and VIII.G of the final rule preamble of the CPP, Chapter 3 of the GH G Mitigation Measures TSD for the CPP Final Rule supporting the final CPP and the Regulat ory Impact Analysis of the final CPP.

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

Commenters stated this modeling will likely show th at increasing NGCC generation will offset existing and new renewable energy, indicating that the proposed RE requirement is neither practical nor cost-effective in operating the grid. Commenters stated that, at a minimum, EPA should assume that additional NGCC generation will offset renewable energy capacity before existing coal-fired generation and solid fuel bioma ss-fired generation. Commenters stated the EPA cannot assume that NGCC generation will offset coal-fired generation, as this is not how the electric supply grid functions in reality; inst ead, the EPA must assume that additional NGCC generation will offset a combination of coal-fired generation, renewable energy, and simple cycle combustion turbine operation. Commenters stated tha t, as a part of this modeling, the EPA must establish a floor for operation of existing coal-fi red EGUs that prevents degradation of their heat

rates.

Comment 22: Some commenters raised issues regarding natural gas -electric coordination.

Response 22: The EPA disagrees that we have inadequately conside red natural gas-electric coordination. We have consulted extensively with s takeholders. Additional analysis and consultation may be performed by implementing autho rities. In response to additional analysis and many comments, we have modified the proposal an d RIA; the establishment of CO2 emission reduction standards is regionally based. T he 111(d) final rule requires that states develop plans that establish emission standards for affected EGUs. We are providing states with substantial flexibility as to how they structure th ose plans to achieve the 111(d) requirements. The flexibility includes, for example, the choice o f approaches, trading, time to develop plans, additional time before the start of the interim per formance period (postponed from 2020 until 2022), and the ability to shift emission rate achie vement between performance periods. Neither the Building Blocks nor the IPM analyses are prescr iptive, and states may consider local circumstances as they develop their plans, includin g system reliability, extreme weather, fuel322

diversity, other regulatory requirements and infras tructure. See sections V.A, V.B, V.D, VIII.A, VIII.C and VIII.G of the final rule preamble of the CPP and Chapter 3 of the GHG Mitigation Measures TSD for the CPP Final Rule supporting the final CPP.

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

Scheduling protocols

Commenters stated that inconsistencies in schedulin g protocols between the gas and electric industries make it challenging for gas-fueled gener ators to purchase gas supplies and schedule pipeline capacity and expressed concern that such p rocesses be in place in time to adequately handle the next weather-driven electricity surge li ke the one we saw on January 7, 2014.

Commenters (cited a March 20, 2014 FERC Scheduling Coordination Order and) stated that stated the FERC has recognized that, as our Nation' s dependence on natural gas generation continues to rise, the differences between regional ly coordinated electricity market scheduling timelines and the nationwide gas scheduling timelin e are increasingly likely to impede reliability across the electric grid. Commenters noted that thr ee things make managing fuel procurement and price risks challenging for generators and tran smission operators: (1) the difference in operating days used by the natural gas and electric industries; (2) the fact that the timeframe for nominating natural gas pipeline transportation serv ice is not synchronized with the timeframe during which generators receive confirmation of the ir bids in the day-ahead electric markets; and (3) the fact that it is not economic for electric g enerators to pay for firm pipeline capacity. Commenters stated FERC has determined that generato rs need the flexibility of the gas scheduling system to improve in order to accommodat e their need to revise nominations in response to weather events or other operational nee ds. Commenters stated that FERC has promulgated a rulemaking to investigate mechanisms to facilitate the use of increased amounts of gas generation to serve load. Commenters stated the rulemaking responds to the concerns of ISOs and RTOs about the potential reliability effec ts on their systems should gas-fired generators have trouble acquiring natural gas or experience cu rtailment of natural gas supplies, particularly during periods of extreme weather, and that steps m ust be taken to ensure that ever-increasing amounts of gas generation can be used to serve load reliably.

Coordination

Commenters urged the EPA to work with federal and s tate electric power regulators to ensure that adequate gas pipeline capacity is available to meet the need for the expanded dispatch of NGCC and other gas-fired EGUs.

Commenters stated the EPA should address issues rel ated to natural gas infrastructure and electric-gas coordination. Commenters stated the EP A failed to consider factors such as age and design of a unit, hourly limitations in existing op erating permits, and the ability of existing natural gas infrastructure to serve additional capa city at the NGCC units. Commenters stated that, in setting the 70 percent re-dispatch element of Building Block 2 EPA failed to adequately consider the potential impact to the gas pipeline i nfrastructure and electric transmission systems of dramatically increasing the dispatch of electric ity produced at the NGCC plant, particularly on the short timeframes required in the proposed Guide lines. Commenters stated that, for the most323

part, coal-fired and NGCC plants are not co-located in Indiana, thus there is no guarantee that adequate transmission currently exists to send the same electric load from an NGCC plant as that being serviced by baseload coal-fired units. Commen ters expressed concern that the EPA assumes that the necessary gas pipeline infrastruct ure can be added in the short span of 3-4 years to support reliable operation of NGCC plants at hig her sustained capacities and stated this is particularly problematic given the "front loading" of Block 2 in meeting the interim targets.

Commenters encouraged the EPA to work with natural gas suppliers, affected utilities, and ISO/RTOs when establishing a reasonable target in b uilding block 2 in the final rule. Commenters expressed concern about the following is sues:

• Availability of sufficient natural gas pipeline cap acity to accommodate this increase in utilization and being able to obtain fi rm commitments from natural gas suppliers, especially during the winter months when many residential and commercial buildings use natural gas for heating pu rposes. Commenters noted the dispatch order for natural gas pipelines prioritize s residential heating, then industry usage, and electricity generation is typic ally last; thus, if there is a pipeline capacity shortage, electricity generation is usually the first to be cut off.

• ISOs/RTOs have also expressed concern that increasi ng the utilization of NGCC units to 70% of their capacity could result in unec onomic dispatch, which could result in conflicts with federal energy regulations

.

• Electricity transmission constraints could occur as a result of increasing output from units not originally intended to generate elec tricity at these levels.

Commenters stated that the EPA recognizes some of t he challenges to increasing NGCC utilization, primarily infrastructure and system co nsiderations, but does not analyze the impact of those challenges or take them into account when det ermining an achievable level for the nation's NGCC fleet utilization rate or recognize the import ance of these constraints. Commenters indicated that solutions to some of these challenge s depend on actions taken by other sectors, injecting a level of uncertainty into any discussio n about fuel availability and deliverability.
Commenters asserted that the EPA should take into a ccount the work being done by both the electric and gas industries and recognize that the challenges presented by gas-electric coordination are greater than the Agency assumed wh en calculating potential natural gas utilization rates, and that natural gas consumption patterns of other industries should also be factored into any determination of "reasonable" or achievable levels of NGCC utilization.
Commenters noted that the two industries have diffe rent regulatory schemes, different operational requirements and different processes fo r building infrastructure, and that these differences are more acutely seen in areas with RTO /ISO markets. Commenters pointed out that these issues are being discussed at both FERC and a t the regional level.

Commenters supported a comprehensive and independen t analysis of the impacts of the proposed rules on the reliability of the nation's electric g rid, referencing Supplemental Responsive Comments of Southwest Power Pool, Inc. Exhibit A. C ase No. EW-2012-0065. October 13, 2014. Commenters stated the proposed rules will cha nge the dispatch of generating units by324

replacing economic generating resources with less e conomic resources which could affect the reliability of the national electric grid.

Commenters stated that generators that supply their NGCCs using strictly interruptible pipeline capacity are exposed to supply cuts during times of peak demand, not because of inadequate supply but because all firm customers are utilizing their capacity rather than releasing it for use by non-firm shippers. Commenters noted that local d istribution companies (LDCs) also offer various levels of transportation services to genera tors. Commenters indicated that units that source gas from intrastate pipelines or that are lo cated behind LDC city gates could potentially be exposed to supply constraints due to inadequate pipeline capacity. Commenters asserted that while the EPA assumes those constraints will have p lenty of time to be addressed, this assumption may be invalid and from the standpoint o f reliably serving the public's need for electricity is risky. Commenters stated that the si ze and location of potential capacity shortages is not known and the economic mechanism for incenting pipeline expansion to those plants in the changing natural gas market is not clear.

Commenters stated that the interaction between elec tric generation, wholesale electricity markets and the natural gas and pipeline industries is much more complex than described in the proposed rule. Commenters indicated that the potential for r e-dispatch between existing coal-fired and NGCC units is largely a factor of whether certain s ystem constraints have been addressed, and that making the appropriate infrastructure and syst em upgrades that will be necessary to achieve increased utilization of existing NGCC units in cer tain areas will take longer than EPA's proposed guidelines currently allow. Commenters not ed that TVA is participating in a DOEfunded study of gas supply adequacy being performed by the Eastern Interconnect Planning Collaborative (EIPC) that is expected to identify a reas where pipeline capacity needs to be expanded, develop contracting mechanisms to incent those expansions, and improve gas-electric coordination to eliminate scheduling issues. Commen ters stated that the final report is expected to be submitted to DOE in June 2015 and will provid e analyses that should be helpful in determining how feasible EPA's assumed 70% capacity factor is.

Commenters stated the EPA, in its final rule, shoul d examine the impacts of improved gas electric coordination practices in implementing BB2 . Commenters stated this issue relates to a fundamental disconnect between how gas pipelines sc hedule and nominate supplies for delivery customers and how generators schedule available cap acity to the wholesale electric markets.
Commenters stated this disconnect between the sched uling functions of the two industries has also contributed to supply shortfalls to electric g enerators during periods of increased system demand. Commenters stated the FERC has an ongoing p roceeding to address this issue and is expected to make some general recommendations for f urther consideration in the near future.
Commenters stated the individual RTO/ISOs have unde rtaken initiatives to resolve these interindustry issues. Commenters stated the EPA should c onsider whether it is prudent to be placing the burden on states to implement BB2 while the gas and electric generation industries are grappling with the need to improve market design is sues between the two industries.

Commenters suggested the EPA consult with FERC befo re trying to redefine the entirety of the electric market/dispatch. Commenters stated the ele ctricity market can be volatile, and massive changes in the capacity and distribution of electri city could have major implications on the market. By incorporating FERC into the rule develop ment process, Commenters stated the EPA325

will have a better technical understanding of the i mportant subtleties associated with electricity dispatch and appropriate timeframes for changes to occur.

Commenters stated that the EPA Proposal relies heav ily on the ability to rapidly increase the amount of natural gas used to generate electricity, but these gas/electric coordination issues pose significant barriers to such an increase. Commenter s added that there remains considerable uncertainty as to whether, and if so, how, FERC may continue to address these issues.
Commenters concluded that the EPA should re-examine and revise the assumptions it has made with respect to related provisions in the Proposed Rule, particularly in its construction of building block 2. Commenters stated that there are concerns surrounding the synchronization of electricity and natural gas markets as supplies of power and natural gas are secured on a different
time basis. Commenters indicated that this disconne ct may prevent facilities committed to provide electric power from securing the gas suppli es they need to operate, or require them to pay higher prices for longer time periods. Commente rs added that this issue is further complicated by the interdependent nature of the nat ural gas and electric generation industries - as more power generation comes from gas, the impact of simultaneous peak electricity demand and peak consumer heating demands converge, creating a scenario where gas deliverability capability can become a bottleneck. Commenters pointed out thi s is particularly true in the winter when shorter days and colder temperatures increase deman ds for heating and lighting; while adequate supplies of natural gas exist, delivering at the ra te needed during peaks could be constrained.
Commenters stated that additional coordination betw een these two industries is needed, in addition to fuel diversity, which will reduce the i nterdependence risk.

Commenters stated that since a series of events in 2011 and 2012 cast a light on mismatches in the operating cycles between the natural gas and el ectricity generation markets and pipeline capacity shortages, FERC has led an effort to encou rage stakeholders and numerous collaborative bodies to identify regional issues an d propose possible solutions. Commenters
added that a number of RTOs have established task f orces on electric and gas coordination, looking at information sharing, operations coordina tion, and process improvements. Commenters noted that in November 2013, FERC issued an order a llowing the voluntary sharing of nonpublic operational information between interstate g as pipelines and electric transmission providers to promote grid reliability and operation al planning. Commenters stated that while FERC was able to take steps quickly to address comm unications between the two industries, the issues of insufficient gas infrastructure and the n onalignment of gas and electricity markets have proven to be thornier for the Commission to deal wi th as the U.S. gas boom whets the appetite for more gas-fired power. Commenters noted that In March 2014, FERC issued a Notice of Proposed Rulemaking (NOPR) which has spawned an ext raordinary effort by the North American Energy Standards Board (NAESB) and natural gas and electric industry participants to develop a consensus on standards for coordinating t he scheduling processes of the natural gas and electricity markets. Commenters provided extens ive detail about the NOPR and the development of consensus standards, including remai ning areas of disagreement.

Extreme weather

Commenters stated that the maximum annual NGCC capa city can be limited by natural gas curtailments, transmission constraints, and/or air permit requirements, which provide additional compliance hurdles with the proposed Rule. Commente rs provided detailed information326

regarding natural gas constraints that affected NGC C unit production at the Fulton and Oswald stations over four continuous months during the win ter of 2013-2014. Commenters stated the most challenging issue facing AECC during this time period was the pipelines' contractual requirement that the plants run ratably (at a const ant level) over a 24-hour period. Commenters stated that, despite having a firm transportation ( FT) gas contract, for 66 days during the 2013- 2014 winter, not only could AECC not vary the plant s' gas consumption during the day (requiring the plants to stay at a constant output) , but AECC would have incurred contractual, financial penalties just to start up the plants. Co mmenters stated the winter of 2013-2014 experience yields three primary conclusions which a re contradictory to the premises underlying the proposed Rule: (1) There are events outside of an EGU-operator's control which affect an NGCC facility's annual capacity factor; (2) The exi sting natural gas infrastructure is currently insufficient to meet demand when it is most needed; and (3) In order to achieve even higher capacity factors for NGCC units than are achievable under current conditions, i.e., 70% (or more than 80%), the natural gas pipeline infrastructure needs to be upgraded. Commenters urged the
EPA to take these factors into account when finaliz ing the proposed Rule. Commenters stated that, while industry experts may differ about the s ufficiency of the existing natural gas pipeline system, there is no doubt AECC was affected by natu ral gas delivery issues during the most
recent winter and those effects cost AECC and its m embers' precious time and money.

Commenters stated that transmission constraints aff ect the ability to achieve capacity factor targets, further impeding the ability to comply wit h the proposed rule. Commenters stated the scope and cost of transmission improvements to elim inate these constraints need to be identified and considered. Commenters noted that AECC has expe rienced transmission constraints in the past and specifically pointed out that Entegra's Un ion Power facility has substantial excess capacity and energy that could be sold and provide substantial economic benefits to Arkansas
electric consumers if transmission access were not severely constrained. Commenters referred to an Entegra petition and stated the scope and cost o f transmission improvements that eliminate this constraint - allowing the Union Power facility and other existing generation resources in the Entergy region to reliably and economically transmi t power across the Entergy-SPP seam - need to be identified and considered [Arkansas Public Se rvice Commission Docket No. 10-011-U, Entegra Power Group, LLC's Petition to Intervene at 2-3 (February 19, 2010)]. Commenters stated that, given natural gas cannot be stored for future use onsite, power plants can only run on gas if the gas is delivered when needed. Commenters stated this uncertainty about supply undoubtedly will affect reliability and could even affect safety, if power cannot be delivered during peak utility usage times (such as for heatin g on a very cold winter day or air conditioning on a very hot summer day). Commenters stated that, given the paramount importance the natural gas delivery system will have under the proposed Ru le's power supply regime, qualitative and comprehensive studies are needed to assess the capa bilities of the natural gas pipeline system and the vulnerability of the system to attacks with res ultant impacts to electricity supply.

Commenters expressed concern regarding the impact o f potential gas delivery interruptions and constraints, such as occurred at the Oswald and the Fulton combustion turbine facility during the polar vortex events of the winter of 2013-14. Comme nters stated that, despite having a firm natural gas transportation contract in place, becau se of deliverability issues that occurred for 66 days during that winter, AECC would have faced cont ractual, financial penalties from its natural gas transportation provider for starting up either Oswald or Fulton. Commenters added that, if AECC had started up either Oswald or Fulton in orde r to serve load demand, it would have been327

unable to vary the hour-to-hour gas consumption dur ing the day for either facility because of the deliverability constraints.

Commenters stated that extreme spikes in spot gas a nd electricity prices, accompanied by widespread unplanned outages of gas-fired generatio n facilities, experienced in the eastern United States, and especially in New England, durin g the polar vortex of January 2014 brought gas-electric interdependency to the forefront. Comm enters indicated that though they were likely planned before that event, FERC's proposed changes to pipeline nominations and scheduling procedures soon followed.

Commenters stated the EPA should not ignore the nat ure of the current system of interruptible gas contracts that may not support increased dispat ch during the winter months. Commenters stated that moving toward a system of non-interrupt ible gas contracts to ensure supply at electric generating units during winter months means that th ese units will be competing with home heating for available gas supplies. Commenters stat ed that these complicated gas and electric interdependency issues are currently being reviewed at FERC and will not be fully resolved in the time necessary to meet the re-dispatch requirem ents of Building Block 2. Commenters stated that these concerns are also mirrored in comments p rovided by MISO. Commenters stated that, if the organizations charged with maintaining reliabil ity and the functionality of the electric system are concerned with natural gas infrastructure and e lectric-gas coordination, EPA cannot simply ignore those concerns.

Commenters stated that EPA cannot simply assume the availability (or planned future availability) of sufficient natural gas generation, natural gas pipeline capacity, or natural gas storage to support EPA's proposed environmental dis patch, particularly in ISO/RTO markets. Commenters (cited Moeller House Testimony and) stat ed that the recent Polar Vortex revealed that heavy reliance on the dispatch of natural gas fired generation already pushes the system to
its limits without the additional demand that the P roposed Rule would require utilities to put on the system.

Commenters stated the availability of gas-fired gen eration depends on the availability of natural gas transportation to the individual unit and, espe cially during periods of high gas demand, the availability of sufficient high-capacity gas storag e close to the location of gas withdrawal. Commenters stated that firm transportation service is not always available in the winter (the highest period of demand for gas heating), and purc hasing firm transportation service for gas is often not economically feasible when that service i s really only needed those few hours a year
when extreme weather events like the Polar Vortex c reate high demand for both electricity and end-use natural gas. Commenters (cited a March 20, 2014 FERC Scheduling Coordination Order and) stated that, when the nationwide gas transport ation system is constrained by peak demand during periods of extremely cold weather, gas-fired generators have sometimes been unable to procure sufficient resources to fulfill their elect ricity market commitments and to contribute to reliable system operation. Commenters provided exam ples of service problems during last winter's Polar Vortex. Commenters (referenced the N ERC report Potential Reliability Impacts of EPA's Proposed Clean Power Plan and) stated as gas- electric dependency significantly increases, unforeseen events like the 2014 polar vortex could disrupt natural gas supply and delivery for the power sector in high-congestion regions, increasing the risk for potential blackouts.328

Commenters (cited a September 2014 NERC on the Pola r Vortex and) stated that there is potential for reduced natural gas-fired generating capacity during periods of extreme cold because of the potential for curtailments and inter ruptions of natural gas deliveries to the power sector. Commenters stated these periods of extreme cold tend to coincide with high demand for natural gas for heating purposes. Commenters stated that very few natural gas-fired generators have any on-site storage of natural gas and must re ly on real-time delivery of the fuel in order to generate electricity; thus, if the natural gas cann ot be delivered (for any reason) then the generators cannot generate to meet electricity dema nd. Commenters provided Figure 3 (titled: “Reproduction of Figure 13 from NERC Polar Vortex R eview"), and stated the figure shows the natural gas-fired generators represent 55% of the f orced outages, while coal-fired generators represent 26% of outages) and nuclear generators (3 % of outages).

Comment 23: Commenters said that, this proposed guideline is to tally inadequate to address a horizontally integrated electric utility system whe re the cooperative has no control over the portfolio mix, and limited access to transmission o ptions. Commenters said, it is inadequate to regulate merchant generation plants that have no co ntact with end-use customers because the merchant generation plants cannot impact or change their customers' consumption practices.

Commenters said that, this failure to address key c omponents of and general practices in the
Electric Generation and Transmission sector is a ma jor reason the commenters requested that EPA withdraw the rule and make the necessary adjust ments before restarting the entire process.

Response 23: The EPA disagrees. The final rule applies to sourc es and emissions from those sources, not to the consumption choices of end user s. The final rule provides multiple pathways for sources to comply, including shifting between s ources already in the portfolio mix and purchase of credits (ERCs). See sections V.A, V.B, V.D, VIII.A, VIII.C and VIII.G of the final rule preamble of the CPP and Chapter 3 of the GHG M itigation Measures TSD for the CPP Final Rule supporting the final CPP.

Comment 24: Transmission issues, market issues, and line losses

Response 24: The EPA disagrees that transmission issues, market issues, and line losses prevent achievement of the goals. Additional analysis may be considered by implementing authorities. In response to additional analysis and many comments, we have modified the proposal and RIA; the establishment of CO2 emission reduction standards is regionally based. The 111(d) final rule requires that states develop plans that establish emission standards for affected EGUs. We are providing states with substan tial flexibility as to how they structure those plans to achieve the 111(d) requirements. The flexi bility includes, for example, the choice of approaches, trading, time to develop plans, additio nal time before the start of the interim performance period (postponed from 2020 until 2022) , and the ability to shift emission rate achievement between performance periods. Neither th e Building Blocks nor the IPM analyses are prescriptive, and states may consider local cir cumstances as they develop their plans, including system reliability, fuel diversity, other regulatory requirements and infrastructure. See329

sections V.A, V.B, V.D, VIII.A, VIII.C and VIII.G o f the final rule preamble of the CPP and Chapter 3 of the GHG Mitigation Measures TSD for th e CPP Final Rule supporting the final

CPP.

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

Commenters stated the EPA needs to address how the CPP will result in increased transmission congestion and higher energy costs across the state and adjust the Building Block calculations for Florida accordingly.

Commenters stated that, to comply with a 70 percent utilization target for NGCC, good faith efforts could be considered market manipulating act ivities: NGCC owners may have to bid into
the MISO market as "must run" or self-schedule NGCC s in MISO's day-ahead bidding process and coal-fired generators may have to adjust the of fered price to comply with other Building Blocks of the Proposed Rule. Commenters stated thes e combined activities could be interpreted unfavorably by MISO's Independent Market Monitor (I MM). Commenters stated that, for the IMM to perform its market monitoring function, MISO market rules would need to change to allow a NGCC generator to bid artificially for a 70 percent dispatch, while also allowing the IMM to monitor the way the bid was executed to ensu re it was not done in a way that allowed the "complying" generator to manipulate the broader market. Commenters stated that nothing in EPA's proposed Building Block recognizes either of these basic market constraints or offers solutions to resolve them. Commenters stated that, because it is unclear how to dispatch environmentally in a market that is reliability and economically driven, as a result, the EPA inappropriately applied BSER because the associated benefits with this Building Block are not
shown to be achievable.

Commenters stated there is no guarantee NGCC units could send their power to the same loads currently being serviced by coal-fired EGUs. Commen ters stated that the longer the distance between the NGCC and the market it serves, the high er the "line loss" associated with delivering the electricity to market. Commenters stated that l ine loss cuts into the emissions reductions assumed by the EPA. Commenters stated that, while t he EPA includes line loss calculations in the Agency's feasibility estimates, the estimates a re not region specific and not appropriately applied in setting state targets. Commenters stated that, as a result, the EPA failed to appropriately apply BSER. Commenters stated the EPA should recalculate its estimates for line loss using state-specific data.

Commenters stated congestion is also a major concer n, between and within transmission regions. Commenters noted that PJM in particular has experie nced major congestion issues in the transmission of electricity between its eastern and western markets and stated the impact of "forcing" specific EGUs to run could result in unin tended consequences, such as creating congestion patterns that would be difficult, if not impossible, to anticipate. Commenters stated that, because PJM has experienced major congestion issues in the transmission of electricity between its eastern and western markets, there is n o guarantee Indiana will be able to economically consume the excess electricity produce d by NGCC plants operating at a higher capacity factor.330

Comment 25: Commenters stated that the proposed rule does not e xamine whether sufficient natural gas storage exists to support large-scale f uel switching.

Response 25: The EPA disagrees. In response to additional analys is and many comments, we have modified the proposal and RIA; the establishme nt of CO2 emission reduction standards is regionally based, and the EPA does not project larg e increases in natural gas usage. The 111(d) final rule requires that states develop plans that establish emission standards for affected EGUs. We are providing states with substantial flexibilit y as to how they structure those plans to achieve the 111(d) requirements. The flexibility in cludes, for example, the choice of approaches, trading, time to develop plans, additional time bef ore the start of the interim performance period (postponed from 2020 until 2022), and the ability t o shift emission rate achievement between performance periods. Neither the Building Blocks no r the IPM analyses are prescriptive, and states may consider local circumstances as they dev elop their plans, including system reliability, fuel diversity, gas storage capacity, other regulat ory requirements and infrastructure. See sections V.A, V.B, V.D, VIII.A, VIII.C and VIII.G of the fin al rule preamble of the CPP and Chapter 3 of the GHG Mitigation Measures TSD for the CPP Final R ule supporting the final CPP.

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

Commenters stated the proposed rule does not examin e whether sufficient natural gas storage exists to support large-scale fuel switching. Comme nters stated that many states do not have adequate geologic formations to store the natural g as that would be needed for the large scale dispatch of NGCC called for under Block 2. Commente rs stated that, according to a 2013 report, "[g]eology limits opportunities to build storage wh ere the market would prefer it and, because of that, the current 400 or so storage facilities are not distributed evenly across the country and many of those facilities are single season reservoi rs -- rather than higher deliverability salt
cavern-based facilities." Commenters stated that wh ile generators may want to take advantage of lower-priced natural gas, supply and storage issues hinder this development. Commenters stated that a reliability concern is that natural gas plan ts cannot stockpile their fuel, so if pipeline deliveries of natural gas are disrupted, the plants almost instantly stop generating power. Commenters stated that coal-fired power plants have the capability to stockpile fuel on site, providing reserve fuel supplies in the event of del ivery problems. Commenters stated that, not only will the increased reliance on natural gas req uire new pipeline infrastructure, or provision of fuel oil backup, but it may require redundancy in t he pipeline infrastructure in order to minimize the risk of natural gas supply disruptions, further driving up costs. Commenters stated that Michigan has the most natural gas storage in the na tion, but during the winter of 2013-2014 there were questions of being able to maintain an adequat e supply of natural gas and price spikes in
the state. Commenters noted that when resources are used, they must be replenished, and this is limited by pipeline transmission capacity.

Commenters stated that, while natural gas pipelines can typically be permitted, financed and constructed in four to eight years, construction of natural gas storage facilities is far more difficult because of the limited geology for natura l gas storage--most parts of the U.S. lack the appropriate geology to store natural gas in the sub surface. Commenters noted that natural gas transmission pipelines cannot store significant qua ntities of gas; at best, they can store a marginal amount through "linepacking." Commenters stated tha t the question of sufficient storage is often331

not considered because many existing natural gas-fi red power plants are located in regions of the U.S. with suitable geology to store sufficient amou nts of natural gas for the power and industrialmanufacturing sectors without any glitches in suppl y and delivery, or they are part of a larger, diversified fleet where they provide back-up power for renewables or peak power. Commenters indicated that in a few states, semi-depleted natur al gas fields offer excellent locations for storage of natural gas, but they are not suitable f or natural gas re-injection on a "multi-turn" or "rapid-use" basis needed by the power sector. Accor ding to the commenters, utilities encounter weather events that alter how much gas they may nee d and have to resell it since they do not have sufficient localized storage. Commenters state d that underground natural gas storage will be necessary to allow the electric utility industry to generate more power from natural gas-fired power plants. "Storage is very useful in providing flexibility to support gas burns by electric generators. Natural gas storage lets a power plant operator: ramp up or ramp down operations quickly (especially for intermittent renewables); m anage its imbalances; potentially hold less firm pipeline capacity; and maintain reliability."

Commenters stated that EIA reported that as of 2013 , roughly 4.6 Tcf of underground storage working gas capacity, representing roughly 410 unde rground gas storage fields, were in operation, but these underground storage fields are not equal in that most are not configured to provide rapid withdrawals for power plants, and man y are not located close enough to power plants to support the rapid change in linepack need ed when a power plant fires or otherwise accommodates multiple turns often needed to support power plant operations (commenters provided a table showing the location of natural ga s storage facilities and their proximity to existing coal-fired power plants). Commenters provi ded information on the existing underground storage fields as follows: 90 percent are "reservoi r or aquifer storage where gas is generally injected during the summer months and withdrawn dur ing winter to serve seasonal demand (with certain exceptions)" and the other 10 percent are h igh-deliverability salt cavern facilities; "Most, but not all, of the multi-turn, salt cavern storage is located along the Gulf Coast." According to the commenters, most of the new storage added since the 2010 APPA Gas Study was released is "producing area storage" located in the states of M ississippi, Louisiana and Alabama. (Commenters provided a table summarizing the key ch aracteristics of U.S. natural gas storage.) Commenters explained the various ways in which stor age can be used.

Commenters stated that NERC reliability standards r equire electric generators to be able to generate within 10 to 15 minutes of receiving notic e to do so (depending upon NERC region), which means that the natural gas to run those gener ators needs to be relatively close by. Commenters stated that linepack cannot be used to s tore enough natural gas for major power plants; it can only be used for marginal hedging ag ainst unexpected weather events and often will provide up no more than 12 hours of supply, as suming that only one or two utilities are doing this on an entire pipeline. Commenters provid e a figure showing that storage facilities are not evenly distributed, either geographically or re lative to demand around the country. Commenters noted that certain pipelines and regiona l markets do not currently have access to any underground gas storage, including Nevada, Idah o and Arizona; while the Central Plains states and Missouri have virtually none; the entire East Coast has none other than far upstream in western New York, western Pennsylvania and West Vir ginia; and to the extent that there is a small amount of storage in the Southeast, none of i t is in the eastern coastal states. Commenters said the Proposed Rule fails to look at key issues related to natural gas storage. Commenters
indicated that the EPA needs to examine these issue s and revise its assumptions regarding the332

timetable by which electric utilities could convert from coal-fired generation to natural gas-fired generation to reduce their CO2 emissions. Commenter s stated that it is likely that the success of many state compliance plans will depend heavily on the ability to build new natural gas infrastructure in a specific timeframe, and the ina bility to do so, based on factors beyond their control, is a prime example of why states should be allowed the opportunity at any time to request that EPA consider changes to their CO2 emis sion goals and/or an extension of the final compliance date.

Comment 26: Commenters stated that energy storage technology is able to not only enhance the capacity factor and efficiency of fossil generation , but by storing and releasing energy when the grid needs it most, it can replace most inefficient peaking capacity all together.

Response 26: The EPA agrees that many studies demonstrate the be nefits of energy storage.

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

Commenters stated that energy storage can specifica lly augment the output of natural gas turbines through thermal energy technology. Comment ers stated that Thermal Air Systems found that by storing energy in the form of chilled water during off-peak and low demand hours, and injecting chilled air into turbine inlets with the fuel, gas turbine output increased from 86% to 104% of their rated capacity. Commenters stated tha t energy storage can also substitute for spinning reserves entirely, thus reducing the need for additional peaker plants and preventing
increased CO2 emissions. Commenters stated that ene rgy storage creates system-wide efficiency, enabling more efficient ramping of existing plants, smoothing integration of renewable energy facilities, and shifting of peak load to off peak h ours, all of which increase the efficiency of the entire system. Commenters stated these values are p rovided wherever a storage system is installed on the grid, whether at the transmission or distribution level.

Commenters provided Figure 3 (titled: "Energy Stora ge for Peak Shaving"), which shows how savings at low demands can be used at high demand.

Commenters referred to a paper which asserts that m ost of the peaking capacity projected by EIA can be provided by energy storage. Commenters cited from the paper: "by providing energy balancing services at both a regional (transmission ) and local (distribution) level with the same storage asset, the locational value and capacity ut ilization of storage can be much higher compared to CTs [combustion turbines] interconnecte d at transmission voltage and operated as a central station resource." Commenters stated the pa per makes the argument that flattening system load with energy storage synergistically reduces th e need for all major categories of utility asset investment, including generation, transmission, and distribution. Commenters noted that, in Arizona, the utility Arizona Public Service agreed on a settlement to include energy storage in the planning and procurement process as a replaceme nt for additional peak capacity, recognizing the ability of storage to provide peaking services comparable to natural gas. Commenters stated that, in another case, Southern California Edison a warded energy storage over 260 MW of capacity in their Load Capacity Requirements Reques t for Offer. Commenters stated that this decision--that only required 50 megawatts of storag e in the LA Basin but ended up in the333

purchase of 260 megawatts of energy storage--was fu rther affirmation that not only can energy storage provide these services, but can do so cost- effectively in a competitive procurement

process.

Comment 27: Commenters expressed concern regarding the adequacy of pipeline infrastructure.

Response 27: The EPA disagrees that gas market issues prevent ac hievement of the goals. Additional studies may be considered by implementin g authorities. In response to additional analysis and many comments, we have modified the pr oposal and RIA; the performance period has been postponed. The 111(d) final rule requires that states develop plans that establish emission standards for affected EGUs. We are provid ing states with substantial flexibility as to how they structure those plans to achieve the 111(d ) requirements. The flexibility includes, for example, the choice of approaches, trading, time to develop plans, additional time before the start of the interim performance period (postponed from 2 020 until 2022), and the ability to shift emission rate achievement between performance perio ds. Neither the Building Blocks nor the IPM analyses are prescriptive, and states may consi der local circumstances as they develop their plans, including system reliability, fuel diversity , other regulatory requirements and infrastructure. See sections V.A, V.B, V.D, VIII.A, VIII.C and VIII.G of the final rule preamble of the CPP and Chapter 3 of the GHG Mitigation Meas ures TSD for the CPP Final Rule supporting the final CPP.

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

More infrastructure needed

Commenters stated that, given there currently are i nfrastructure and supply constraints in the natural gas market, more pipeline investment is req uired to satisfy the 70 percent requirement. Commenters stated that 2012 natural gas prices were the lowest they've ever been, and dispatch did not even approach 70 percent; it was closer to 57 percent. Commenters noted that the EPA expected a 12 percent increase in natural gas stock prices by the end of the decade. Commenters stated that it is difficult to foresee achieving ev en close to 70 percent dispatch. Commenters used 2014 winter in the polar vortex to see how the stoc k market handles relying on only one fuel

source.

Commenters expressed concern regarding the adequacy of pipeline infrastructure and stated that NERC found that EPA's assumption in Building Block 2 that the "power industry in aggregate can support higher gas consumption without the need for any major investments in pipeline infrastructure" is unrealistic, and there are "crit ical areas," including Arizona, Nevada, and New England that already face pipeline constraints and will need even more pipeline capacity to the extent that coal generation is replaced by natural gas generation.

Commenters stated that, in analyzing the adequacy o f natural gas pipeline capacity to support increased operation of existing NGCCs, EPA conflate s natural gas retail deliveries overall and delivery to power plants. Commenters stated that ga s pipelines are generally designed to deliver natural gas on a 24-hour ratable basis, meaning the same quantity each hour for 24 hours;334

however, electric generation is not ratable over 24 hours and peaks significantly during the day. Commenters stated NGCC generation can easily requir e twice as much gas on peak as compared to off peak hours. Commenters concluded the EPA ove restimates the adequacy of natural gas pipeline capacity to support increased operation of existing NGCC.

Commenters stated that an enormous amount of natura l gas pipeline and storage infrastructure will be needed to enable fuel switching from coal t o natural gas in many states. According to the commenters, a March 2014 study by ICF International for the INGAA Foundation shows that most of the oil and gas pipeline investments made i n the last 4 years were made to move the upstream production of natural gas to gas processin g centers or oil to refineries; very little pipeline capacity has been built to address electri c utilities' current or future demand for natural

gas.

Commenters stated that the U.S will need thousands of miles of pipelines to meet the demand for natural gas by the electric utility sector once the Proposed Rule is finalized but, the Proposed
Rule does not take into account how much time will actually be needed to build this infrastructure, nor does it look at potential imped iments to the siting and permitting of natural gas pipelines. Commenters noted that FERC must revi ew and approve all projects to construct new interstate pipelines or expand existing ones be fore they can be built, and during the FERC approval process an environmental impact statement (EIS) must be prepared, as required by the National Environmental Policy Act (NEPA). Commenter s added that FERC must also verify that applicants have secured permits from local, state, and federal agencies before construction can begin. Commenters further stated that conflicts can arise during the review process between the various permitting agencies involved in the approva l process, which slow down the approval process and in some cases prevent the project from going forward or result in increased construction costs that are eventually borne by nat ural gas end users. Commenters stated that contentious permitting issues can lead to avoidance of certain areas of the country for future permitting, "constraining the ability of supply to reach markets."

Commenters stated that market-related issues can al so present impediments to new gas pipeline development. According to the commenters, RTO-opera ted capacity markets in the eastern part
of the U.S. create obstacles to the construction of new pipelines needed to supply sufficient gas to electric utilities (as well as obstacles to the construction of renewable generation), and this has been particularly problematic in New England, which generates over half of its electricity from natural gas and where the lack of sufficient pipeli ne capacity is widely expected to have significant, adverse reliability and cost impacts. Commenters noted that concerns about overreliance on natural gas and the need for suffic ient pipeline capacity to meet demand by the New England states led to an attempted effort to de velop a new business model for obtaining needed natural gas pipeline and transmission infras tructure. Commenters explained this as
follows:

"In December 2013, the Governors of the New England states issued a joint statement expressing their commitment to "continue to work to gether, in coordination with ISONE, and through the New England States Committee on Electricity (NESCOE), to advance a regional energy infrastructure initiative that diversifies [its] energy supply portfolio while ensuring that the benefits and cost s of transmission and pipeline investments are shared appropriately among the New England States." To further the335

Governors' stated goals, NESCOE launched the Energy Infrastructure Initiative ("Initiative") with two primary purposes; to increa se pipeline capacity in the region and to expand electric transmission to facilitate the deli very of electricity from "low to nocarbon resources.

"NESCOE recognized that the natural gas and electri city markets are not producing needed pipeline construction. Natural gas pipelines requir e long-term contracts to provide a steady stream of revenue, and in contrast the natural-gas- fired merchant generators operate in a shortterm restructured market with volatile revenue stre ams. As a result, these generators are not willing to commit to a long-term contract. Pipeline projects in New England have had no electric power generators purchasing firm gas transportation . The absence of generator subscription caused Spectra Energy's Algonquin Incremental Marke t (AIM) pipeline project to be downsized from the planned 500 mmcf/day to 342 mmcf/day.

"However, the NESCOE Initiative is currently on hol d as a result of the Massachusetts legislature's adjournment without passage of a bill to provide for state long-term contracting for electricity from resources with zero or low carbon dioxide emissions. Although this development primarily affected the electric transmission compon ent of the Initiative, the natural gas
infrastructure efforts were also stalled."

Time

Commenters also noted concern that regulatory actio ns might delay the additional pipeline
investment.

Commenters stated it is not likely there is suffici ent time and incentive to build the pipeline that is needed. Commenters noted that pipeline is genera lly built on the basis of demonstrated firm demand resulting from an open season. Commenters st ated that, historically power generators have been hesitant to sign up for long term firm tr ansportation capacity that is required to gain the needed investment in a timely manner, which res ults in a slower build-out of gas transmission, such as we see in the Northeast, wher e incremental pipeline capacity is not growing fast enough to mitigate periods of very hig h gas prices. Commenters stated that, as power generators' share of gas consumption in Arizo na and surrounding states grows, a similar situation to the Northeast region may develop in th e Southwest, in which new pipeline capacity is hindered by hesitation for firm capacity commitm ents.

Commenters stated the time to develop new pipeline infrastructure is at a minimum four years from the determination of need, although the permit ting stage can often significantly extend the process to five years or much longer. Commenters st ated an extension of this timeline is very possible in Arizona and the greater Western U.S. as the amount of land owned by the military, federal government, state governments, and tribal n ations is large which adds to the complexity of siting and constructing new capacity. Commenters stated that incremental expansions through compression upgrades can be realized in a two-year timeframe, but this only provides for small incremental capacity expansions. Commenters stated the NERC's 2014 Initial Reliability Review specifically identifies Arizona as one state whereb y the existing pipeline capacity is not adequate to handle incremental gas needs of the state under the CPP, consistent with Pace Global's findings. Commenters stated Pace Global projects po wer sector natural gas demand in Arizona in336

the building block case to increase from 546 MMcf/d in 2015 to 2,088 MMcf/d by 2030, an almost four-fold increase from the power sector alo ne. Commenters stated the natural gas supply situation in combination with literal application o f the CPP building blocks appears to place Arizona in a precarious position: given that Arizon a is reliant on the supply of natural gas from 3 major pipelines, the prolonged disruption of servic e to one of these pipelines could prove devastating to Arizona residents in the absence of backup coal capacity.

State-specific constraints

Arizona

Commenters stated that, while the proposal purports to provide flexibility to states in complying with the rule, Building Block 2 is the only option available for reducing carbon emissions in Arizona in the amount required by the proposal. Com menters stated the proposed rule would require utilities in the state to shut down or conv ert all coal facilities. Commenters stated that phasing out coal in Arizona is not as easy as simpl y converting current coal power plants to natural gas, because Arizona does not have natural gas deposits to draw on or any facilities available to store natural gas. Commenters stated t hat, in order to meet the goal required for this state significant additional infrastructure will be necessary to supply the state with natural gas in amounts sufficient to power base load power generat ion to replace the current coal generation. Commenters added that forcing the state to become t hat reliant on one source of energy production is a costly and imprudent action that wi ll leave the citizens of Arizona beholden to a resource that has historically been subject to vola tility in both cost and availability.

Commenters stated that the EPA's assumption that al l coal generation could be replaced by NGCC by 2020 fails to consider the implications for the gas pipeline system in Arizona. Commenters stated the merchant NGCC generators freq uently use non-firm pipeline capacity because it is generally available in the summer tim e when they run the most. Commenters stated there is very little firm gas pipeline capacity and no storage capacity available at this time in Arizona. Commenters stated that firm gas pipeline c apacity would be necessary if the Arizona utilities were forced to rely on the merchant NGCC capacity year round. Commenters stated there are currently no plans for the addition of ne w pipeline capacity to serve Arizona. Commenters stated the construction of new pipeline capacity can be a very lengthy process and noted that the recently completed Transwestern Phoe nix expansion project took close to five years from the initial open season to operation and cost approximately $950 million. Commenters stated that, as a result, it is almost c ertain that there would not be adequate firm gas pipeline capacity by 2020 to meet the needs under E PA's assumptions. Commenters stated the NERC recently identified the need for natural gas p ipeline expansion under EPA's Proposed Carbon Rule and specifically identified Arizona as one of the states in which current and planned infrastructure is inadequate to handle increased na tural gas demand due to the Proposed Carbon Rule. Commenters agreed with all of the concerns NE RC has raised and stated they support the concerns raised by the ACC.

Commenters stated the EPA's assumption that the exi sting NGCC generation could replace all of the coal generation ignores the electric transmissi on limitations within Arizona. Commenters indicated the major load pockets (Phoenix and Tucso n) are served by transmission lines from the coal plants, which tend to be in the northeastern p art of the state, and by transmissions lines from337

the Palo Verde hub, which is to the west. Commenter s asserted that, if all the coal plants are retired, as assumed by EPA in the goal setting, the majority of the energy would then be coming only from the west where the NGCC gas plants and so lar plants are located. Commenters stated that reliance will then be primarily upon the elect ric transmission lines from the west, which currently are not capable of transporting all of th e energy needed from the Palo Verde Hub into the Phoenix and Tucson load pockets.

Commenters stated that Arizona's current NGCC capac ity is not sufficient to both redispatch coal generation and meet summer peak demand. Commenters stated the Pace Study similarly found that existing NGCC EGUs are inadequate to replace t he coal-fired EGUs (Pace Study section 3.1, at 13). Commenters stated that, if Arizona wer e to redispatch coal with the existing NGCC capacity, the State would need to build out signifi cant additional NGCC capacity and infrastructure and renewable resources or make larg e and likely unsustainable market purchases. Commenters referred to the Pace Study (section 3.1 at 14) and stated that, while there are two major natural gas pipeline systems in Arizona, both systems would run out of capacity in the mid-2020s and time is short to fully integrate pipe line system improvements given lead times for such infrastructure projects. Commenters referred t o the Pace Study (section 3.6 at 26) and stated
that NERC-CAISO has determined that Arizona's "exis ting pipeline capacity is not adequate to handle incremental gas needs of the state under the CPP." Commenters stated the EPA has not given adequate consideration of this issue and it r equires a change in the timing of BB2 and revision to the Interim Goal, at the very least. Co mmenters stated the assumption that this generation switching could occur by 2020 is not fea sible for Arizona due to in large part to the magnitude of investments in generation, transmissio n and pipeline infrastructure simultaneously, which require substantial commitments, permitting a nd construction lead times.

Commenters referenced PACE modeling and stated that natural gas reliability in Arizona could be compromised due to the short time available to d emonstrate firm demand, secure necessary permits and build the natural gas pipeline expansio ns that would be needed to accommodate increased demand, as well as the risk of a prolonge d disruption to one of the pipelines serving
Arizona. Commenters stated demand would exceed exis ting pipeline capacity as soon as 2022 because existing natural gas capacity is nearly ful ly subscribed during peak hours.

Florida

Commenters stated it is important that EPA consider the challenge of relying so heavily on a fuel which currently enters the state through only 2 sev eral-hundred-mile-long pipelines, as this additional capacity is simply not available. Commen ters expressed concern that the EPA has factored re-dispatching to existing sources as acco unting for nearly 30% of the total reductions leading to the state goal, given that Florida alrea dy relies significantly on NGCC generation for
more than half of the state's total sales. Commente rs stated the City has already pushed its own generation, absent an EPA requirement, to natural g as, and improved the heat rate by retrofitting combined cycle operations to an existing unit at th e Arvah B. Hopkins Generating Station. Commenters stated that, even with this already-heav y reliance on NGCC, EPA presumes that the state of Florida can push 20% more of the state's g eneration to NGCC. Commenters noted that a third pipeline is being evaluated at this time, but was originally proposed to provide gas for new power plants, not the existing plants.338

Mississippi

Commenters stated that, although Mississippi has a large amount of NGCC generation, there are some limitations on increasing generation at all un its, including a gas transport limitation that impedes the station output from at least one NGCC u nit.

South Carolina

Commenters stated the EPA has designed building blo ck 2 based on a series of assumptions that are inapplicable to South Carolina and Santee Coope r. Commenters stated the Proposed Rule presumes that there is existing firm gas capacity a vailable to operate all NGCC units at 70% capacity. Commenters stated that, while for South C arolina in total there is sufficient firm gas to operate the existing units at 70% capacity factor, individual plants do not have and cannot currently obtain sufficient firm gas to operate at that level on an annual basis. Commenters stated that a gas-fired unit must have contracts for firm gas to operate at nearly 100% capacity factor to guarantee annual operations at 70% capacity factor (i.e., a unit cannot contract for firm gas capacity for only part of a year). Commenters state d that firm gas supply is contracted in million Btu's per day, but a customer cannot choose to move gas day-to-day. Commenters stated that, without firm gas supply, interruptible gas may or m ay not be available and, thus, interruptible gas contracts are not a reliable option for units t o meet anywhere close to 70% utilization. Commenters stated that South Carolina is not a prod ucer of natural gas and, while natural gas consumption for electricity generation in South Car olina doubled from 2008 to 2012, no major supply pipelines have been added in South Carolina and the number of operational flow orders (OFOs) that interrupt gas supplies have increased s ignificantly. Commenters stated that, in the winter of 2006-2007, on the Carolina Gas Transmissi on system within South Carolina, there were six OFO days compared with 40 in 2013-2014 and 34 in 2012-2013. Commenters stated this trend further underscores the inadequacy of in terruptible gas supplies for ensuring operation
of all NGCC units within the State at an annual 70% capacity factor.

Commenters stated that additional pipeline capacity would need to be added to South Carolina for its existing NGCC units to operate at an annual 70% capacity factor. Commenters stated this expansion will take significant time for financing, permitting, and construction-a minimum of three to five years is estimated (NERC Initial Reli ability Review at 10) and then only if the expansion experiences minimal delays or opposition. Commenters stated it will also be expensive: rate estimates given to Santee Cooper by Carolina Gas Transmission are 3.5 to 7 times the rate for existing capacity.

Comment 28: Commenters included a description of NERA's whole-e conomy model, NewERA, and findings from their analysis of the extent to w hich they anticipate gas deliverability concerns over the peak seasons that may constrain states’ ab ility to comply with the EPA's proposed CPP targets under Section 111(d) of the Clean Air Act.

Response 28: The EPA disagrees that the modeled results of the p roposal would reflect a similar analysis of the 111(d) final rule. The EPA believe s that a model this detailed would likely show results quantitatively different from an analysis o f the final CPP, due to significant changes from339

proposal. See sections V.D, VI, and VII of the fin al rule preamble of the CPP and the regulatory impact analysis of the final CPP.

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

As summarized below, commenters provided state-leve l disaggregated findings via a qualitative and relative ranking exercise informed by quantitat ive, model-based projections of natural gas demand changes under the CPP.

Commenters included the following description of NE RA's whole-economy model, NewERA, methodology and broad findings:

NERA ran its whole-economy model, NewERA, using the EPA's CPP compliance cost assumptions to replicate approximately EPA's aggreg ate estimates of the effect of the CPP targets on electric sector natural gas demand. NERA then used the model's outputs to assess the state-by-state levels of total natural gas demand i ncreases implicit in EPA's analysis. NERA also ran a second scenario relaxing EPA's input assumpti on around the availability of energy efficiency, to help establish a range of uncertaint y on projected state-level gas demand increases. Using these state-level demand projections, NERA as sessed whether existing pipelines and the potential for new pipeline development by 2020 can reasonably be expected to accommodate that projected amount of growth in natural gas dema nd. This was performed via a qualitative, multi-tiered screening of states according to risk factors identified by NERA's natural gas market experts, including high regional relative prices, i ndicating constraints at natural gas supply hubs; high futures prices, highlighting traders' expectat ions of future constraints at such hubs; and large natural gas demand increases in each state, adding load to the system. If a state's projected baseload electricity generation is reliant on natur al gas, we project that even a brief or small shortage could reduce electricity service reliabili ty. Hence, our screening criteria include an assessment of the share of natural gas in projected baseload generation. (In a footnote, commenters noted the following: Traditional electri c system planning has not taken into account the correlation of unit outages. Rather, it has tre ated outages as independent events. Insofar as multiple generators take natural gas from a single pipeline, a forced outage due to unavailability of natural gas on that pipeline would cause multipl e generators to face an outage. In practice, unit outages can therefore be correlated. This underscor es the potential for reliability concerns that have not been addressed in traditional power system reliability analysis.) We also consider the institutional arrangements in each state, as market considerations alone are not sufficient to understand the deliverability problems that may res ult from large increases in natural gas demand. As a result of these considerations, we cat egorized each of the 48 U.S. mainland states into one of five categories of risk, reflecting our assessment of the likelihood of natural gas supply concerns and associated electricity price an d/or reliability risk. Our assessment of the
combined effect of these considerations has caused us to identify a top-tiered set of 18 states and
a second-tier of 12 more states across the U.S. in which electricity generation may face natural gas supply concerns and associated electricity pric e or reliability risk. The remaining states were not identified by any of the screening criteria tha t we have used in this assessment, but this does not imply that they are free of any natural gas sup ply risk. For example, our analysis has not addressed how increasing natural gas demand on a na tional scale may affect even states that may have declining reliance on natural gas.340

Commenters stated that in ranking states in terms o f their potential risk for electricity price or reliability pressures, they considered two things: (1) where there are institutional risk factors in states with large percentage increases in natural g as consumption by 2020; and (2) where the baseload is projected to be very heavily dependent on natural gas combined cycle generation.

Commenters provided the following description of th e electricity sector model, NewERA:

The model includes a representation of all existing generating units that send power to the grid. Each existing unit is provided with a number of options over time, including dispatching, remaining online for reliability purpo ses, and retiring. Potential new units can also be added to replace retired units, to meet increasing electricity demand, and to meet environmental rules and regulations. Given con straints on variables such as electricity demand, electricity transmission limits , and environmental limits, the model identifies the set of long-term planning and short- term operational decisions that serve loads through time on a present value least-cost ba sis. With the added constraint of complying with EPA's proposed CPP, each state must meet specified CO2 emission rate limits (denoted in lbs/MWh from covered units). As well as ramping up energy efficiency (in the scenario where this is assumed to be cost-e ffective and available as a component of the CPP compliance formula), re-dispatch of coal -fired generation to natural gas-fired generation is a primary compliance option. In addit ion to re-dispatch, there are also additions of new natural gas combined cycle generat ors to meet electricity demand. The combination of re-dispatch and new natural gas-fire d generating capacity creates increased natural gas consumption in the electric s ector in many states. The increased consumption from existing natural gas-fired generat ors is straightforward to quantify, since we know the physical location of each existin g generator. The physical location of projected new natural gas-fired generating capacity is more complex. These units are built in the model in electricity market regions ra ther than in specific states within each region. For this analysis, we have allocated natura l gas use from projected new capacity
to states based on each state's relative share of r egional electricity demand. This assumption injects a degree of uncertainty into our projected state-level increases in natural gas projections. A more complex quantitativ e analysis would evaluate whether alternative allocations might significantly alter o ur qualitative rankings of some states. The NewERA model is a whole-economy model, which as sesses both natural gas demand changes for the electric sector and for othe r sectors of the economy. Commenters
stated that evaluation of risks associated with inc reases in natural gas demand requires an assessment of total natural gas demand, not just el ectricity sector demand. Commenters
stated that results from the IPM model cannot infor m such an assessment, even if statespecific results were estimated from that model's o utputs; rather, a whole-economy model
like NewERA is needed.

Commenters stated they performed the natural gas de mand projections using the NewERA model for two extreme assumptions about the cost/av ailability of demand-side energy efficiency: (1) That the full amount of demand-sid e energy efficiency that EPA has assumed for building block 4 is cost-effective compared to any of the other compliance options; and (2) that no demand-side energy efficiency (beyond quantities projected to occur in the baseline without the CPP) is available for compliance determinations and/or cost-effective relative to the other alternatives. In this scenario, each state achieves the proposed Section 111(d) targets without any341

demand-side energy efficiency programs. Commenters noted that both scenarios assumed proposed state rate limits under Option 1 would be met by each state independently seeking its least-cost opportunities, without any multi-state c oordination and that States would use the flexibility mechanisms to the extent possible, but they differ in how much cost-effective demandside energy efficiency would be feasible. Commenter s stated they considered the two extremes: (1) that the entire amount EPA assumed when constru cting the rate limits would be cost-effective as a first line of action for compliance and (2) th at none of it would be cost-effective relative to the other potential compliance actions.

Commenters stated that all other key compliance ass umptions in their model runs rely upon EPA's IPM modeling assumptions. Commenters provided Table 2 and stated the table demonstrates the similarity of total electric secto r natural gas consumption in the EPA's IPM analysis and the comparable baseline and policy eva luation that they conducted using the NewERA model (NewERA with Energy Efficiency). Comme nters stated that their state-by-state electricity sector natural gas demands would likely be quite similar to EPA's because we have used the same key policy assumptions, such as the r equired state emission rate limits and the quantity of energy efficiency available in each sta te.

Commenters provided a figure with two maps, entitle d "Figure 1. Projected Natural Gas Demand in 2020 in Compliance with Section 111(d) State Tar gets, with Overlay of Locations of Interstate and Intrastate Pipelines." Commenters stated Figure 1 shows the following:

Most states will experience increases in total natu ral gas demand by 2020 relative to the maximum they consumed in 2012. The largest percenta ge increases are generally in the mid-Atlantic, Midwest and upper Midwest, implying r elatively little overlap between
states with risks of institutional barriers and tho se with the larger increases in natural gas demand. Given such lack of overlap, we defined the states with the highest potential risk, based on demand increases alone, as those where the projected total natural gas demand significantly exceeds 2012 natural gas consumption. These are states where even an occasional difficulty in obtaining natural gas coul d trigger concerns about electricity reliability. We also add to our first-tier screen s tates that are projected to generate more than 35 percent of their baseload energy with natur al gas under the CPP. We project eleven states (appearing in the darkest blue of one or both panels of Figure 1) will have an increase in total natural gas demand of more tha n 25 percentage points, thus placing them in the top-tier risk category. In addition, we include in this top-tier category three states with 50 percent projected reliance on natura l gas for baseload generation under the baseline case with increased reliance on natural ga s expected under the CPP: California, Florida, and Nevada. Also included are Arizona, Ala bama, Louisiana, Oklahoma, and Texas, which we project will rely on gas for more t han 35 percent of baseload generation
under the baseline case and will increase reliance under the CPP.

Commenters provided Table 3, and stated Table 3 sum marizes the demand attributes of the states in the top-tier risk screen. Commenters stated that , of the 18 states, ten qualify on the grounds that they have demand increases of more than 25 per centage points; seven qualify because of their significant natural gas baseload shares, and one (Arizona) qualifies under both criteria.342

Commenters stated that, for the 18 states that pass ed our first set of screening criteria (as listed i n Table 3), they identified as relatively higher risk within this first screened set, those states that also appeared to be or were affected by the network fragility identified in the pricing analysis or by other institutional considerations. Commenters n oted their analysis included reference to forward prices curves and well-publicized infrastru cture development, although this qualitative ranking exercise did not include a rigorous analysi s incorporating forward prices. Commenters stated that causes for fragility could be, for exam ple, being upstream of a downstream constraint. Commenters stated they used the following the consi derations to categorize the states into three
levels of relative risk:

• Relatively High - Anticipated to have sustained gas deliverability concerns over the peak seasons. These are states where gas pipeli ne deliveries have been constrained and are projected to be constrained, as reflected in high basis spreads. Projected large increases in gas loads are likely t o lead to delivery problems

• Moderate to High - At risk of non-deliverability in event-driven tight supplydemand circumstances (such as the polar vortex). Th ese are states where gas pipeline deliveries have not typically been (and ar e not anticipated to be) constrained on a sustained basis during the peak se asons. However, states that relied on gas for more than 50 percent of their bas eload generation in the baseline in 2020 and are expected to increase their reliance by 2020 under the EPA's 111(d) targets have been classified as intermediate risk as interruptible gas supply may be curtailed during events that lead to tight m arket conditions.

• Low to Moderate - States that are likely to have la rge projected growth in gas consumption but have sufficient infrastructure (exi sting or in the pipeline) to
accommodate the increased demand. States that relie d on gas for more than 35 percent of their baseload generation in the baselin e in 2020 and increase reliance under the EPA's 111(d) targets are also included as low risk as interruptible gas supply may be curtailed during events that lead to tight market conditions.

Commenters stated that, for the remaining states th at were not identified by their first set of screening criteria, they applied a second-tier scre ening that recognizes that there is no bright line for which projected demand increase represents risk of natural gas supply and deliverability; even small percentage increases may create some und esirable outcomes, particularly when a very large number of states are experiencing simultaneou s demand increases. Commenters stated they included as relatively higher risk the 13 states wi th increases less than the 25 percent but more than 10 percent in both modeled cases. Commenters s tated that, while there may be relatively little risk of natural gas shortages in 2020 if the increases in 2020 relative to 2012 are less than 25 percent, it is not reasonable to assert that tho se other states are not free of any natural gas supply risk, and so they have classified these stat es as having a low risk of natural gas deliverability and reliability concerns. Commenters stated that, of those states that met this second-tier screen, the ones that might be of most concern are where power generators have no history of purchasing from interstate pipeline capa city. Commenters stated that such states are largely in the Northeastern U.S., although Northeas tern states are mostly projected to demand less total gas in 2020 than they consumed in 2012. Commenters stated there are two deregulated states that are projected to have at least 10 perce nt demand increase in both model cases and343

should perhaps be given further scrutiny in a more detailed evaluation of natural gas supply concerns: Oregon and Illinois.

Commenters provided a table in Figure 2, which summ arizes the 18 top-ranked states' relative risk rankings with an overlay of natural gas pipeli ne infrastructure. Commenters stated that Figure 2 highlights that not only may gas-exporting states with dense gas infrastructure face pipeline constraints in the future, but also those states at the terminal end of major pipelines, especially during summer and winter peaks (i.e., Ma ryland, Florida, and California).

Commenters provided Table 4, which shows the relati ve rankings of states that resulted from application of their criteria and the additional su b-rankings for the 18 states that were identified by our first screen. Commenters stated Table 4 show n in plain text format is as below:

Risk Level: Relatively High

• Maryland: Spot pricing for Transco Zone 6 Non-NY ha s historically shown constraints. Forward pricing confirms market partic ipants' expectations of continued congestion in the Mid-Atlantic markets. A lso, this is a region where competitive generators do not buy gas transport on a firm basis, so institutional barriers are expected to beset new pipeline project s.

Risk Level: Moderate to High

• North Carolina: While not traditionally congested, the market sits just upstream of potentially congested markets. In addition, Transco is the only large interstate pipeline to serve the state. Significant increases in natural gas loads would be difficult to meet without new pipeline investment.

• Virginia: While not traditionally congested, the m arket sits just upstream of potentially congested markets. New pipeline infrast ructure investment is being made to serve the Cove Point LNG Export Terminal.

• West Virginia: While more closely tied to the rela tively uncongested Midwestern markets than Virginia, it is dependent on two major interstate pipeline systems, including Transco, which has downstream constraints

.

• California: Now relies on natural gas for more tha n 50% of baseload and this reliance projected to increase under proposed CPP.

• Florida: Relies on natural gas for more than 50% o f baseload generation in base case increased reliance under proposed CPP. Pipelin es near capacity during peak
months.

Risk Level: Low to Moderate

• Arizona: Not currently considered to be constraine d; excess capacity on pipes going west.344 • Indiana, Iowa, Kentucky, Missouri and Ohio: Typica lly not congested. Witnessed extreme prices for a few days during the 2014 cold snap. Not anticipated to be congested.

• Pennsylvania: Not congested on forward basis. Sign ificant in-state production and infrastructure build to accommodate new supplie s.

• Louisiana: Relies on natural gas for more than 35% of baseload generation under
the base case and will increase to more than 50% re liance under proposed CPP. Natural gas exporting state that experiences an inc rease in demand for interruptible within state supply.

• Oklahoma, Alabama: Relies on natural gas for more than 35% of baseload generation under the base case and will increase to more than 50% reliance under proposed CPP.

• Texas: Relies on natural gas for more than 35% of baseload generation under the
base case and will increase to more than 50% relian ce under proposed CPP. Natural gas exporting state that experiences increa se in demand for interruptible from state supply, especially as it is deregulated.

• Nevada: Relies on natural gas for more than 50% of baseload generation under the base case and this percentage will increase und er proposed CPP. Limited pipeline infrastructure that connects to other at-r isk states (i.e., California and Arizona).

Risk Level: Low

Colorado, Georgia, Illinois, Minnesota, Nebraska, N orth Dakota, Oregon, South Dakota, Tennessee, Utah, Wisconsin, and Wyoming.

Risk Level: Lowest

• Arkansas, Connecticut, Delaware, Idaho, Kansas, Mai ne, Massachusetts, Michigan, Mississippi, Montana, New Hampshire, New Jersey, New Mexico, New York, Rhode Island, South Carolina, Vermont and Washington: This "Lowest" group simply identifies all the states tha t did not pass any of our screening criteria. This does not imply that they a re free of any gas supply risk. For example, our analysis has not addressed how inc reasing gas demand on a national scale may affect even states that may have declining reliance on natural

gas.

Commenters noted limitations regarding their analys is:

The analysis, which is based on a screening of proj ected changes in natural gas demand by state with an overlay of hub price data, could be enhance d by a more detailed comparison of
infrastructure assets in those states and surroundi ng regions to the projected load increases345

among different types of customers. For example, in those states where pipelines have operated at or near capacity, existing interstate pipeline i nfrastructure may not be able to accommodate even small increases in natural gas demand. The scr eening analysis does not consider freeze-offs, where small amounts of water produced along with na tural gas crystallize, blocking passage of natural gas. While both natural gas and coal units experienced forced outages during the polar vortex, the simultaneous spike in heating gas deman d and electric generation natural gas demand suggest heightened risks associated with such event s in the future.

Comment 29: Commenters suggested the EPA's modeling with the IP M is inadequate with respect to reliability margins, transmission and op erational constraints, and prices.

Response 29: EPA disagrees that our modeling is inadequate. The IPM model is well described noted in published documentation, and EPA used othe r analyses in addition to the IPM model. Moreover, EPA believes that the CPP provides states with the flexibility, including trading, to develop plans that consider reliability and local c ircumstances, such as transmission constraints, extreme events, and system balancing. See sections V.D, VIII.A, VIII.C and VIII.G of the final rule preamble of the CPP and Chapter 3 of the GHG M itigation Measures TSD for the CPP Final Rule supporting the final CPP.

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

Commenters stated that reliability and regional pla nning concerns should be more fully considered. Commenters stated that, while the EPA a ttempted to evaluate reliability via the Integrated Planning Model (IPM), NV Energy stated t hat use of the IPM does not allow for adequate consideration of system reliability and ot her operational concerns. Commenters stated that, in the NV Energy system, the state utility re source planning codes require that resource development, purchases, retirements, and contracts be prioritized around a peak open position that includes reliability margins and potential uni t forced outages, not an annual capacity factor. Commenters stated that IPM lacks sufficient granula rity to reasonably simulate the operational implications of EPA's proposed regulation under sec tion 111(d), and consequently, the IPM model results cannot fully predict how operational reliability considerations will affect the
tradeoff between emissions benefits and electric se ctor costs. Commenters specifically
recommended the EPA:

• Refine its analysis of the proposed rule by incorpo rating the need for system operators to maintain sufficient operating reserve levels and use this analysis to revise the proposed BSER to ensure it is aligned wi th operational realities.

• In the event impacts to reliability are predicted, states should be allowed the flexibility to incorporate mitigation measures, inc luding the time to implement such measures, into their state plans.346 • If reliability impacts are encountered during imple mentation of state plans, EPA should allow a reliability safety valve or variance process that suspends compliance for those states or entities which make adequate demonstrations.

• Fully evaluate how the proposed BSER will affect re gional system reliability, modify the BSER for each state to ensure that it ca n be implemented without deteriorating regional system reliability, and upda te its economic analysis to include all costs required to maintain regional sys tem reliability.

Commenters provided the following detailed comments on EPA's IPM analysis.

• EPA's IPM analysis models resource adequacy by impl ementing a reserve margin, which is a percentage applied to net peak load with in a model region that drives new resource additions over the simulation period. As described in EPA's documentation for IPM v.5.13, the reserve margin re quirement encourages regions to build beyond forecasted peak load to gua rantee reliability of the electric generation system within the region. While this mod eling approach ensures that there is sufficient capacity available at the time of peak load (i.e., one hour in the year), it does not ensure that generating plants ar e dispatched to maintain sufficient operating reserves among all hours in th e year. In fact, IPM lacks the ability to simulate dispatch of generating assets i n a way that provides sufficient operating reserves are being carried consistent wit h regional reliability standards, which extend beyond resource adequacy criteria. Act ual operations can significantly impact dispatch levels of flexible ge nerating assets, which in turn can significantly impact emission rates associated with fossil-fueled plants. The very foundation of the proposed rule is to establis h a BSER and derive a target
emission rate for each state. If states choose to i mplement plans that align with the BSER, the actual emission rate impacts of that plan will not align with those shown in EPA's IPM modeling, which is not capable o f modeling operating

reserves.

• The EPA's IPM modeling also assumes significant ret irements by 2020, but does not adequately accommodate transmission constraints . The IPM represents the effect of major transfer path constraints by limiti ng the ability to transfer power between regions to set values for each path. This i s a simplistic method commonly used in production cost models to recognize known t ransmission capacity constraints in order to improve the accuracy of the generation dispatch solutions. However, since the actual transmission system is no t modeled, simulation results from the IPM cannot predict the performance of the transmission system. This is particularly true if a significant quantity of exis ting generation is retired and new replacement generation is proposed for installation at unknown locations.

• A related limitation of the IPM is that it does not represent unit commitment and dispatch in a detailed manner. Dispatch within the model is based on variable generation costs alone and does not include operati onal constraints (e.g., ramp rates, startup and shutdown costs, minimum load lim its, etc.). These omissions impact IPM's ability to offer insights about questi ons related to the operation of a347 portfolio of fixed capacity and investment decision s related to capacity expansion. Consequently, the resource adequacy and reliability analysis TSD does not sufficiently demonstrate potential operational chal lenges associated with the capacity mixes resulting from the proposed rules. T he TSD states that "...the implementation of this rule can be achieved without undermining resource adequacy or reliability...," and IPM runs are used as supporting evidence for this claim. However, detailed unit commitment modeling h as not been done to date and NV Energy believes this would be a necessary pr erequisite to a thorough assessment of the resource adequacy and flexibility requirements induced by the proposed rule.

Commenters stated there is no evidence that the EPA 's modeling has taken into account the following factors: (1) continued access at today's historically low prices is questionable in the face of special-interest opposition to drilling and the specter of additional federal regulations and (2) the EPA's proposal admits that 70% utilization rates have been exceptionally rare, 12 consequently, assertions of technical feasibility r equire detailed modeling, contingency planning, and real-word testing. Commenters noted the corresp onding percentages of NGCC units that in 2012 operated at annual utilization rates of at lea st 65 percent and at least 75 percent were 16 percent and 6 percent, respectively (U.S. EPA, Emis sion Guidelines for Existing Stationary Sources: Electric Utility Generating Units, June 2, 2014, at Fn 127).

Commenters expressed concern that IPM projects no n ew significant NGCC generation in Ohio despite the closures of coal-fired plants, increase s in electricity demand, and increasing availability of natural gas in the state. Commenter s noted that new NGCC units appear in the IPM projections in Ohio, but those units have negli gible generation. Commenters stated this makes no sense and is incompatible with Building Bl ock 2. Commenters noted that, by the middle of 2016, closures of coal-fired power plants in the state will result in a loss of 6836 MW, or 30%, of Ohio's generating capacity.

Comment 30: Commenters stated that, based on modeling analysis, Florida cannot meet the EPA's proposed rule with current generation plants, no matter how they are run.

Response 30: EPA disagrees that the commenter’s modeled results of the proposal would reflect a similar analysis of the 111(d) final rule. EPA b elieves that changes since proposal, including modifying the CO2 emission performance rate for Flo rida and delaying the start of the interim performance period until 2020 have made the analysi s referenced in this comment less applicable. Also, EPA believes that the Rule allows Florida to address local issues including system balancing, transmission constraints, and fue l diversity. The Rule does not prescribe the approach states must take to achieve CO2 emission p erformance rates, and it provides flexibility, including trading, for states to develop plans that consider reliability. States may choose any of a variety of approaches to develop a plan. See sectio ns V.D, VIII.A, VIII.C and VIII.G of the final rule preamble of the CPP and Chapter 3 of the GHG M itigation Measures TSD for the CPP Final Rule supporting the final.348

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

Commenters stated that inter-utility purchases incr emental to Ten Year Site Plans were not estimated, but are not sufficient to avoid new ener gy sources. Commenters stated the FCG membership collaborated on a modeling analysis to e stimate the potential impacts of the proposed emission guidelines on Florida's electric generation system. Commenters stated the results of this analysis are intended to be order-o f-magnitude and directionally representative estimates of the potential impacts to Florida's ele ctric generation system and its customers.
Commenters noted that the cost estimates do not inc lude consideration of potential stranded costs, deferral of planned investments, or potentia l technology improvements, including energy efficiency. Commenters provided the following point s regarding their modeling analysis:

• The analysis first determined that Florida's rate i n 2020 under a business-as-usual case would be 1,100 lb/MWh-net. Next, the dispatch was changed from current economic dispatch (Base Case) to a dispatch to try to meet the proposed rule via fuel switching (Change Case), and the rate reduced to 950 lb/MWh-net in 2020 and 900 lb/MWh-net in 2030. Depending on the detail s of rule implementation and future natural gas prices, fuel switching alone is estimated to result in an average cost to Florida electric customers of $3/MW h to $20/MWh. Even with fuel switching, Florida's average emission rate wil l still be significantly greater than EPAs proposed requirement of 740 lb/MWh-net by 2030.

• Importantly, however, this dispatch scenario would increase Florida's dependence on natural gas from 60 percent to around 80 percent , which would materially increase reliability risks resulting from over-reli ance on a single fuel. And even with fuel switching, Florida's average emission rat e will still be significantly greater than EPAs proposed requirement of 740 lb/MW h-net by 2030. Inter-utility purchases incremental to Ten Year Site Plans were n ot estimated, but are not sufficient to avoid new energy sources.

• The analysis focused on the most impactful componen t of the proposal, which is Building Block 2. Because fuel switching alone did not achieve the proposed goal, it then estimated the amount and cost of addi tional low- or zero-emitting generation that would be required in order to reach the proposed 2030 emissions goal for Florida.

• In order to assess the potential impacts of the pro posal over the entire state of Florida, which includes utilities located in two FE RC regions (the FRCC and the SERC), each member utility ran its dispatch model f or its service area for the study cases. The results were then aggregated in or der to represent the entire state. Two cases were run for the years 2020 and 2030: (1) Base Case, business-as-usual in accordance with current utility generation plans and no additional fuelswitching and (2) Change Case, in accordance with B uilding Block 2, NGCC units were increased to a 70 percent capacity facto r and the operation of other generating resources was decreased, using a base ca se natural gas price. Natural gas prices were derived from the current Energy Inf ormation Administration (EIA) fuel price projections. Since increasing natu ral gas demand puts upward349 pressure on gas prices, the change case also evalua ted a high natural gas price forecast from EIA to estimate the cost impact from supply and demand.

• The analysis then attempted to bridge the gap betwe en the change case and compliance. Because the implementation of Building Block 2 resulted in a significant projected gap in the state's average em ission rate between the modeled decrease and the proposed goal of 740 lb/MWh-net, t he analysis estimated the theoretical amount of nuclear power, solar photovol taic (PV) power, or biomass
that would have to be added to reduce emissions fur ther to meet the goal (Building Block 3). Again, the base case and high g as price sensitivity cases were evaluated. The costs of the zero CO2- emitting tech nologies were derived from public information, FPSC filings, and industry stud ies.

• The analysis did not evaluate cost impacts from Bui lding Blocks 1 and 4. Regarding Building Block 1, which focuses on heat r ate improvements at coalfired units, the opportunities for efficiency impro vements are limited, and the resulting very low coal-fired unit capacity factors resulting from fuel switching make Building Block 1 moot. Building Block 4, conce rning substantial increases in demand-side energy efficiency, was not specifica lly evaluated due to limitations of the model and because significant in creases in end-use energy efficiency are out of the control of utilities and regulatory agencies, and ultimately are dependent on the customer. Moreover, Florida ut ilities have been implementing demand-side management (DSM) measures for decades, and as required by the FPSC, have already implemented the more cost-effective measures. Accordingly, EPA's conclusion that substa ntial additional improvements can be made in Florida is unreasonable and unproven.

Comment 31: Some commenters suggested the EPA has not adequate ly considered the competing demands for the available natural gas and /or the contracting mechanisms for that gas.

Response 31: The EPA disagrees. We believe our modeling adequate ly represents competing demand for natural gas – the IPM model uses a natur al gas module that models gas use throughout the economy. In response to additional a nalysis and many comments, we have modified the proposal and RIA; the establishment of CO 2 emission reduction standards is regionally based. The 111(d) final rule requires th at states develop plans that establish emission standards for affected EGUs. We are providing state s with substantial flexibility as to how they structure those plans to achieve the 111(d) require ments. The flexibility includes, for example, the choice of approaches, trading, time to develop plans, additional time before the start of the interim performance period (postponed from 2020 unt il 2022), and the ability to shift emission rate achievement between performance periods. Neith er the Building Blocks nor the IPM analyses are prescriptive, and states may consider local circumstances as they develop their plans, including system reliability, fuel diversity , other regulatory requirements, competing demands for natural gas, and infrastructure. See se ctions V.A, V.B, V.D, VIII.A, VIII.C and VIII.G of the final rule preamble of the CPP and Ch apter 3 of the GHG Mitigation Measures TSD for the CPP Final Rule supporting the final CPP

.350

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

Interruptible supply contracts

Commenters stated that some states operate under in terruptible supply contracts, not primary supply, meaning that current contracts may not supp ort the demand of baseload generation. Commenters noted that in a recent white paper, the PJM RTO pointed out that the changing resource mix is creating greater operational stress on the power system due to the lack of coordination between the commodity market and intra state pipeline. According to the commenters, this lack of coordination affects both generators holding firm transportation contracts and those using interruptible transportat ion contracts. Commenters stated that PJM also pointed out that it is common practice for pipeline s to issue operational flow orders (OFO) that hold gas generators to a ratable (or consistent) ho urly gas consumption over each 24 hour period, which reduces the operational flexibility of a gas unit, and that gas market timing is not in-sync with PJM market timing, meaning this mismatch can r esult in normally low-cost and flexible resources becoming high-cost and inflexible generat ors. Commenters gave an example of this operational stress and inflexibility in a table tha t summarizes delivery interruptions and
constraints in the winter of 2013 - 2014 for Arkans as Electric Cooperative Corporation's (AECC) NGCC Oswald plant, which is connected to Natural Ga s Pipeline Company of America (NGPL).
Commenters stated that the table shows that AECC - despite having a firm gas contract - experienced 66 days in which it did not have the fl exibility to vary the gas consumption at Oswald, and would also have incurred contractual an d financial penalties just to start up the plant from January 5, 2014 through April 7, 2014 due to t he OFO.

Commenters stated that natural gas pipelines have t raditionally been built through long-term firm contracts for the pipeline capacity, and because fi rm contract holders purchase for peak periods, they may have excess capacity that they will releas e or contract to others (using interruptible or secondary firm contracts); because the electric and natural gas systems historically have peaked at different times, this "released" capacity has be en available for use by EGUs without firm
contracts. Commenters indicated that the increased use of natural gas by EGUs, industrial customers and distribution companies creates additi onal competition for this finite existing capacity.

Commenters also stated that an important considerat ion in the proposed re-dispatch of NGCC is the difference in firm and non-firm natural gas sup ply contracts between generators and gas suppliers. Commenters noted that firm natural gas s upply for year-round service is expensive to obtain for generators in a competitive wholesale ma rket. According to the commenters, NGCC units typically are used during peak summer periods when the supply need is greatest and nonfirm gas supplies are utilized; however, if NGCC un its are expected to operate at a higher CF, they would require a secured firm gas supply or fac e supply constraints and/or price spikes forcing limited run time. Commenters added that the price volatility of natural gas is a key determinant with respect to higher utilization rate s for NGCC units, as the fuel cost typically sets the marginal price and associated offers of these u nits in the market.

Demand increase351

Commenters stated that natural gas availability and inadequate pipeline infrastructure hinder the feasibility of achieving a 70 percent NGCC state-wi de capacity factor. Commenters expressed concern regarding the need to expand and update the large-scale needs for pipeline, storage, and other midstream infrastructure, given the likely de mand for natural gas to provide more and more base-load electric utility generation, the potentia l demand from industries such as chemical manufacturing sector, and the unknown growth long-t erm to convert it to liquid natural gas for shipping to the international global energy market. Commenters noted a study done by the
Interstate Natural Gas Association of America Found ation found that the U.S. and Canada will need 28,900 to 61,600 miles of additional natural g as pipelines through 2030 at a cost of $130 to $210 billion between 2009 and 2030. Commenters adde d that pipeline construction and installation is not only a cost issue, but faces la nd use challenges from potential not-in-mybackyard (NIMBY) opponents to locating pipelines ne ar residential, commercial or farm lands.

Commenters stated that the Proposed Rule presumes t here is existing firm gas capacity available to operate all NGCC units at a 70% capacity factor. Commenters stated that interruptible gas contracts are not a reliable option for units to me et high capacity factors (e.g., 60-70% utilization or more). Commenters stated an NGCC unit must have contracts for firm gas to operate at nearly 100% capacity factor to guarantee operations at tho se levels. Commenters stated a unit may not be able to contract for firm gas capacity for only part of a year.

Commenters included a figure illustrating the typic al consumption patterns of the three competing groups of natural gas users, demonstratin g that consumption from the three groups generally creates an "infrastructure use equilibriu m." Commenters stated that if that equilibrium is broken because natural gas generation increases dramatically during the whole year, it is likely that the electric power and natural gas distributio n industries will have to compete for limited pipeline capacity, which can result in natural gas shortages for either power generation or residential heating (for health and safety reasons, gas for home heating traditionally has had priority over natural gas for power generation). Co mmenters asserted that a major expansion of the pipeline network and/or a modification of the r ules governing that market would be required
to avoid such results.

Commenters stated that EPA does not consider the co mpetition for existing pipeline capacity, noting that the electric power sector competes for pipeline services with two other major natural gas consumers: gas LDCs serving both residential an d commercial sectors, and industrial
consumers. Commenters indicated that EPA's assertio n that the pipeline network can support high levels of natural gas-based generation during electric peak hours tells only part of the story. According to the commenters, on an annual basis, na tural gas and electricity consumers traditionally demonstrate counter-cyclical consumpt ion patterns, which help facilitate greater sharing and efficiency in the use of pipeline capac ity - the natural gas peak tends to coincide with the winter heating season, whereas the electric pea k usually occurs in the summer. Commenters believed that by requiring the increased use of nat ural gas for electricity throughout the year, the proposed rule likely would strain the supply of nat ural gas in the winter months, and pointed out that NERC has stated that "though fuel supply conce rns for natural gas-fired generation are more significant during the winter season, difficulties can arise during the summer season."

Commenters stated that the EPA failed to consider t he result of all affected utilities increasing NGCC generation simultaneously. Commenters stated t hat, in that situation, demand for natural352

gas to serve NGCC generation would reasonably be ex pected to increase significantly, which, in turn, would require additional pipeline, compressio n, and storage capacity as well as freeze protection for critical natural gas supply system c omponents to meet demand of all end users during periods of high usage.

Commenters stated the EPA must further consider tha t new and existing NGCC plants will be in competition not only with each other for existing n atural gas pipeline capacity but also with new and expanding export markets for natural gas. Comme nters stated the EPA has not demonstrated that existing natural gas pipeline capacity will be sufficient to meet the needs of all consumers in the market, nor has it analyzed the natural gas pri ce or deliverability impacts that this increased demand may create. Commenters stated the EPA has no t accounted for unpredictable market trends, which will impact Texas's ability to meet E PA's building block 2 target. Commenters
stated that market efficiencies within the natural gas supply and transportation industries will be critical for the delivery of gas to both existing a nd new NGCC plants. Commenters stated the market trends for the past 10 to 15 years, as analy zed by BMcD, indicate that pipeline capacity is most efficiently utilized when held or managed by g as producers and gas marketing firms that direct supplies to different markets and sectors as demand and gas prices fluctuate. Commenters stated the natural gas-fired power plant resources have historically operated as intermediate resources during that timeframe, not at the high ca pacity factors EPA projects. Commenters stated that existing capacity may not be sufficient to meet the needs of all consumers in the market, and capacity constraints could be a more fr equent and prolonged occurrence.

Comment 32: Commenters stated the EPA must account for natural gas needed by other sectors, including residential heating, and should not apply building block 2 during the heating season.

Response 32: The EPA disagrees. We believe our modeling adequate ly represents competing demand for natural gas – the IPM model uses a natur al gas module that models gas use throughout the economy. In response to additional a nalysis and many comments, we have modified the proposal and RIA; the establishment of CO2 emission reduction standards is regionally based and the start of the performance p eriod has been postponed. The 111(d) final rule requires that states develop plans that establ ish emission standards for affected EGUs. We are providing states with substantial flexibility a s to how they structure those plans to achieve the 111(d) requirements. The flexibility includes, for example, the choice of approaches, trading, time to develop plans, additional time before the s tart of the interim performance period (postponed from 2020 until 2022), and the ability t o shift emission rate achievement between performance periods. Neither the Building Blocks no r the IPM analyses are prescriptive, and states may consider local circumstances as they dev elop their plans, including system reliability, fuel diversity, other regulatory requirements, comp eting demands for natural gas and infrastructure. See sections V.A, V.B, V.D, VIII.A, VIII.C and VIII.G of the final rule preamble of the CPP and Chapter 3 of the GHG Mitigation Meas ures TSD for the CPP Final Rule supporting the final CPP.353

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

Commenters stated that the EPA must account for the increasing natural gas demand from (1) industrial and utility facilities that are replacin g coal boilers with natural gas boilers in response to the boiler MACT rule; (2) transportation; and (3 ) the use of DSM as a compliance method which will include converting electricity end-use t o natural gas. Commenters stated that, regardless of the growth in other sectors, the EPA must also ensure the availability of natural gas for residential heating purposes. Commenters stated that building block 2 should not be applied (in full or in part) during the winter heating seas on in order to safeguard home heating supplies.

Comment 33: Commenters stated forcing the system to dispatch th e NGCC fleet to a 70% capacity factor will lead to higher costs than othe rwise might be required under a market-based solution, which would price in the cost of carbon a nd allow the system to be dispatched around

that constraint.

Response 33: The EPA disagrees. The CPP does not force the syste m to dispatch the NGCC fleet to a 70 percent capacity factor. The EPA bel ieves that the CPP provides states with the flexibility, including trading and additional time, to develop plans that consider reliability and local circumstances, The NGCC capacity factor is no t prescriptive, but rather was used to calculate CO2 emission performance rates. See secti ons V.D, VIII.A, VIII.C and VIII.G of the final rule preamble of the CPP and Chapter 3 of the GHG Mitigation Measures TSD for the CPP Final Rule supporting the final CPP.

Comment 34 : Commenters expressed concerns regarding the economi cs of the redispatch proposal.

Response 34: The EPA disagrees that the concerns over the econo mics of generation shifting prevent achievement of the 111(d) final rule goals, and we believe our analysis adequately addresses these issues. The 111(d) final rule requi res that states develop plans that establish emission standards for affected EGUs. We are provid ing states with substantial flexibility as to how they structure those plans to achieve the 111(d ) requirements. The flexibility includes, for example, the choice of approaches, trading, time to develop plans, additional time before the start of the interim performance period (postponed from 2 020 until 2022), and the ability to shift emission rate achievement between performance perio ds. In response to additional analysis and many comments, we have modified the proposal and RI A – the establishment of CO 2 emission reduction standards is regionally based. The Buildi ng Blocks are not prescriptive, and states may consider local circumstances as they develop their plans, including system reliability, fuel diversity, the “useful life” of generation assets, other regulatory requirements and infrastructure. See sections V.A, V.D, VIII.A, VIII.C and VIII.G of the final rule preamble of the CPP and Chapter 3 of the GHG Mitigation Measures TSD for th e CPP Final Rule supporting the final
CPP.354

With respect to lack of economics and claims that t he proposal requires environmental rather than economic dispatch, EPA regards these claims as misunderstanding the proposal. The proposed rule was intended and designed to work wit h current environmental regulations that are consistent with the current security constrained ec onomic dispatch (SCED) protocols and to continue that history of compatibility between env ironmental regulation and economic dispatch. This final rule reinforces that approach by making clear that the concept of emissions rate trading is part of the BSER process and can be implemented consistently with the building blocks on
which it is based. See section V of the final rule preamble of the CPP.

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

Lack of economics in the EPA's re-dispatch proposal

Commenters stated that the environmental dispatch i n the proposed rule used to calculate final CO2 reductions for each state was done randomly by increasing natural gas combined cycle capacity factors to 70 percent regardless of econom ics.

Commenters asserted that EPA mistakenly assumes tha t re-dispatch can be effortlessly and economically achieved. Commenters stated that, if t he State of Mississippi's combined cycle fleet were to run at 70 percent, it would force une conomic dispatch that would raise electricity prices.

Commenters stated that, in order for combined cycle generation to reach a capacity factor above an economic dispatch, such as the 70% level EPA pro posed, the RTO/ISO would, at times, need to cut lower cost resources (i.e., coal, wind) and, as a result, wholesale power prices could increase due to a decrease in the ability to take a dvantage of economic power purchase opportunities.

Commenters expressed concern over the EPA's require ment for sale of electricity generated from natural gas as mandated federally regardless of pri ce. Commenters noted that electricity is currently purchased on an economic basis, and coal has historically been the lowest cost fuel. Commenters noted that the proposal would transform the electricity market form an economic market to an environmental market based on a single environmental consideration -- CO2. Commenters quoted FERC Commissioner Moeller when th e Commissioner said "changing from economic dispatch to environmental dispatch is trul y a fundamental change that would require a complete redesign of markets to include essentially a carbon fee on any resources that emit
carbon dioxide." Commenters stated that such action s would strain utilities' ability to meet demand, especially during extreme weather events. C ommenters also noted that utilities would be required to reconstruct generation portfolios in a short amount of time and at significant costs to businesses and rate payers. Commenters concluded by saying that the EPA has not authority to fundamentally transform the electricity market.

Commenters stated that, by setting the goals at 6% heat rate improvement and 70% NGCC capacity, the states' options may be limited becaus e EPA's proposal changes the current electricity dispatch process which considers cost a nd reliability to adding environmental factors.

Commenters noted that, under the proposed rule, the energy markets of the PJM region (which includes Virginia) may have to shift to an environm ental basis rather than the current economic355

basis. The commenters stated that the objective of economic dispatch is to optimize the electric system so that costs to customers is minimized. The commenters stated that current environmental constraints on generating units exist ing in PJM's markets are limited and do not support the reach of the proposed rule. The comment ers referred to comments made by Commissioner Tony Clark of FERC in relation to PJM' s current treatment of SO2, NOx, and RGGI emission allowance costs neither justifies nor demonstrates the feasibility of extensive and non-economic changes to economic dispatch. The comm enters stated that the complexity of redispatching a system that has been constructed an d operated under a different regulatory and market paradigm is substantial. The commenters note d that given this complexity and the 2020 start date for compliance, it would be difficult to envision how the proposed rule would accommodate economic dispatch; Commissioner Moeller is quoted on wondering how state compliance plans could be implemented in electricit y markets.

Commenters stated the EPA failed to account for the costs associated with uneconomic dispatch of NGCCs at 70 percent capacity factors. Commenters stated the EPA must acknowledge that NGCC capacity factors are driven by market forces, such as fuel-supply costs, and NGCC operational costs will increase with higher capacit y factors due to additional maintenance. Commenters stated the EPA did not appropriately dem onstrate the cost of achieving requirement of BSER. Commenters noted that Indiana's NGCC plant s operated at a combined 53 percent capacity factor in 2012, which is a historically hi gh level of NGCC utilization driven primarily by low natural gas prices. Commenters stated the EP A cannot reasonably expect Indiana's NGCC capacity factors to economically exceed 53 per cent in years with higher natural gas prices than those in 2012 and added that, as expected, Ind iana's average NGCC capacity factors were
lower in 2013 than in 2012 due to increased natural gas prices.

State- and area- specific comments

Commenters stated the CPP's re-dispatch analysis ig nores established dispatch control systems. Commenters stated the CPP's building block 2 fails to account for the generation dispatch structure that exists in a deregulated state. Comme nters stated that, in order to allow for Ohio to dispatch natural gas generating units at a 70 perce nt efficiency rate, dramatic industry overhauls
would be needed.

Commenters noted that Ohio relies upon PJM to opera te the bulk electric system and dispatch generation on a least-cost economic basis. Commente rs stated that, as a restructured state, Ohio depends on PJM and does not use an IRP process to d etermine what classification of generation units must be used, or when generating units can an d cannot run. Commenters stated that market forces provide the necessary incentives for generat ing resources to be built within the state, as well as to determine when existing units will run. Commenters stated that Ohio's generating units may be owned by affiliates of regulated distributio n utilities or may operate as independent merchant generators. Commenters stated that, when d etermining which generators are required to ensure reliability, PJM considers cost and unit efficiency on a locational basis through SCED. Commenters stated the CPP suggests that PJM would n eed to perform environmental dispatch in lieu of economic dispatch. Commenters stated this p laces PJM in an enforcement role for the 13
states and the District of Columbia within PJM's fo otprint. Commenters stated that, logistically, PJM may be faced with numerous dispatch plans that it must consider while also ensuring system reliability.356

Commenters stated that the CPP's environmental disp atch obligation cannot coexist within the
SCED model. Commenters stated that advocates of the current construction of building block 2 have argued that RTOs could maintain the SCED model by artificially adding costs to carbonemitting EGUs to ensure that these units dispatch l ess frequently, or not at all, while at the same time pre-serving the economic market maintained by PJM. Commenters stated this contemplated construct completely ignores the fundamental princi ples upon which SCED was developed: costs for these units would be artificial in nature; unit efficiency would be ignored as no consideration would be given to the technical difficulties associ ated with ramping-up and ramping-down units;
and the SCED model would be decimated. Commenters o pposed any such artificial adders or penalties to the SCED economic marketplace, as the goal of this economic marketplace is to ensure the delivery of reliable electricity to its consumers at affordable rates. Commenters stated that a carbon penalty would drastically increase th e cost of electricity to Ohio consumers and, if coal units are not being utilized efficiently and a re not being dispatched to allow for cost recovery, these plants may close, creating reliabil ity concerns for all Ohio consumers.

Commenters objected to the Clean Power Plan stating that it would negate Colorado's long-held, if implicit, prerogative to choose to rely on econo mic dispatch, and, in its stead, imposes a system of environmental dispatch. Commenters stated that a key concept in the operation of any power system is "economic dispatch." Commenters sta ted that section 1234(b) of the Energy Policy Act of 2005 defines economic dispatch to mea n "the operation of generation facilities to produce energy at the lowest cost to reliably serve consumers, recognizing any operational limits of generation and transmission facilities." Comment ers stated that Colorado electricity consumers are served by multiple power systems whic h use sophisticated software and supercomputers in assigning load to specific genera ting stations to effect the most economical supply as demand varies. Commenters stated that dis patch is so intimately associated with the provision of retail electricity that federal energy regulators have never even thought to challenge the state's authority over this process, save for v ery narrow reliability emergencies. Commenters stated the EPA is asserting the authority to requir e a decrease in the dispatch of coal-fired generation, and an increase of virtually all other resources. Commenters stated that such a de facto natural gas generation quota would profoundly alter the manner in which electricity is dispatched to serve Colorado ratepayers. Commenters stated the EPA's Clean Power Plan incorporates dispatch squarely within EPA's regulat ory purview and cited a technical support
document to the rule:

Reduced generation is encompassed by the terms of t he phrase "system of emission reduction" in Clean Air Act section 111(a)(1) because, in accorda nce with the above-discussed definitions of "system," reduced generation is a "set of things" w hich included reduced use of generating equipment and therefore reduced fuel input that the affected source might take to reduce CO2 emissions. (Legal Memorandum for Proposed Carbon Po llution Emission Guidelines for Existing Utility Generating Units, at 13-14.)

Carbon price

Commenters stated that implementation of Building B lock 2 should not be achieved by means of artificial manipulation of dispatch processes. Comm enters suggested that States should be encouraged to implement procedures to develop and p romote market-based mechanisms (such as a price on carbon) that would effectively alter the bid structure within the electricity market and357

thereby change the dispatch of resources. Commenter s also suggested that market based mechanisms could be the favored approach for buildi ng blocks 3 and 4. Commenters stated that White tags and Renewable Portfolio Standards for ex ample could be effective means of implementation, tracking and retirement.

Commenters stated that even if the rule itself does not mandate a price on carbon, given EPA's and states' limited ability to control dispatch dir ectly, as well as the obstacles to achieving the full emissions reductions under the other Building Blocks, establishing a price on carbon would likely be a dominant tool to effectuate Building Bl ock 2, particularly in competitive electricity markets like Pennsylvania. Commenters stated Homer City needs an alternative compliance mechanism to recoup its capital investments. Commen ters referred to EPA modeling 55 and stated that, (1) due to rising natural gas prices the capa city factor of existing NGCC declines from 52% in 2020 to 42% in 2030, (2) to overcome this declin e, in its IPM modeling of Options 1 and 2, EPA chose to use a structure that put a price on ca rbon, and (3) in its policy cases, the capacity factor of NGCC units rises above the base case, but still does not reach 70%. Commenters stated that the EPA states that the NGCC capacity factor s tays below 70% because states choose "alternative CO2 reduction strategies" other than r e-dispatch to meet their goals. Commenters stated that modeling of Pennsylvania's target emiss ion rate predicted a carbon price of $39.38 in 2011 dollars, which is equivalent to approximately $50 in 2030 dollars. Commenters stated, at this carbon price, a significant "alternative" stra tegy referenced by EPA is the backing out of coal from the generation mix. Commenters stated that the fact that EPA uses a car bon price constraint to model its options illustrates the double-edged s word of Building Block 2 for coal-fired power plants. Commenters stated that, to demonstrate comp liance with its proposed target of 1,052 lb CO2/MWh-net, Pennsylvania will be forced either to establish a price on carbon or essentially mandate the shutdown or reduced dispatch of coal-fi red units. Commenters stated that both approaches would impose fatal blows to coal units; the only difference would be timing. Commenters stated that the latter would be quick, b ut the former, establishing a price on carbon, would impose a slow death by stripping all cash fro m coal-fired facilities, a fact confirmed by EPA's IPM model runs that, under Option 1 (state ca se), have Units 1 and 2 retiring by 2025 and margins for Homer City Unit 3 declining precipitous ly. Commenters stated that, through 2030, revenue for energy and capacity remains relatively flat for Homer City Unit 3, while the carbon cost per MWh increases, which lowers Unit 3's energ y and capacity margin on a $/kw-yr basis from $105.56 in 2016 to $70.79 in 2030, which is lo wer than the Unit's fixed operation and maintenance costs of $73.33/Kw-yr.

Comment 35: Commenters supported an environmental dispatch appr oach.

Response 35: The EPA disagrees that the 111(d) final rule mandat es an approach. The CPP does not force the system to dispatch the NGCC fleet to a specific capacity factor, nor does it force a proportionate dispatch protocol. The 111(d) final rule requires that states develop plans that

establish emission standards for affected EGUs. We are providing states with substantial flexibility as to how they structure those plans to achieve the 111(d) requirements. The flexibility includes, for example, the choice of approaches, tr ading, time to develop plans, additional time before the start of the interim performance period (postponed from 2020 until 2022), and the ability to shift emission rate achievement between performance periods. In response to additional358

analysis and many comments, we have modified the pr oposal and RIA; the establishment of CO2 emission reduction standards is regionally based. T he Building Blocks are not prescriptive, and states may consider local circumstances as they dev elop their plans, including system reliability, fuel diversity, the “useful life” of generation ass ets, other regulatory requirements and infrastructure. See sections V.A, V.D, VIII.A, VIII .C and VIII.G of the final rule preamble of the CPP and Chapter 3 of the GHG Mitigation Measures TS D for the CPP Final Rule supporting the

final CPP.

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

Commenters stated that environmental dispatch limit ation is an easily achievable and straightforward way for EPA to bolster the Clean Po wer Plan's efficacy and achieve greater CO2
reductions. Commenters stated there are no demonstr ated advantages to the proportionate redispatch protocol described in EPA's rule, and the agency has not explained (nor provided record support for) its decision. Commenters stated that, if the Clean Power Plan is to reflect the best system of emission reduction, as the Clean Air Act requires, EPA must adopt the environmental dispatch limitation approach described by the comme nters. Commenters supported the EPA's
technical determination that states can scale down utilization of their steam EGUs consistent with an increase in NGCC dispatch up to a 70 percen t capacity factor without jeopardizing electric system reliability. Commenters explained t hat manufacturers of NGCC units have confirmed their technical ability to operate at 70 percent capacity factors and eGRID data reveal that 94 NGCCs operated at capacity factors of 70 pe rcent or higher in 2012.

Commenters suggested the EPA employ an environmenta l dispatch limitation for Building Block 2, which would assume that dispatch of the highest emitting sources, typically coal-fired EGUs is limited first, while the O&G steam fleet would redu ce its dispatch only if additional NGCC capacity (up to 70 percent) remained after coal gen eration is reduced to zero. Commenters stated the EPA must reconsider the way it allocates reduce d dispatch among the coal and O&G steam fleets. Commenters stated the EPA's current proposa l follows a proportionate re-dispatch model with regard to coal and O&G steam units. Commenters stated that this approach, which EPA fails to justify or explain, results in a less stri ngent emission limitation, since existing O&G steam units generally emit 20-30 percent less CO2 p er MWh than existing coal-fired plants. Commenters stated that, by preserving the historical ratio of coal-to-O&G steam in its standard-setting process, EPA fails to apply the be st system of emission reductions. Commenters
referred to Table 4 in their comments and stated th at, for example, in Louisiana, an environmental dispatch limitation approach would re duce the state's final emission target by approximately 6.5 percent, which is greater than th e reductions for that state expected under Building Block 1. Commenters stated that, on a nati onal level, this approach to dispatch limitation would reduce CO2 emissions by around 12 million tons per year, approximately onesixth of the reduction that will be through Block 1 's heat rate improvements across the nation's
coal-fleet. Commenters stated that an environmental approach to dispatch limitation could expect simple cycle gas-fired combustion turbines that ope rate at capacity factors more suited for loweremitting NGCCs (i.e., load-following and base load uses above a 10 percent capacity factor) to reduce dispatch in favor of available NGCC capacity , which would reduce the use of natural gas
and would cut emissions even further.359

Commenters recommended that Block 2 dispatch should be restructured to set targets based on dispatch to the least-emitting power source availab le at the time the energy is needed, favoring, in descending order, zero-carbon renewable generati on, most efficient natural gas generation, and least efficient gas generation. Commenters stat ed this least-emitting dispatch hierarchy should replace a least-cost coal- to natural gas-fi red unit dispatch regardless even of the latter's relative efficiency within its source class. Commen ters urged the EPA to adjust its Block 2 targets based on establishing this system as BSER f or the Proposed Rule.

Commenters recommended the EPA, at a minimum, model the impact of the Proposed Rule through 2050 and beyond. Commenters stated that, as Block 2 is presently structured, it is designed to result in a significant increase both i n the amount of gas-generated power and the
construction of new NGCC facilities. Commenters sta ted that, according to the EPA, the twoblock approach (heat rate improvement plus dispatch ing) results in a gas production increase of 19-22 percent, and its four-block approach in an in crease of 12-14 percent; both approaches result in construction of additional NGCC capacity by 2020, with 11-18 GW of new NGCC for the two-block approach and 20-22 GW of new NGCC cap acity for the four-block approach. 192 Commenters stated the EPA projects that the situati on improves for 2030, where RE and EE begin to displace the increased natural gas generat ion: according to EPA, by 2030 the two-block approach results in 5-17 GW of new NGCC capacity, w hile the four-block approach results in 32-35 GW less NGCC capacity relative to the base ca se. Commenters stated the EPA's projection ignores the fact that as is now the case with coal plants trying to maximize their useful life to the very end, these newly constructed NGCC plants similarly will seek to extend their lives as long as possible and will continue to emit CO2 for many decades to come. Accordingly, EPA must, at a minimum, model the impact of the Pro posed Rule through 2050 and beyond. Commenters encouraged the EPA to analyze the dispat ch proposal taking into account the full life cycle of greenhouse gas generation of both coa l and natural gas. Commenters noted that natural gas generates about 40% fewer CO2 emissions than coal during combustion.

Commenters stated the current dispatch scheme creat es disincentives for both renewable energy and demand-side efficiency measures, a result that severely hampers America's transition away from fossil fuels. Commenters acknowledged that som e fossil fuel use will be needed for some time to come, for reasons including overcoming chal lenges related to the intermittency of solar and wind generation. Commenters stated a least-emit ting dispatch hierarchy takes these factors into account. Commenters stated dispatch to renewab le energy would occur only when it is available (and thus would not affect reliability) b ut when it is, it would be preferred over sources that emit more CO2; and if a more efficient natural gas plant could be used, the less efficient one would not. Commenters asserted that States may, of course, ignore dispatch altogether and choose to use other means of reaching their targets , but, as with all other elements of EPA's fourblock BSER approach, EPA's emissions target will ch ange, becoming more stringent in this instance, if its dispatch regime-derived target is based on least-emitting fuel switching which, in turn, will lead to higher state targets and a great er likelihood that states would follow the path EPA sets. Commenters stated that a least-emitting d ispatch system would incentivize, rather than displace, investment and infrastructure build-out f or renewable energy.

Commenters stated there is no doubt that a least-em issions dispatch or loading order is adequately demonstrated. Commenters stated it would also incentivize Block 1 heat rate improvement measures within the existing power plan t fleet. Commenters stated that a least-360

emissions dispatch system is not a novel concept, r ather, it is adequately demonstrated, as a similar system is already in place in California, t he country's most populous state, where renewable energy resources are being integrated int o the loading order so as to generate the least possible amount of GHG emissions from the power sec tor. Commenters stated that, under this plan, California has set a target to meet 33% of it s energy needs from renewable resources by 2020. Commenters stated the system requires dispatc h capabilities at renewable energy sources that allow them to decrease or increase their energ y output in response to dispatch instructions or automated control signals, and it incentivizes the development of clean energy technology while ensuring reliability at reasonable rates. Commenter s stated that its loading order places energy efficiency and demand response as its top prioritie s (further enabling integration of intermittent energy), and calls for the use of renewable resourc es and distributed generation over fossil fuelgenerated power. Commenters stated that, similarly, the states participating in the Regional Greenhouse Initiative have several years of experie nce with factoring CO2 emissions limits directly into their dispatch bids.

Commenters requested the EPA to model least-dispatc h generation's technical feasibility as well as its cost-effectiveness, or explain why it will n ot do so. Commenters stated that costs and benefits are among the factors the EPA must conside r when establishing BSER, and that EPA's proposal for coal-to-gas dispatch is based in large part on the current supply of cheap natural gas. Commenters stated that, as EPA observes, dispatch r ecords show that the rate of dispatch from coal plants to natural gas plants has increased sig nificantly during recent years as gas prices fell to historic lows (and as the current least cost dis patch scheme would dictate). Commenters stated that the EPA bases Block 2 on its prediction that t he economic advantage of using natural gas will continue unabated and thus that dispatch to ga s-fired generation is BSER. Commenters stated that, in devising Block 2 the EPA did not co nsider integrating renewable energy into the dispatch hierarchy. Commenters stated the EPA did n ot calculate the costs of doing so, and it certainly did not take the social cost of carbon in to account, an essential requirement if renewable energy is to be measured against fossil f uels on a level playing field. Commenters stated that shifting Block 2 from a coal-to-gas dis patch system to a least-emissions dispatch system is likely to have only modest price impacts. Commenters stated that RE costs are falling at impressive rates, and some RE is already cost-co mpetitive with natural gas generation. Commenters stated that, in its discussion of Block 3, the EPA itself recognizes that the costs of RE expansion are modest. EPA observes that:

• Several studies have found the cost of RPS-driven R E deployment to be modest. One comparative analysis that synthesize[d] and ana lyze[d] the results and methodologies of distinct state or utility-level RP S cost impact analyses found the median change in retail electricity prices to be $0 .0004 per kilowatt-hour (only a 0.7 percent increase), the median monthly bill impa ct to be between $0.13 and $0.82, and the median CO2 reduction cost to be $3 p er metric ton.

Commenters stated that (1) like coal-to natural gas dispatch as proposed by EPA, least-emissions dispatch would recognize any operational limits of generation and transmission facilities, including peaking, cycling, base load constraints, and reliability and (2) like EPA's proposal, least-emissions dispatch would factor in availabili ty for natural gas plants, consisting of planned and unplanned maintenance and unplanned outages, an d for renewable energy, those events as
well as the intermittent nature of some renewable e nergy generation. Commenters stated that,361

unlike EPA's proposal, however, least-emissions dis patch puts renewable energy sources ahead of natural gas plants and creates a strong inventiv e to invest in emission-free power generation. Commenters stated that incentivizing renewable ener gy in this manner would also support an expansion of emissions reductions that come from Bl ock 3.

Comment 36: Commenters stated the EPA should abandon its propo rtionate redispatch approach in favor of environmental redispatch.

Response 36: For the EPA’s response to this comment, please see the response to Comment 34
in 3.2.4.

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

In comments on the Tribal & Territorial supplementa l proposal, commenters stated that, to the extent that a jurisdiction curtails dispatch from i ts steam EGUs under Block 2, it should not seek to preserve the existing balance of generation from different classes of units within the steam EGU fleet, but should ensure that the different cla sses reduce their dispatch in order of their emission rates. Commenters noted that, in the U.S. territories, where steam generation is prevalent, this may make a considerable difference. Commenters stated the EPA should both follow an environmental redispatch model and quanti fy the additional reductions that can be achieved by requesting data from the utilities and/ or regulatory authorities in the territories.

Comment 37: Commenters stated the EPA's BSER ignores the fact that NGCCs tend to be more prone to catastrophic failure during operation than coal-fired units.

Response 37: The EPA disagrees that we have inadequately analyze d this issue. Our analysis and modeling uses current data on NGCC availability , which reflects historical differences in failure rates. See model documentation as http://e pa.gov/powersectormodeling.

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

Commenters stated that, despite diligent maintenanc e and significant expenditures on long-term service agreements, NGCCs tend to be more prone to catastrophic failure. Commenters stated that, for example, the Vann Plant's steam turbine s uffered a catastrophic blade failure on July 7, 2014 that resulted in a two month forced outage of the entire Vann Plant. Commenters stated that, during such forced outages, which may happen regardless of the extreme care taken by PowerSouth at its NGCCs, PowerSouth's available cap acity would be significantly diminished and fall short of the expected 70 percent capacity factor.

Comment 38: Commenters stated the Proposed Rule does not take i nto consideration time and costs impacts resulting from non-Clean Air Act regu lations that will impact the ability of states362

to require large-scale fuel switching from coal to natural gas to achieve their CO2 reduction goals.

Response 38: The EPA disagrees with the interpretation of the re quirements of the 111(d) final rule, and we disagree that we have not adequately c onsidered regulatory requirements on the system. The 111(d) final rule requires that states develop plans that establish emission standards for affected EGUs. We are providing states with sub stantial flexibility as to how they structure those plans to achieve the 111(d) requirements. The flexibility includes, for example, the choice of approaches, trading, time to develop plans, addi tional time before the start of the interim performance period (postponed from 2020 until 2022) , and the ability to shift emission rate achievement between performance periods. In respons e to additional analysis and many comments, we have modified the proposal and RIA; th e establishment of CO2 emission reduction standards is regionally based. The Buildi ng Blocks are not prescriptive, and states may consider local circumstances as they develop their plans, including system reliability, fuel diversity, the “useful life” of generation assets, other regulatory requirements and infrastructure. See sections V.A, V.D, VIII.A, VIII.C and VIII.G of the final rule preamble of the CPP and Chapter 3 of the GHG Mitigation Measures TSD for th e CPP Final Rule supporting the final
CPP.

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

Commenters indicated the EPA's analyses failed to c onsider FERC rules and other non-Clean Air Act statutory and regulatory requirements. Commente rs stated that it is impossible to implement Building Block 2 because FERC regulation preempts m any of the actions Building Block 2 assumes the States will take. Commenters (reference d NERC documents and) stated that (1) new interstate natural gas transmission facilities must receive FERC review and authorization, (2) FERC generally does not authorize new pipeline capa city unless customers have already committed to using it (i.e., have firm delivery con tracts), and (3) pipelines are prohibited from charging the cost of new capacity to their existing customer base. Commenters stated that, to ensure that pipeline capacity closely matches the n eeds of new customers, FERC approves new facilities and facility improvements only after new customers have requested firm service. Commenters asserted that, if all of the pipeline's firm customers use their full capability, then there will be little or no excess pipeline capacity to support NGCC units' efforts to achieve the 70% capacity factor target.

Commenters stated that other federal statutes that affect the construction of interstate natural gas pipelines include the Clean Air Act, Clean Water Ac t, the Endangered Species Act, the Coastal Zone Management Act, the Fish and Wildlife Coordina tion Act, the Historic Preservation Act, the Rivers and Harbors Act, the Mineral Leasing Act , the Federal Land Policy Management Act,
and the Wild and Scenic Rivers Act. Commenters stat ed that permits for associated environmental issues such as endangered species are a moving target, as the U.S. Fish and Wildlife Service is currently making listing decisi ons on 250 candidate species through 2018. Commenters stated that a host of federal, state, re gional, and local approvals are necessary for pipeline construction to begin. Commenters noted th at urban development has encroached on many existing pipeline right-of-ways, thereby makin g some expansions parallel to existing pipelines difficult to implement and noted that pro jects often are opposed by multiple stakeholders, including landowners, environmentalis ts, and others with competing interests.363

Commenters suggested that FERC, under the Energy Po licy Act of 2005, may be able to streamline this process in order to facilitate expe ditious development of pipeline capacity, or it may become even more time consuming and difficult t o construct natural gas pipelines.

Commenters indicated that the EPA did not consider the role of Endangered Species Act (ESA) regulations on the natural gas pipeline permitting process or new Department of Transportation regulations that require the retrofitting of existi ng natural gas pipelines to improve their safety.
Commenters added that the EPA did not take into acc ount its own pending regulations to eliminate polychlorinated biphenyls (PCBs) along pi peline segments with new non-PCB
materials. Commenters asserted that it is fair to a ssume that the application of such regulations will add time and costs to the development of the i nfrastructure required to support the new gas generation - the EPA should have factored this into its analysis.

Comment 39: Commenters stated that the EPA's analysis contains significant errors and data quality issues suggested EPA should withdraw the cu rrent proposal, address these concerns, and publish a new proposed rule for public comment.

Response 39: The EPA disagrees.We have reviewed the calculations for Building Block 2 and

believe these concerns are either incorrect. The 11 1(d) final rule has been modified since proposal and the analysis was redone. See the Regu latory Impact Analysis for the final CPP.

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

Commenters stated the EPA made significant errors t hat overstate the reductions in CO2 rates that building block 2 could achieve, even if implem entation were possible. Commenters stated the net result of these errors alone (using EPA's m ethod) is that building block 2's contribution to Texas's goal would be 60 pounds CO2 per megawatt-ho ur less than EPA calculates.

Commenters stated that EPA's analysis contains an e xtensive number of methodological errors and data quality issues which erode the fundamental credibility of building block 2 and the entire proposal. Commenters stated that any attempt to cor rect the litany of concerns or determine how these corrections alter state goal calculations, co mpliance strategies, reliability evaluations, and cost-benefit analyses is too complex to complete wi thin the public comment period. Commenters suggested EPA should withdraw the current proposal, address these concerns, and publish a new proposed rule for public comment.

Commenters stated that the EPA makes calculation er rors that directly impact the proposed goals. Commenters stated that substantially more na tural gas generation will be required to meet the CPP's goals than EPA estimates. Commenters stat ed the EPA's calculations assume a 400 TWh/year shift to existing NGCC generation from coa l (376 TWh/year) and older oil-gas steam (64 TWh/year) and the EPA estimates that the NGCC m arket will increase from 29 percent of the country's energy in 2013 to 33-34 percent of th e nation's energy from 2020-2030. Commenters stated that, for NGCC to be 35 percent o f the country's total energy in 2020, 39 percent in 2030 and 49 percent 2040, an additional 400-450 TWh/year increase in NGCC generation will be required. Commenters stated that , with these miscalculations underestimating364

the needed NGCC, EPA's CPP also underestimates the substantial investment in NGCC that will be necessary.

Comment 40: Commenters asked for clarification regarding units under used in 2012 and the 70% capacity factor.

Response 40: For the EPA’s response to this comment, see section V.D of the final rule preamble of the CPP.

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

In integrating BB 2 into state goals, why did the E PA treat units that were in outages for 11 months of the year, but operated at 100% capacity f or the 12th month, the same way that it treated units that operated for a full year at an 8 .3% (i.e., 1/12) annual capacity factor?

Why did the EPA determine that the top 10% of NGCC units, operating at a 70% capacity factor, was technically feasible for the entire fleet? What were the characteristics of this top 10%? How did EPA determine that the top 10% is representativ e of the entire fleet?

The EPA justifies its 70% capacity factor target in part by stating that national average capacity factors are relatively high during hours of peak de mand. In the preamble the EPA states that average capacity factor is 60% or higher during pea k hours of the day, but in the TSD, the EPA states that average capacity factor is only approxi mately 50%" during peak hours. The
commenters asked which is correct?

Comment 41: Commenters requested clarification of the items in the GHG Abatement Measures TSD, page 3-14:

Response 41: The EPA thanks the commenters for these comments. The TSD has been revised for the final rule. See the GHG Mitigation Measure s TSD in the docket for this rule.

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

Commenters requested clarification of the discussio n regarding the availability of NGCCs is confusing and seems to suggest that the availabilit y of "advanced" NGCCs is higher than that of lower firing temperature NGCCs. Commenters recommen ded that the EPA clarify the
discussion.

Commenters recommended the EPA clarify or correct a discrepancy in two sets of numbers cited as coming from the same data file regarding the CO2 emission rate. Commenters referred to page 3-5 under the heading "Historical Context" where th e CO2 emission rate of U.S. coal power plants is stated to be 2,200 lb/MWhr and that of NG CCs is 907 lb/MWhr and page 3-10, footnote 53 which refers to CO2 emission rates of 2,354 lb/M Whr for coal and 926 lb/MWhr for NGCC.365

Commenters referred to Table 3-6, stated the base c ase has an NGCC capacity factor of 52% which is significantly higher than the value in 201 2, and suggested the EPA clarify whether this is due to the assumed impact of planned coal unit r etirements and NGCCs taking up the slack or
another reason.

Commenters recommended EPA clarify its assumptions for the potential magnitude of LNG exports to the potential price of natural gas. Comm enters referred to the final sentence on page 3- 10 regarding an expected increase in natural gas pr oduction of 20% between 2012 and 2020, suggested that it is important to evaluate what is expected to be consumed by the LNG export facilities which have recently been approved, and n oted that EPRI estimates 3.6 trillion cubic feet (TCF) per year have already been approved and another 3.6 TCF is under review by DOE.

Commenters stated there is a mismatch between numbe rs in the reference document and the costbenefit memo and provided the following information :

Page 3-11: "Adding in the existing sources that wer e not yet online in 2012 (under construction) increases total NGCC generation calculated in the g oal setting to 1,444TWh." This would represent a 50% increase over what was produced in 2012, which was a record year; however, in the "Building Blocks" memo TSD, EPA predicts NGCC p ower production in 2030 will be 1,743TWh, which is 178% of the 2012 value. That imp lies a significant increase in natural gas consumption versus today. For 2020 EPA predicts NGC C power production will be 1,369TWh,
which shows a mismatch between what is in this refe rence document and what is in the costbenefit calculation memo.

Commenters disagreed with a calculation regarding t he heat rate of NGCC units and provided the following information:

Page 3-12: "For comparison, NGCC generation growth of 450TWh (calculated in goal setting) would result in increased gas consumption of roughl y 3.5 TCF for the electricity sector." There is
a miscalculation here based on what is stated in Fo otnote 69 where the heat rate of an NGCC is assumed to be 10,000 Btu/kWhr. EPRI believes this i s too high. To get 3.5 TCF from 450TWh of electricity one has to assume a heat rate of 7,9 64 Btu/kWhr. However, EIA estimates the electric power sector consumed 9.1 TCF of natural g as in 2012.23 Consuming an additional 3.5 TCF of natural gas would mean an increase of 38.5%, but that does not seem to match with the statement on page 3-11 that NGCC generation would i ncrease by 50%. Although the amount of power produced by simple cycles might be large enou gh to account for this discrepancy, the modeling results in the cost-benefits memo show onl y a very small amount of power being generated by simple cycles.

Commenters recommended the EPA clarify the discussi on on page 3-14, stating the discussion is confusing and seems to suggest that the availabilit y of "advanced" NGCCs is higher than that of lower firing temperature NGCCs.

Commenters stated that additional rationale would b e useful regarding the discussion on page 3- 20 of the assumptions that went into the EPA's IPM predictions. Commenters referred specifically to an assigned CO2 charge to units tha t produced CO2 at a rate greater than 1,100
lb/MWhr.366

Commenters suggested the EPA clarify the second sen tence at the top of page 3-26 where it is stated: "This is because only 29 state goals are pr emised on the existing NGCC fleet achieving an average capacity factor of 70 percent. Consequen tly, a 70% utilization rate target for the existing NGCC fleet requires an average national ca pacity factor of 63 percent."

Comment 42: Commenters stated there is nothing in the language of CAA 111(d) that even remotely suggests that the EPA has the authority to set limits or require emission reductions for existing sources premised on the construction of ne w sources. Commenters said in addition, as with the other approaches discussed in the NODA the EPA has failed to undertake the requisite economic and technical analysis needed to adequatel y demonstrate that the re-dispatch to new gas sources concept represents BSER. Commenters sta ted thus, the EPA is precluded from applying this approach in the final rule.

Response 42: The EPA disagrees. Our legal interpretation is pro vided, and we have conducted extensive technical and economic analysis to suppor t this final rule. The determination of BSER does not depend on any technical analysis of constr uction of new EGU’s. See sections V.A, V.D, VIII.A, VIII.C and VIII.G of the final rule preambl e of the CPP, Chapter 3 of the GHG Mitigation Measures TSD for the CPP Final Rule supp orting the final CPP, and the Regulatory Impact Analysis of the final CPP.

3.2.5 Analysis of Cost-Effectiveness

This section discusses issues related to the cost-e ffectiveness analysis that the EPA carried out for building block 2 at proposal.

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

Comment 1: Commenters stated that the cost-effectiveness of NG in redispatch is constrained by high gas prices and the price response assumptio ns in IPM.

Response 1: The EPA disagrees – we believe the IPM modeling is conservative and demonstrates that the goals of the rule are achieva ble. The 111(d) final rule requires that states develop plans that establish emission standards for affected EGUs. We are providing states with substantial flexibility as to how they structure th ose plans to achieve the 111(d) requirements. The flexibility includes, for example, the choice o f approaches, trading, time to develop plans, additional time before the start of the interim per formance period (postponed from 2020 until 2022), and the ability to shift emission rate achie vement between performance periods. In response to additional analysis and many comments, we have modified the proposal and RIA –
the establishment of CO2 emission reduction standar ds is regionally based. The Building Blocks367

are not prescriptive, and states may consider local circumstances as they develop their plans, including system reliability, fuel diversity, the “ useful life” of generation assets, other regulatory requirements and infrastructure. See sections V.A, V.D, VIII.A, VIII.C.1 and VIII.G.2 of the final rule preamble of the CPP and Chapter 3 of the GHG Mitigation Measures TSD for the CPP Final Rule supporting the final CPP.

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

Commenters stated that the potential cost-effective role of additional use of natural gas in the redispatch of existing and new NGCC units, as well as through gas co-firing in coal units, is constrained by the high gas prices and gas price re sponse assumptions (i.e., gas price elasticity) in the EPA's IPM modeling analysis. The commenters noted that the gas price forecast in the June 2014 IPM base case (adjusted to nominal dollar s using a 1.5 percent annual inflation rate) starts at $5.70/MMBtu in 2020 and rises to $7.00/MM Btu by 2025. The commenters noted, in contrast, that recent NYMEX prices (in nominal doll ars) start at just $4.43/MMBtu and only rise to $4.84/MMBtu during the same period. The commente rs remarked that this means the June 2014 base case IPM prices are 30 percent to 45 perc ent higher than current NYMEX prices and suggests that the cost of production and quantity o f gas resources underlying the IPM estimates are overly conservative compared to current market expectations. The commenters added that since current NYMEX prices are well within the rang e of NYMEX prices over the last year, this conclusion is not the result of a temporary or unus ual pattern of NYMEX prices, but a more basic shift. The commenters noted that several prop osed findings in the CPP are sensitive to the EPA's assumptions regarding gas price elasticity in cluding the 70 percent ceiling for existing gas
unit utilization in BB2 and the decision not to inc lude new NGCC or gas co-firing in the BSER determination and state goal calculation methodolog y.

References Cited:

192 Ventyx, "NYMEX Henry Hub Natural Gas Futures" a vailable at: http://www.ventyx.com/en/solutions/businessoperatio ns/business-products/velocity-suite

Comment 2: Commenters stated that the EPA's analysis in GHG T SD using 2011/2012 NG prices is inaccurate.

Response 2: The EPA disagrees. Our analysis of the 111(d) fina l rule as presented in the Regulatory Impact Analysis of the final CPP include s higher natural gas prices and EPA believes

that the estimated costs are conservative. We belie ve 2012 is appropriate. See section VI.D of the preamble to the final CPP and the Regulatory Im pact Analysis of the final CPP.

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

Commenters stated that, contrary to EPA's analysis in the GHG Abatement Measures TSD in which the EPA notes that advances in the production of natural gas have helped to reduce natural gas prices - using 2011/2012 in the analysis suppor ting the proposed rules - 2012 is not representative of natural gas prices and, in fact, represents the lowest price year in the past 12368

years. The commenters recommended the EPA either se lect an earlier year where prices were higher or use an average of multiple years to captu re the variability in natural gas prices. Commenters provided a graph, which shows U.S. EIA p lot of NG annual avg $/Mcf cost from 2002-13, showing 2012 as lowest cost during this pe riod.

Comment 3: Commenters stated that the EPA needs to consider t he impact of firm capacity

contracts.

Response 3: The EPA disagrees that we have inadequately consid ered the economic features of the utility power and natural gas sectors. The 111( d) final rule requires that states develop plans
that establish emission standards for affected EGUs . We are providing states with substantial flexibility as to how they structure those plans to achieve the 111(d) requirements. The flexibility includes, for example, the choice of approaches, tr ading, time to develop plans, additional time before the start of the interim performance period (postponed from 2020 until 2022), and the ability to shift emission rate achievement between performance periods. In response to additional analysis and many comments, we have modified the pr oposal and RIA – the establishment of CO2 emission reduction standards is regionally base d. The Building Blocks are not prescriptive, and states may consider local circumstances as they develop their plans, including system reliability, fuel diversity, the “useful life” of g eneration assets, other regulatory requirements and infrastructure. See sections V.A, V.D, VIII.A, VIII .C.1 and VIII.G.2 of the final rule preamble of the CPP and Chapter 3 of the GHG Mitigation Measure s TSD for the CPP Final Rule supporting
the final CPP.

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

Commenters stated that the EPA needs to recognize t hat the links between power markets and pipeline construction make it difficult to develop the pipeline system in a way that allows states to comply with the proposed rule. Specifically, the commenters stated that the EPA's assumptions about increased natural gas use ignore the firm capacity contracts used in the industry. The commenters noted that natural gas pip elines have traditionally been financed through long term, firm capacity contracts signed b y natural gas consumers, such as local distribution companies, utilities and industrial co nsumers, and that natural gas pipelines are built when demand for natural gas can be translated direc tly into these contracts.

Commenters also noted that some power generators, e specially in RTO/ISO markets, only recover costs when they run at peak, and so are unw illing to sign firm capacity contracts, but rely
on more flexible and affordable non-firm or interru ptible contracts. The commenters stated that changing this practice of not using long term, firm capacity contracts may require institutional and regulatory changes that take time, particularly in areas with organized markets where generators cannot pay the premium required to purch ase firm pipeline service and remain competitive in wholesale electric markets. The comm enters referenced an example in the February 2014 EIA report on natural gas issues and trends in New England, in which Spectra Energy announced a capacity expansion of its Algonq uin pipeline of 1 Bcf/day in 2011 but that, in 2013, the proposed expansion was reduced by 65 p ercent to 0.33 Bcf/day, due to lack of interest in long-term firm transport capacity contr acts, despite identified reliability concerns369

related to insufficient capacity. The commenters no ted that the report additionally found that public utility commissions require utilities to see k approval for signing long-term contracts and the rate changes required to pay for them, whic h increases the uncertainty of when, and if, pipeline expansions occur.

Comment 4: Commenters stated that the EPA needs to consider th e competing demands on natural gas infrastructure when calculating achieva ble NGCC utilization rates.

Response 4: For the EPA’s response to this comment, please see the response to comment 34 in

section 3.2.4.

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

Commenters stated that the EPA must consider the co mpeting demands on natural gas infrastructure when calculating achievable NGCC uti lization rates. The commenters asserted the electric power sector competes for pipeline service s with two other major natural gas consumers: gas LDCs serving residential/commercial sectors and industrial consumers. The commenters added that consumption by the electric generators d oes not necessarily coincide with consumption in the natural gas transmission system. The commenters stated that a pipeline network supporting high levels of natural gas-based generation during electric peak hours is only part of the picture as, on an annual basis, natural gas and electricity consumers traditionally demonstrate counter-cyclical consumption patterns, helping facilitate greater sharing and efficiency in the use of pipeline capacity. The com menters added that gas peak tends to coincide with the winter heating season, whereas electric pe ak usually happens in summer. Increased utilization of NGCC units to 70% as sought by the E PA, according to the commenters, will likely result in competition between the electric utility and the LDC for the same gas infrastructure, thus the EPA needs to further analyze this integrat ed supply issue.

The commenters further stated that, traditionally, pipelines have been built through long-term, firm contracts for the pipeline capacity. Because f irm contract holders purchase for peak periods, the commenters stated, they may have excess capacit y that they will release or contract to others (using interruptible or secondary firm contracts). The commenters stated that because the electric and natural gas systems historically have peaked at different times, this "released" capacity was available for use by EGUs without firm contracts. A ccording to the commenters, the increased use of natural gas by EGUs, industrial customers an d distribution companies will increase additional competition for this finite existing cap acity.

The commenters asserted there are natural gas trans mission constraints that will limit increases in natural gas-fired generation in Missouri. For ex ample, the commenters stated Southern Star Central Gas Pipeline's Line Segment 235 serves KCP& L's Hawthorn, South Harper, Greenwood and Ralph Green 3, and Kelson Energy's Dogwood Ener gy Center. Assuming there is no other demand on Line Segment 235, asserted the commenters , it does not have sufficient capacity to serve the simultaneous maximum hourly flows for all of these units; even though Dogwood and South Harper also have access to Panhandle Eastern Pipeline, only recently has a small amount of forward haul capacity become available.370

The commenters stated the pipelines serving Missour i were designed to serve winter heating load and do not have the capacity to simultaneously serv e winter natural gas heating load and coalfired generation displaced to natural gas and an up grade of the magnitude necessary to support the EPA's target could be substantial. According to the commenters, cost of generation would also be significantly higher for the generation dis placed from coal to natural gas because natural gas is more expensive than coal and the increased d emand for natural gas resulting from the EPA's proposed rule will further drive up the price of natural gas.

Comment 5: Commenters stated that the EPA should consider the impact of FERC on achievability of Building Blocks 2, 3 and 4.

Response 5: The EPA believes that FERC Order 1000 is consistent and compatible with the 111(d) final rule. The rule provides states with t he flexibility to develop plans that consider reliability and local circumstances, including othe r regulatory requirements and system requirements. The Building Blocks are not prescript ive (and comments addressing Building

Block 4 are not addressed because EPA has not to in clude the provision in the final Rule), but rather was used to calculate CO2 emission performan ce rates. States need not require any specific unit to operate a specific capacity factor . The flexibility that states have includes, for example, the choice of approaches, trading, time to develop plans, additional time before the start of the interim performance period, and the ability to shift emission rate achievement between performance periods. See sections V.D, VIII.A, VIII .C and VIII.G of the final rule preamble of the CPP and Chapter 3 of the GHG Mitigation Measure s TSD for the CPP Final Rule supporting

the final CPP.

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

Commenters stated that the EPA should take into con sideration the impact FERC authority will have in the achievability of Blocks 2, 3, and 4, pa rticularly with respect to cost impacts to
utilities and consumers. The commenters noted that the U.S. Court of Appeals for the DC Circuit recently unanimously upheld FERC Order 1000, which updated and enhanced requirements for utilities to participate in regional transmission p lanning in addition to cost allocation reforms and other matters, which could have implications for th e achievability of Blocks 2, 3 and 4 as well as costs for states with utilities subject to FERC jur isdiction. The commenters additionally noted that since FERC jurisdiction is limited in Texas, n ot all Texas utilities are subject to FERC Order 1000, which should be considered by the EPA in eval uating the potential emission reductions attributable to Blocks 2, 3, and 4.

Comment 6: Commenters questioned states' legal authority to se t prices affecting dispatch.

Response 6: The 111(d) final rule requires that states develop plans that establish emission standards for affected EGUs. We are providing state s with substantial flexibility as to how they structure those plans to achieve the 111(d) require ments. State are not required to set prices in order to achieve these requirements. States may ch oose to meet the 111(d) requirements through371

a variety of ways, including methods that impact th at costs of affected EGUs participating in electricity markets. ISOs/RTOs allow generators to bid in their variable costs, including environmental compliance costs, into the energy mar ket. In ISOs/RTOs where system operators dispatch the system in a least-cost economic dispat ch process, an affected EGU having higher costs will likely impact the amount that the affect ed EGUs is dispatched. There is ample precedent in other federal and state environmental programs which establish, for instance, allowance trading. Tradable allowances generally i ncrease the costs of affected generators which in turn impacts system. See VIII.C of the pre amble of the final CPP.

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

Commenters stated that the EPA should address, from a legal perspective, whether a state could or should be able to set prices that would influenc e the dispatch of the electric market.

Commenters cited U.S. Court of Appeals for the 3rd Circuit opinion on case 13-4330. Commenters stated the case involve NJ's authority t o arrange for the construction of new electric generators through a scheme focused on capacity pri ces and in which the 3rd District Court of Appeals overturned the state decision.

Comment 7: Commenters stated that IPM presumes regional tradi ng.

Response 7: The EPA has modified the approach and the IPM runs for the final rule. Please see section V.A of the preamble to the CPP and the Regu latory Impact Assessment of the final CPP.

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

Commenters stated that the discussion of modeling r esults in the proposal regarding the magnitude of redispatch refers to a region's existi ng electric generating fleet, and such a reference is only meaningful if there is regional t rading. The commenters asserted that the EPA cannot assume the economic impact will be based on a regional trading program since that option has not yet been determined to be an economi cally viable option for any individual state; and therefore, the EPA must reconsider this assumpt ion.

Comment 8: Commenters stated that the IPM is inconsistent with economic utility practices.

Response 8: The EPA disagrees. We believes that analysis of th e rule is appropriate and that we properly considered market practices. The 111(d) f inal rule provides states with the flexibility to develop plans that consider reliability and local c ircumstances, including the circumstances of individual plants. The Building Blocks are not pres criptive, but rather were used to calculate CO2 emission performance rates. The EPA believes th e IPM model to be useful in regulatory analysis, but the specific model results are not pr escriptive for the CPP. States may choose any of a variety of approaches. The flexibility that state s have includes, for example, the choice of approaches, trading, time to develop plans, additio nal time before the start of the interim372

performance period, and the ability to shift emissi on rate achievement between performance periods. See sections V.D, VIII.A, VIII.C and VIII. G of the final rule preamble of the CPP, Chapter 3 of the GHG Mitigation Measures TSD for th e CPP Final Rule supporting the final CPP and the Regulatory Impact Analysis of the final CPP.

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

Commenters stated that the IPM is inconsistent with economic utility practices. Commenters stated that EPA's IPM analysis for Option 1 complia nce for Arizona is the most relevant comparison, considering that Arizona has no firm pl ans for regional compliance at this time.
Commenters asserted that Pace Global finds the EPA analysis to be inconsistent with economic utility practice in its assumption that coal units, specifically Springerville Units 1, 2 and 3, would operate for such an extended period of time at sub- optimal dispatch. Commenters stated this large reduction in the overall plant utilization at Springerville Generating would result in an economic outcome that would favor shutdown over ope rating the plant at average annual capacity factor of 40% over a 10-year period. Comme nters stated it would average 30% over a 10-year period.

According to commenters, Pace Global does not find this analysis to support Arizona's ability to maintain any more than a very minimum capacity of t he existing coal fleet online beyond 2019 while complying with EPA's goals, particularly the interim goal. Commenters stated EPA's analysis is flawed and disagrees with the EPA's con clusions that, under the proposed rule, Arizona could maintain a portion of its coal capaci ty beyond 2019 while complying with the interim and final goals.

Comment 9: Commenters stated that the EPA's cost effectiveness evaluation underestimates the economic impact of EPA's rule on Arizona.

Response 9: The EPA disagrees with interpretation of the BSER a nd the 111(d) final rule. We believe we have appropriately modeled and analyzed the rule. The 111(d) final rule requires that states develop plans that establish emission standa rds for affected EGUs. We are providing states with substantial flexibility as to how they structu re those plans to achieve the 111(d) requirements. The flexibility includes, for example , the choice of approaches, trading, time to develop plans, additional time before the start of the interim performance period (postponed from 2020 until 2022), and the ability to shift emission rate achievement between performance periods. In response to additional analysis and man y comments, we have modified the proposal
and RIA – the establishment of CO2 emission reducti on standards is regionally based. The Building Blocks are not prescriptive, and states ma y consider local circumstances as they develop their plans, including system reliability, fuel diversity, the “useful life” of generation assets, other regulatory requirements and infrastru cture. See sections V.A, V.D, VIII.A, VIII.C.1 and VIII.G.2 of the final rule preamble of the CPP and Chapter 3 of the GHG Mitigation Measures TSD for the CPP Final Rule supporting the final CPP.

The following are summaries of the specific public comments under this comment:373

Commenters stated that the EPA's cost effectiveness evaluation significantly underestimates the true economic impact of its proposal and that the w ording in this section is misleading as the EPA's analysis is based on re-dispatch at a represe ntative, albeit hypothetical, coal-fired EGU to a representative NGCC EGU when, in reality, the EPA used the IPM to assess the costs of redispatch [79 FR 34864]. Therefore, the commenters a sserted, $30/metric ton represents an average cost across the entire modeling domain. Thi s is an important distinction, according to the commenters, as BSER, including the cost effectivene ss component, must be applied at the source level, defined as "any building, structure, facilit y, or installation which emits or may emit any air pollutant." [42 USC 7411(a)(6).]

According to the commenters, the proposal does not provide any information about the range of cost effectiveness as it would apply at the source level, probably because the EPA uses an electricity-sector-wide approach to determining BSE R. Notwithstanding the legality of such an approach, since the EPA is establishing goals for e ach state as "binding emission guidelines" [79 FR 34897], it should, at a minimum, per the comment ers, calculate cost effectiveness values ($/metric ton) for each state. From that data, the commenters stated the EPA would be able to evaluate if its chosen BSER is truly cost effective ; from that, then determine if adjustments or subcategorization is warranted.

The commenters stated they estimated the cost effec tiveness of the proposal for Arizona using a method similar to the EPA's method. Using the resul ts of modeling performed by PACE Global to compare the total cost and total emission reduct ions associated with compliance with the EPA's building block approach to a reference case, the commenters estimated that the cost effectiveness of the proposal for Arizona (based on compliance with its interim and final goals) is at least $122/metric ton. The commenters believe d this a conservative estimate, as PACE did not run a true business-as-usual case (i.e., absent the CPP). The commenters further estimated that $122/metric ton is not a direct comparison wit h EPA's estimate of $30/metric ton, as EPA's estimate was limited to only the re-dispatch buildi ng block and that if their cost effectiveness estimate was limited to the re-dispatch component o f the proposal, the value would likely be higher.

The commenters stated nothing in the docket explain s how Arizona, a significant exporter of energy, would become a significant importer by 2020 . During a teleconference with EPA officials on September 18, 2014, the officials stat ed that the reason for this shift in interstate power transfers was the result of their attempt to reflect the impact of California's AB-32 by adding a fee (presumably based on CO 2 emissions) to power imported into California, howev er, the commenters do not believe such a shift in inter state power transfers is likely to occur. The commenters added that EPA has provided no explanati on to support this approach or the value or "fee" added to California electricity imports. If t he EPA's assumption is wrong and Arizona is able to continue to export significant amounts of e nergy to California based on economic dispatch (or at least to serve load in Arizona), fo ssil generation in Arizona would increase, according to the commenters, as would the cost to a bate the resulting emissions to meet Arizona's stringent goal.

The commenters stated that a flaw in the EPA's mode ling approach, which assumes that the fleet of NGCC imports nationwide is required, on average, to achieve the specified annual utilization rates, is that it ignores individual unit ownership and other firm commitments that limit the374

availability of individual units. Some of these com mitments may not represent the most economical dispatch given the variability in loads across the grid during each hour, according to the commenters. While the commenters recognized tha t it would be difficult for EPA to capture that level of granularity, the commenters believed EPA should, at a minimum, acknowledge that incorporating these elements accurately would incre ase the cost of compliance for each of these
scenarios.

The commenters also questioned the EPA's constraint s, or lack thereof, for low utilization of large coal-fired EGUs. While the EPA claims that "I PM includes detailed representations of key operational limitations, such as turn-down constrai nts," [79 FR 34864] the commenters do not believe IPM's turn-down constraints accurately refl ect economic realities of operating a large, coal-fired unit at low capacity factor. The comment ers stated that EPA's compliance case show several units at SGS, which is operated by TEP, ope rating at annual capacity factors far below
what TEP would consider economical.

Most significantly, according to the commenters, EP A's cost estimates failed to consider the remaining book value of assets forced to retire ear ly. The commenters stated EPA apparently
dismisses stranded costs based on the notion that s tates could avoid them through the "flexibility" allegedly afforded in the rule. [79 F R 34897] The commenters believe they are entitled to recover their capital investment, havin g approximately $1 billion in book value remaining on all of its coal-fired generating asset s, of which $739 million is subject to retirement under the Proposal that would need to be recovered. In addition, the commenters asserted their customers would be paying for nearly $1.1 billion i n new generation to replace the retired coalfired plants. The commenters concluded these combin ed costs would have a significant impact
on retail rates.

The commenters urged EPA to correct these deficienc ies and re-evaluate the cost effectiveness of Proposal, recognizing the need for modifications to the final rule to maintain the desired cost
effectiveness.

Commenters stated that, as proposed, application of BB2 accounts for 77 percent of the required
reduction in the CO2 emissions/net-MWh in Arizona. The commenters added that EPA assumptions result in an overstatement of the amoun t of coal and gas steam generation in Arizona (and likely other states) that could be dis placed by NGCC generation starting in 2020. The commenters asserted that the costs projected by EPA for implementation of the Proposed
Carbon Rule must be reevaluated for Arizona and oth er similarly situated states.

Comment 10: Commenters stated that EE/RE cost estimates are too high and cost estimate for natural gas are too low. Commenters stated that mod est corrections to the EPA's estimates would show that EE and RE are cheaper carbon-reducers tha n natural gas.

Response 10: The EPA believes that the CO2 emission performance rates are reasonable. The EPA believes the Rule will not result in large incr eases in natural gas fired capacity nor does it believe that there will be a large increase in natu ral gas consumption. See the Regulatory Impact Analysis of the final CPP.375

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

Commenters stated that because burning natural gas also releases carbon we must soon phase out electric generation from natural gas. Thus, the com menters asserted, the proposal significantly
understates the cost of BB2. An accurate estimate o f the cost of switching to natural gas over the next 5-15 years, according to the commenters, must incorporate the estimated cost of switching away from natural gas soon thereafter. The commente rs asserted that the true cost of switching to natural gas now is the cost of that change plus the cost of replacing natural gas with renewables (the only feasible alternative) in a few years.

The commenters stated that the EPA's estimates for energy efficiency and renewables are far too high, and its estimate for natural gas far too low and that even modest corrections to EPA's estimates would show that both efficiency and renew ables are cheaper carbon-reducers than natural gas. The commenters asserted that switching to natural gas may burden consumers because the price of natural gas is expected to ris e steeply-23% by 2030. Also, the commenters believe that if the CPP spurs additional demand for natural gas, it could increase prices further, deepening the strain on low-income households, wher eas the cost of building renewable generation continues to plummet and, once built, re newable electricity has zero ongoing fuel

costs.

Comment 11: Commenters expressed concern regarding the economic and infrastructure impact of redispatch.

Response 11: The EPA disagrees. We believe we have appropriately considered the economic impacts of the rule and provided states with the ab ility to consider these concerns. The 111(d) final rule requires that states develop plans that establish emission standards for affected EGUs. We are providing states with substantial flexibilit y as to how they structure those plans to achieve the 111(d) requirements. The flexibility in cludes, for example, the choice of approaches, trading, time to develop plans, additional time bef ore the start of the interim performance period (postponed from 2020 until 2022), and the ability t o shift emission rate achievement between performance periods. In response to additional anal ysis and many comments, we have modified the proposal and RIA – the establishment of CO2 emi ssion reduction standards is regionally based. The Building Blocks are not prescriptive, an d states may consider local circumstances as they develop their plans, including system reliabil ity, fuel diversity, the “useful life” of generation assets, other regulatory requirements an d infrastructure. See sections V.A, V.D, VIII.A, VIII.C.1 and VIII.G.2 of the final rule pre amble of the CPP and Chapter 3 of the GHG Mitigation Measures TSD for the CPP Final Rule supp orting the final CPP.

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

Several commenters expressed concern about the econ omic impact of redispatch, including
infrastructure. Commenters stated that the EPA has not adequately analyzed the economic impacts and of NGCC redispatch and must evaluate st randed asset costs, state-level employment impacts, and new infrastructure costs. Commenters n oted concern regarding stranded costs for376

existing retrofitted coal units and believed the ad dition of NGCC would exacerbate stranded costs while raising rates to pay for new NGCC units

.
Commenters stated that, as a small business entity with only one generating unit, they have no other means to supply their customers, thus, redisp atching from coal will increase the cost to
owners/customers. The commenters estimated the cost increase to be 10-20%, dependent on the decrease in their output. The increased cost, state d the commenters, is due to operating below design output of the unit, which decreases efficien cy (more fuel per MwHr); and the fixed cost of the plant being spread over fewer MwHrs produced.

Regarding the assumption of increased redispatch of natural gas units of up to 70 percent, commenters stated concern that in moving from an "e conomic dispatch" to an "environmental dispatch," units will be called to generate primari ly based upon the emission profile of the unit.
The commenters stated this could be reconciled with economic dispatch if a carbon fee were added to each generator's costs to reflect its emis sions profile, forcing the costs of greater emitting generation higher in the merit order of di spatch.

The commenters questioned whether there will be suf ficient pipeline capacity to support this increase in natural gas generation and noted that p ipelines have traditionally been financed with long-term contracts - often 20 or 30 years in lengt h - between natural gas distribution companies and the natural gas pipelines. However, the fastest growing set of customers for pipelines are now natural gas generation units, according to the commenters, often in "organized" wholesale markets with day-ahead and real time energy markets that require power plant owners to bid into these markets (as opposed to base load plants in ve rtically integrated markets). For example, the commenters noted that despite widespread recognitio n that New England needs additional pipeline capacity, the fundamental challenge has be en how to finance this expansion when generators are reluctant to sign long-term contract s. The commenters stated concern that this challenge of financing adequate pipeline infrastruc ture in New England will be replicated in other markets because of the proposal's increased r eliance on natural gas generation.

Comment 12: Commenters stated that the cost-benefit analysis is incomplete and there is insufficient guidance regarding NGCC dispatch.

Response 12: The EPA disagrees with the interpretation of the fi nal rule. We believe we have offered sufficient guidance to states. The 111(d) f inal rule requires that states develop plans that
establish emission standards for affected EGUs. We are providing states with substantial flexibility as to how they structure those plans to achieve the 111(d) requirements. The flexibility includes, for example, the choice of approaches, tr ading, time to develop plans, additional time before the start of the interim performance period (postponed from 2020 until 2022), and the ability to shift emission rate achievement between performance periods. In response to additional analysis and many comments, we have modified the pr oposal and RIA – the establishment of CO2 emission reduction standards is regionally base d. The Building Blocks are not prescriptive, and states may consider local circumstances as they develop their plans, including system reliability, fuel diversity, the “useful life” of g eneration assets, other regulatory requirements and infrastructure. See sections V.A, V.D, VIII.A, VIII .C.1 and VIII.G.2 of the final rule preamble of377

the CPP and Chapter 3 of the GHG Mitigation Measure s TSD for the CPP Final Rule supporting
the final CPP.

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

Several commenters stated that the EPA had not adeq uately analyzed the economic impacts of NGCC dispatch. Commenters stated that EPA guidance did not explain fully how an economical dispatch of NGCC will occur and the CPP did not tak e into consideration the mechanism used to require the operation or incentivize utilities unde r an economical dispatch model to operate NGCC plants. The commenters requested that the fina l CPP specifically address how state plans and cooperatives will economically dispatch NGCC un its to meet the CPP. The commenters noted, for example, that the CPP should consider th e costs and project delays for rights-of way obtainment related to expanding NGCC generation for the construction of natural gas supply pipelines to accommodate rule requirements. The com menters asserted that obtaining rights-ofway is often difficult and time consuming and doing so hastily can create additional costs and
risk. The commenters also stated that the CPP cost benefit analysis did not consider the cost of natural gas pipeline and firm contracts to meet the rule and requested that infrastructure costs to meet the CPP using additional NGCC generation be in cluded in the cost benefit analysis.

Commenters stated EO 13563 requires the EPA to (1) make a reasoned determination that the benefit of a proposed regulation justifies its cost and (2) tailor its regulations to impose the least burden on society, consistent with obtaining regula tory objectives. Accordingly, the commenters
stated that the EPA must consider the economic cons equences of stranded assets associated with the proposed redispatch, along with the impacts of local job losses, and tailor the final rule to minimize these impacts.

Commenters asserted many of the units that the EPA' s IPM model predicts will retire have been upgraded recently with emission control equipment m andated by other CAA programs, such as the Regional Haze Rule and the MATS rule, other uni ts predicted to retire are less than 10 years old. The commenters stated owners of these plants h ave not had sufficient time to recover the
costs of these investments and that forced retireme nts would result in billions of dollars in stranded assets; whose costs would be borne either by the units' owners or by ratepayers. The
commenters added that the forced retirement of coal -fired EGUs would have even more severe consequences for merchant generators because coal-f ired assets would have no salvage value, forced retirement of coal-fired generation likely w ould mean bankruptcy and dissolution for many merchant generators.

Commenters stated coal-fired EGU retirements as a r esult of redispatch to NGCCs would have significant economic impacts on local economies. Fo r example, the commenters asserted that the EPA projects that, by 2020, 5 of the 7 coal-fired E GUs in Arkansas and all of the coal-fired EGUs in Mississippi would need to shut down for the states to meet their interim goals. The commenters urged the EPA to consider the local econ omic impacts of these shutdowns as these plants are an important source of high-wage employm ent, and most are located in rural areas where there are few alternative employment options. The construction of new NGCCs, even if a viable option, according to commenters would not co mpensate for these impacts, as NGCCs require less than a third of the staff required to operate coal-fired EGUs.378

Comment 13: Commenters expressed concern regarding cost and ava ilability of needed NG pipeline infrastructure.

Response 13: The EPA disagrees with the interpretation of the fi nal rule – it does not mandate specific capacity factors, and we believe our analy sis is appropriate. The 111(d) final rule requires that states develop plans that establish e mission standards for affected EGUs. We are providing states with substantial flexibility as to how they structure those plans to achieve the 111(d) requirements. The flexibility includes, for example, the choice of approaches, trading, time to develop plans, additional time before the s tart of the interim performance period (postponed from 2020 until 2022), and the ability t o shift emission rate achievement between performance periods. In response to additional anal ysis and many comments, we have modified the proposal and RIA – the establishment of CO2 emi ssion reduction standards is regionally based. The Building Blocks are not prescriptive, an d states may consider local circumstances as they develop their plans, including system reliabil ity, fuel diversity, the “useful life” of generation assets, other regulatory requirements an d infrastructure. See sections V.A, V.D, VIII.A, VIII.C.1 and VIII.G.2 of the final rule pre amble of the CPP and Chapter 3 of the GHG Mitigation Measures TSD for the CPP Final Rule supp orting the final CPP.

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

Commenters expressed concern regarding the cost of additional natural gas pipeline infrastructure that will be needed through 2030. Co mmenters stated that INGAA estimated that the U.S. and Canada will need 28,900 to 61,600 mile s of additional natural gas pipelines through 2030; INGAA and the Eastern Interconnection States' Planning Council projected that expenditures from 2014-2035 for new pipeline, compr ession, and pumping infrastructure would be about $10 billion per year; and the U.S. will ne ed 1.4 TCF of new working gas storage capacity at an estimated cost of $12.5 billion. Com menters cited tables from a September 2, 2013 Oil & Gas Journal indicating the U.S. average cost- per-mile for onshore pipeline construction on FERC applications submitted by June 30, 2012, was $ 3.1 million. In addition, commenters stated these numbers would be vastly higher if existing NG CC units were required to double their capacity factor and, if States cannot meet the emis sion reduction requirements EPA proposes for Building Blocks 1, 3, and 4, and more pressure is p ut on Building Block 2, these numbers will climb higher still.

Commenters stated that generators in Pennsylvania m ust bid into PJM's capacity markets and do
so on an economic basis. The commenters believed th e forced incentivizing of natural gas over coal threatens to imprint a significant distortion on the market and is concerned if there is enough infrastructure and fuel supply available if this oc curs. The commenters noted that EPA estimates that this forced demand increase will drive up natu ral gas spot prices by 12.5% in 2020, impacting electricity ratepayers and manufacturing and other industries that rely heavily upon natural gas as a production feedstock.379

Comment 14: Commenters expressed concern that reduced power sup ply diversity leads to higher energy costs.

Response 14: The EPA disagrees with the application of the cited study to the final rule. The 111(d) final rule requires that states develop plan s that establish emission standards for affected EGUs. We are providing states with substantial flex ibility as to how they structure those plans to achieve the 111(d) requirements. The flexibility in cludes, for example, the choice of approaches, trading, time to develop plans, additional time bef ore the start of the interim performance period (postponed from 2020 until 2022), and the ability t o shift emission rate achievement between performance periods. In response to additional anal ysis and many comments, we have modified the proposal and RIA – the establishment of CO2 emi ssion reduction standards is regionally based. The Building Blocks are not prescriptive, an d states may consider local circumstances as they develop their plans, including system reliabil ity, fuel diversity, the “useful life” of generation assets, other regulatory requirements an d infrastructure. See sections V.A, V.D, VIII.A, VIII.C.1 and VIII.G.2 of the final rule pre amble of the CPP and Chapter 3 of the GHG Mitigation Measures TSD for the CPP Final Rule supp orting the final CPP.

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

Commenters stated that to illustrate the importance of power supply diversity at the national level, IHS compared a base case reflecting the gene ration mix in regional U.S. power systems during the 2010-2012 period with a reduced diversit y case. The commenters noted that IHS found that the cost of generating electricity in th e reduced diversity case was more than $93 billion higher per year and the potential variabili ty of monthly power bills was 50 percent higher compared to the base case. Consequently, the commen ters asserted the study calculates that the typical household's annual disposable income to be around $2,100 less in the reduced diversity scenario, there would be around one million fewer j obs compared to the base case and U.S. GDP would be nearly $200 billion less. The commenters s tated additional costs would arise if current trends lead to the retirement and replacement of ex isting power plants before it was economic to
do so.

Comment 15: Commenters stated that the EPA needs to consider th at fuel costs vary nationally.

Response 15: The EPA disagrees. We do consider that fuel costs v ary from region to region, and we believe our analysis is appropriate. The 111(d) final rule requires that states develop plans
that establish emission standards for affected EGUs . We are providing states with substantial flexibility as to how they structure those plans to achieve the 111(d) requirements. The flexibility includes, for example, the choice of approaches, tr ading, time to develop plans, additional time before the start of the interim performance period (postponed from 2020 until 2022), and the ability to shift emission rate achievement between performance periods. In response to additional analysis and many comments, we have modified the pr oposal and RIA – the establishment of CO2 emission reduction standards is regionally base d. The Building Blocks are not prescriptive, and states may consider local circumstances as they develop their plans, including system reliability, fuel diversity, the “useful life” of g eneration assets, other regulatory requirements and380

infrastructure. See sections V.A, V.D, VIII.A, VIII .C.1 and VIII.G.2 of the final rule preamble of the CPP, Chapter 3 of the GHG Mitigation Measures T SD for the CPP Final Rule supporting the final CPP and the Regulatory Impact Assessment of t he final CPP.

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

Commenters stated that coal costs for serving elect ricity generation vary significantly between regions and that the EPA has biased its Building Bl ock 2 analysis by presuming and applying a fuel pricing structure more typical of the Eastern U.S. to redispatch from existing coal to existing NGCC in the upper Midwest. The commenters noted tha t most coal sourced within Minnesota comes from the Powder River Basin (PRB) of Montana/ Wyoming. The commenters stated that Minnesota's imported coal-based electricity is also mostly fueled with lower cost PRB coal and North Dakota lignite. The commenters referenced a t able from the EIA November 2014 Short Term Energy Outlook that portrays how the price of coal for different U.S. regions significantly varies, and establishes that the coal serving the M innesota region is much less expensive than the coal delivered for electricity generation in much o f the Eastern U.S. An underlying factor for this relatively lower cost for PRB and lignite coal, acc ording to the commenters, is the natural resource being suited for strip mining. The comment ers stated that PRB and lignite also benefit from relatively cheap transport by rail across the Great Plains to Midwest utilities for electricity generation and mine-mouth to generating unit operat ion.

In contrast, the commenters asserted that natural g as pricing that may result from expanded operation of existing NGCC units is expected to be more uniform across the U.S., resulting in a much higher premium for compliance with the EPA's p roposed CPP-related preference for the more expensive, natural gas dispatch than what the EPA would observe when assessing eastern U.S. market replacement of existing coal with exist ing NGCC. The commenters believed the BSER cost-effectiveness analysis should be recogniz ing a higher coal to natural gas fuel switching difference expressed as a cost per ton CO 2 reduction in the Midwest compared to the
eastern U.S. The commenters stated that EPA's Build ing Block 2 cost effectiveness analysis is not properly reflecting the energy-based natural re sources, power markets and associated economics in the upper Midwest.

The commenters added that interim modeling (EGEAS S eptember 17, 2014) analysis of the CPP performed by MISO indicated that EPA's Building Blo ck 2 carries a cost premium of $53/ton of CO2 emission reduction when compliance is delivered at the MISO model subregion (state) level. The commenters stated that this $53/ton CO 2 reduced significantly exceeds the EPA's $36 per short ton CO 2 ($40 per tonne) cost-effectiveness threshold. The commenters asserted that this MISO modeled high cost reinforces how Minnesota Int egrated Resource Planning that includes
CO 2 cost consideration designates existing NGCC for di spatch to support reliability for intermittent renewable resources and to serve peak customer demand periods rather than a base load dispatch capability. Considering that the cost premium to redispatch existing coal generation to existing NGCC exceeds the EPA's own c ost effectiveness criteria, the commenters stated that the EPA should delete the Building Bloc k 2 target component for Minnesota, giving deference to Minnesota Integrated Resource Planning and least cost power market dispatch used for establishing the level of production from Minne sota existing NGCC generating units.381

Comment 16: Commenters stated that the cost effectiveness analy sis does not properly take into account the workings of the wholesale energy market

.
Response 16: The EPA disagrees. We believe our analysis adequate ly addresses the market, and, moreover, the rule does not compel the actions desc ribed by the commenter. The 111(d) final rule requires that states develop plans that establ ish emission standards for affected EGUs. We are providing states with substantial flexibility a s to how they structure those plans to achieve the 111(d) requirements. The flexibility includes, for example, the choice of approaches, trading, time to develop plans, additional time before the s tart of the interim performance period (postponed from 2020 until 2022), and the ability t o shift emission rate achievement between performance periods. In response to additional anal ysis and many comments, we have modified the proposal and RIA – the establishment of CO2 emi ssion reduction standards is regionally based. The Building Blocks are not prescriptive, an d states may consider local circumstances as they develop their plans, including system reliabil ity, fuel diversity, the “useful life” of generation assets, other regulatory requirements an d infrastructure. See sections V.A, V.D, VIII.A, VIII.C.1 and VIII.G.2 of the final rule pre amble of the CPP and Chapter 3 of the GHG Mitigation Measures TSD for the CPP Final Rule supp orting the final CPP.

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

Commenters stated that Block 2 redispatch from exis ting coal to existing NGCC operated at a 70% capacity factor represents the largest Minnesot a contribution to the EPA's proposed BSER determination of the Minnesota CPP target due to fa ctors including the relatively large amount of existing Minnesota NGCC capacity deployed to provid e reliability support for intermittent renewable energy resources, reserves needed to quic kly meet metro area peak customer energy demand periods and early action efforts by Xcel Ene rgy under its Metropolitan Emission Reduction Program (MERP).

The commenters asserted that Minnesota Power curren tly has no existing natural gas nor combined cycle natural gas capacity, but has plans for deployment of new NGCC capacity targeted to serve about 1/3 natural gas to our cust omer electricity needs. If EPA's CPP Block 2 requirements compel the redispatch from coal to hig her priced natural gas, the commenters stated utilities will be forced to curtail their self-gene ration from coal and substitute existing NGCC from other areas within the state or region. Becaus e this power is purchased in the wholesale electric market and not self-generated, the comment ers stated it exposes utility consumers to considerable cost and availability risks. The comme nters stated that Minnesota utilities manage the risk of market cost exposure for their customer s by including a managed segment of purchased power in their generation mix. The commen ters asserted that Minnesota's IRP process requires that utilities consider and manage risk in their overall resource planning processes. The commenters believe that compelled purchases of exis ting NGCC generation to support the EPA's proposed Minnesota CPP compliance target imposes a number of unnecessary risks on Minnesota retail electricity customers and that the EPA's cost effectiveness analysis has not given adequate consideration to how wholesale elect ric markets work or how utilities manage price risk.382

Comment 17: Commenters stated that BB2 assumptions do not recog nize physical, financial, and regulatory constraints on the electric grid, el ectric reliability and the cost of energy to

consumers.

Response 17: The EPA disagrees with the interpretation of the f inal rule. The rule does allow states to consider the concerns the commenters expr ess. The 111(d) final rule requires that states develop plans that establish emission standards for affected EGUs. We are providing states with substantial flexibility as to how they structure th ose plans to achieve the 111(d) requirements. The flexibility includes, for example, the choice o f approaches, trading, time to develop plans, additional time before the start of the interim per formance period (postponed from 2020 until 2022), and the ability to shift emission rate achie vement between performance periods. In response to additional analysis and many comments, we have modified the proposal and RIA –

the establishment of CO2 emission reduction standar ds is regionally based. The Building Blocks are not prescriptive, and states may consider local circumstances as they develop their plans, including system reliability, fuel diversity, the “ useful life” of generation assets, other regulatory requirements and infrastructure. See sections V.A, V.D, VIII.A, VIII.C.1 and VIII.G.2 of the final rule preamble of the CPP and Chapter 3 of the GHG Mitigation Measures TSD for the CPP Final Rule supporting the final CPP.

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

Commenters stated BB2 creates winners (gas plant ow ners) and losers (coal plant owners) without regard to the real cost borne by consumers. Utilities have spent billions for SOTA air pollution control systems to meet the emission limi ts of the CAIR and the utility MATS rule for units that will be prematurely closed, commenters s aid. The EPA's proposal does not take into
account the billions in stranded costs to consumers if this occurs, commenters further added. The commenters asserted not assessing the cost impact i s contrary to the EPA's own guidelines requiring cost impact assessment of a section 111 p roposal. Commenters stated that the EPA's BB2 does not recognize the need to capture the econ omic value of existing resources. The commenters asserted that Building Block 2 assumptio ns do not recognize physical, financial, and regulatory constraints that could have negative con sequences for the electric grid, electric reliability and for the cost of energy to consumers

.
Commenters stated that among the practical problems the EPA has not addressed into its models

are:

• Generator Ownership & Stranded Assets: The EPA's pr oposal suggests that

massive redispatch of the entire electric generatio n fleet can occur without regard to ownership of the facilities.

• Generator Design: Many gas units were not designed to run at high capacity factors and, more importantly, most coal fired plan ts simply cannot become the type of load-following unit necessary to meet EPA's expectations.

• Permit Constraints: Many coal plants have minimum l oad requirements to keep pollution control systems operating and many gas pl ants, designed for peaking383 purposes only, were permitted with significant oper ating limitations to address local environmental impacts.

• Generator Location: Power generator location is a c ritical factor for electric reliability but is not addressed by the EPA's IPM m odel.

• Transmission Constraints: Serious transmission prob lems likely to arise with such a massive shift in the national generation profile are not addressed by the EPA.

• Pipeline Capacity: Areas of the country like the NE and parts of the Midwest have already identified pipeline capacity shortfalls tha t will serve to limit change in dispatch.

Similarly, commenters concluded that the EPA should recalculate state goals to account for physical constraints, actual gas generation capacit y and known pollution control investments. Additionally, the commenters believed states should have the flexibility to further adjust goals for stranded investment, and physical and permit co nstraints that prevent or delay redispatch.

Comment 18: Commenters stated that the lack of fuel diversity w ill lead to higher fuel costs and unreliability.

Response 18: The EPA disagrees with the commenter’s interpretat ion of the final rule. The 111(d) final rule does allow states to consider tra nsmission and natural gas distribution infrastructure. Additionally, we have postponed th e start of the performance period in response to analysis and comments. The rule requires that s tates develop plans that establish emission standards for affected EGUs. We are providing state s with substantial flexibility as to how they structure those plans to achieve the 111(d) require ments. The flexibility includes, for example, the choice of approaches, trading, time to develop plans, additional time before the start of the interim performance period (postponed from 2020 unt il 2022), and the ability to shift emission rate achievement between performance periods. In re sponse to additional analysis and many comments, we have modified the proposal and RIA – t he establishment of CO2 emission reduction standards is regionally based. The Buildi ng Blocks are not prescriptive, and states may consider local circumstances as they develop their plans, including system reliability, fuel diversity, the “useful life” of generation assets, other regulatory requirements and infrastructure. See sections V.A, V.D, VIII.A, VIII.C.1 and VIII.G. 2 of the final rule preamble of the CPP and Chapter 3 of the GHG Mitigation Measures TSD for th e CPP Final Rule supporting the final
CPP.

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

Commenters stated that while the EPA believes that the power industry can support higher gas consumption without additional pipeline infrastruct ure investments, NERC suggested additional pipeline capacity will be needed in Arizona, Nevada and New England states. The commenters stated that increased natural gas power generation will require pipeline expansion to maintain a reliable source of natural gas, particularly during peak winter heating season. Pipeline constraints384

and growing gas and electric interdependency are ch allenges that will impede the electric industry's ability to ensure delivery of natural ga s, according to the commenters. The
commenters asserted that the EPA did not consider t he time frame to build new gas plants as well as additional pipeline capacity (a minimum of 3-5 years or more, to plan, permit, sign contracts, finance and build additional infrastruct ure).

The commenters asserted that the EPA does not value coal fired generation and seems to favor shutting down all coal. The commenters stated that risks of losing the coal fleet will be an unstable grid, soaring electrical energy pricing du e to lack of fuel diversity and the loss of economic growth. The commenters suggested the EPA c onsider recent activities in Germany where they are building highly efficient coal fired power plants without carbon controls after years of following the same policies the EPA is pro posing today. The commenters asserted it is not practical or economical to operate coal fired p ower plants at a 40% capacity factor; the cost to the ratepayer for supporting idle capacity will be prohibitive and the impact on manufacturing will be negative due to higher power prices.

Comment 19: Commenters stated that the EPA's IPM results are no t supportable.

Response 19: The EPA disagrees. We consider our analysis adequat e. The study cited by the commenters does not model the provision of the fina l rule. The 111(d) final rule requires that states develop plans that establish emission standa rds for affected EGUs. We are providing states with substantial flexibility as to how they structu re those plans to achieve the 111(d) requirements. The flexibility includes, for example , the choice of approaches, trading, time to develop plans, additional time before the start of the interim performance period (postponed from 2020 until 2022), and the ability to shift emission rate achievement between performance periods. In response to additional analysis and man y comments, we have modified the proposal
and RIA – the establishment of CO2 emission reducti on standards is regionally based. The Building Blocks are not prescriptive, and states ma y consider local circumstances as they develop their plans, including system reliability, fuel diversity, the “useful life” of generation assets, other regulatory requirements and infrastru cture. See sections V.A, V.D, VIII.A, VIII.C.1 and VIII.G.2 of the final rule preamble of the CPP and Chapter 3 of the GHG Mitigation Measures TSD for the CPP Final Rule supporting the final CPP.

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

Commenters stated that while the IPM suggests that the Proposed Carbon Rule produces a net positive outcome for Arizona, it uses incorrect ass umptions and does not provide the level of detailed system modeling to identify the power syst em reliability issues and gas pipeline
constraints that would arise within Arizona. The co mmenters asserted that the IPM's analysis of positive cost/benefit impacts does not consider all costs associated with the Proposed Rule's implementation and some of its underlying assumptio ns are inaccurate. For example, in reviewing the results for Arizona, the commenters s tated EPA assumes that coal units can be shut down in one year and then brought back on line in f uture years, which is unreasonable. The
commenters added that EPA also assumes certain coal units can be operated as cycling/peaking units, which is untrue for those units in Arizona.385

The commenters added that import capacity into Ariz ona from New Mexico, taken from a Western Electricity Coordinating Council (WECC) rep ort, is overstated by over 3,000 MW. The commenters stated that in EPA's modeling about 90 p ercent of the imports to Arizona come from New Mexico, which would be substantially reduced if the proper import capability were used.
The commenters stated EPA did not consider the cost of "stranded assets" in its analysis, which in Arizona alone could amount to $3.0 billion. The commenters added that EPA did not consider the electric transmission and gas pipeline constrai nts within Arizona with adoption of the proposed rule. The commenters believe EPA would hav e to factor in the significant costs associated with building additional transmission li nes and pipelines in AZ when coal plants are shut down. The commenters also asserted existing tr ansmission lines may need to be retired before the end of their useful lives, which is anot her cost that must be considered in AZ.

The commenters added that the inputs in the IPM dif fer from the assumptions made in the emission targets, creating a disparate result in th at EPA is using the IPM to backstop the 111(d) emission targets; however, the two are using a comp letely different set of assumptions and inputs
to do so.

Comment 20: Commenters commented on the cost analysis at the st ate level and requested IPM

clarification.

Response 20: The EPA disagrees with the commenter’s interpretati on of the rule – it does not, for example, require that the building blocks be im plemented exactly as described in the goal setting nor does it require individual EGU owners t o meet specific capacity factor goals. Because those specifications are not part of the rule, we h ave not modeled them. The 111(d) final rule requires that states develop plans that establish e mission standards for affected EGUs. We are providing states with substantial flexibility as to how they structure those plans to achieve the 111(d) requirements. The flexibility includes, for example, the choice of approaches, trading, time to develop plans, additional time before the s tart of the interim performance period (postponed from 2020 until 2022), and the ability t o shift emission rate achievement between performance periods. In response to additional anal ysis and many comments, we have modified the proposal and RIA – the establishment of CO2 emi ssion reduction standards is regionally based. The Building Blocks are not prescriptive, an d states may consider local circumstances as they develop their plans, including system reliabil ity, fuel diversity, the “useful life” of generation assets, other regulatory requirements an d infrastructure. See sections V.A, V.D, VIII.A, VIII.C.1 and VIII.G.2 of the final rule pre amble of the CPP and Chapter 3 of the GHG Mitigation Measures TSD for the CPP Final Rule supp orting the final CPP.

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

Commenters asked why did the EPA not perform modeli ng to assess the cost of redispatching NGCC to 70% capacity factor at the state level, not only nationwide. Commenters asked for an explanation of why the EPA believe the costs in its GHG TSD accurately reflect the cost of redispatching NGCC to 70% capacity factor at the st ate level. The commenters also asked for
clarification of whether the IPM can restrict redis patch modeling to the same owners. Finally, the386

commenters asked for clarification of the methodolo gy EPA used in its determination that $34/ton cost is reasonable, what the distinction is between $/tonne and $/tonne CO 2 , and why
this is the most relevant metric.

Comment 21: Commenters were concerned of the potential and cost of stranded investments.

Response 21: The EPA disagrees with the commenters’ interpretati on of the rule. The 111(d) final rule requires that states develop plans that establish emission standards for affected EGUs. We are providing states with substantial flexibilit y as to how they structure those plans to achieve the 111(d) requirements. The flexibility in cludes, for example, the choice of approaches, trading, time to develop plans, additional time bef ore the start of the interim performance period (postponed from 2020 until 2022), and the ability t o shift emission rate achievement between performance periods. In response to additional anal ysis and many comments, we have modified the proposal and RIA – the establishment of CO2 emi ssion reduction standards is regionally based. The Building Blocks are not prescriptive, an d states may consider local circumstances as they develop their plans, including system reliabil ity, fuel diversity, the “useful life” of generation assets, other regulatory requirements an d infrastructure. See sections V.A, V.D, VIII.A, VIII.C.1 and VIII.G.2 of the final rule pre amble of the CPP and Chapter 3 of the GHG Mitigation Measures TSD for the CPP Final Rule supp orting the final CPP.

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

Some commenters were concerned with the costs of po tentially stranded investments. Commenters stated potential for stranded investment s is not limited to application of BB2 in 2020 and that even if the implementation date for B B2 were extended to 2030, full implementation would result in substantial stranded investments in Arizona. For example, commenters stated that Unit 4 at the Springerville Generating Station commenced operation in December 2009 with bond financing of approximately 30 years with final bond maturity in 2038. In addition, commenters stated SRP recently complet ed air pollution control equipment upgrades on Units 1 and 2 at the Coronado Generating Station , which cost approximately $470 million; likewise with 30 years bond financing with final bo nd maturity in 2041. The commenters added
that these stranded cost estimates do not include t hose that will be incurred by AEPCO, APS, SRP, and TEP for compliance with the Regional Haze rule.

Commenters stated that several existing coal-fired units in Arkansas likely will be forced to retire as a result of the proposed rule, resulting in stra nded assets for which cost recovery will be a significant concern for AECC and its members. The c ommenters asserted that if a generating unit, which takes years and hundreds of millions (i f not billions) of dollars to build, is forced to prematurely close and it has not yet reached the en d of its useful life, then the owner(s) of that generating unit will be left with stranded assets. The commenters added that if a unit is shut down, the historical and present-day costs to build and maintain that unit do not simply go away,
and there are additional costs in the form of decom missioning and the like associated with the
closure.

Commenters stated that Florida's ESPS depends prima rily on load shifting from coal to gas-fired generation for compliance and most of the reduction s are front-loaded to the 2020-2022 time387

period. The commenters asserted the shift would res ult in the premature closing of many coalfired units, which the Federal government through t he Fuel Use Act required us to build and add pollution controls. The commenters noted that FMEA utilities recently added $2 billion of "state of the art" air pollution control systems to coal p lants to meet the emission limits of the CAIR, CSAPR and the Utility MATS (UMATS) rules. The comme nters asserted EPA's proposal does
not take into account the hundreds of millions of d ollars in stranded costs for those units that must be paid by our consumers if those units are pr ematurely shut down, and also threatens electric reliability.

Commenters asserted that application of BB 1 and 2 results in all coal and other steam boiler generation units being completely displaced by redi spatch of natural gas at a higher capacity factor than currently employed in Nevada. The comme nters stated that the EPA assumed that NV Energy's Tracy Unit 3 and Fort Churchill Units 1 & 2 will retire by 2020, but as a result of implementation of the Regional Haze BART requiremen ts for these affected units, the capability to burn fuel oil was removed. In addition, the comm enters asserted that a substantial investment has just been completed on each of these units to m eet the state's January 1, 2015 BART compliance date. The commenters stated NV Energy re asonably assumed it would be able to operate the units for a duration such that it would be able to depreciate its investment in environmental controls over a reasonable period of time, certainly after 2020.

Similarly, commenters stated that the EPA did not a dequately consider other compliance-related expenditures such as NV Energy's North Valmy Genera ting Station MATS-related investments to meet the April 2015 compliance date. The comment ers stated the remaining useful life of
these units dictates that to avoid stranded investm ent in these units and to minimize costs to customers, NV Energy will be required to continue d ispatching these units well into the interim compliance period of the CPP.

Commenters stated that section 111(d) of the CAA re quires the EPA to develop regulations that allow states to consider, among other factors, the remaining useful life of the existing source to which the standard applies. The commenters stated t hat while, arguably, the EPA will allow the states to take this aspect into consideration in th eir state plans, in applying BB 1 and 2 in the standard-setting process, the EPA effectively remov es this consideration for the states as they struggle to meet the established interim targets wi th limited options. The commenters suggested that the EPA specifically add a fifth provision to 40 CFR section 60.5740(11), "supporting material" to include "materials demonstrating the s tate's analysis of the remaining useful life of the existing source to which such standard applies" to address situations where affected EGUs
have made recent emission control retrofits or have significant remaining book life.

Comment 22: Commenters stated that there is a disproportionate burden on states with perceived underutilized NGCC capacity.

Response 22: The EPA disagrees. We believe the comments do not a pply to the final rule. In response to additional analysis and many comments, we have modified the proposal and RIA –
the establishment of CO2 emission reduction standar ds is regionally based. The 111(d) final rule requires that states develop plans that establish e mission standards for affected EGUs. We are388

providing states with substantial flexibility as to how they structure those plans to achieve the 111(d) requirements. The flexibility includes, for example, the choice of approaches, trading, time to develop plans, additional time before the s tart of the interim performance period (postponed from 2020 until 2022), and the ability t o shift emission rate achievement between performance periods. The Building Blocks are not pr escriptive, and states may consider local circumstances as they develop their plans, includin g system reliability, fuel diversity, the “useful life” of generation assets, other regulatory requir ements and infrastructure. See sections V.A, V.D, VIII.A, VIII.C.1 and VIII.G.2 of the final rul e preamble of the CPP and Chapter 3 of the GHG Mitigation Measures TSD for the CPP Final Rule supporting the final CPP.

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

Commenters stated that while the proposed rule purp orts to produce a 30% reduction nationally
in CO 2 emissions from EGUs by 2030, Arkansas must produce a disproportionately higher amount of reductions (44%) over that same time peri od because it assumes Arkansas it has a relatively large amount of "underutilized" existing NGCC capacity. Based on current fuel prices, the commenters stated that the proposed rule's conc ept of "redispatch" from coal to natural gas will cost Arkansas ratepayers an estimated $75 mill ion per year. The commenters added that AECC expects that amount to increase over time as n atural gas prices increase in response to higher demand and constrained supply.

The commenters asserted Arkansas is penalized under the proposed rule because it has been diligent for a long time in diversifying its energy portfolio to ensure a proper generation mix that includes both coal- and natural gas-fired EGUs, and those efforts ensured access to stable fuel prices. The commenters argued that such a burden on one of the smallest and poorest states in the country will hamper its ability to join in a region al compliance plan, further limiting its ability to offset its disproportionately high 44% compliance b urden.

Comment 23: Commenters commented on the cost and reliability im pacts of redispatch.

Response 23: The EPA disagrees. The 111(d) final rule requires t hat states develop plans that

establish emission standards for affected EGUs. We are providing states with substantial flexibility as to how they structure those plans to achieve the 111(d) requirements. The flexibility includes, for example, the choice of approaches, tr ading, time to develop plans, additional time before the start of the interim performance period (postponed from 2020 until 2022), and the ability to shift emission rate achievement between performance periods. In response to additional analysis and many comments, we have modified the pr oposal and RIA – the establishment of CO2 emission reduction standards is regionally base d. The Building Blocks are not prescriptive, and states may consider local circumstances as they develop their plans, including system reliability, fuel diversity, the “useful life” of g eneration assets, other regulatory requirements and infrastructure. See sections V.A, V.D, VIII.A, VIII .C.1 and VIII.G.2 of the final rule preamble of the CPP and Chapter 3 of the GHG Mitigation Measure s TSD for the CPP Final Rule supporting

the final CPP.

The following are summaries of the specific public comments under this comment:389

Commenters stated that Arkansas has been identified to achieve a significant portion of its emission reduction by redispatching NGCC plants to a 70% utilization factor, and that, in 2012, approximately 27% of Arkansas' electricity was prod uced at natural gas plants. The commenters
were concerned this increase will result in either significant coal retirements or major reductions in coal utilization, which would result in increase d electricity costs and compromised reliability.

Comment 24: Commenters stated that the significant investments required, costs, and timeframe

assumed under BB2 are unreasonable.

Response 24: The EPA disagrees. We do not agree with the interpr etation of the rule, nor do we believe that the analysis referenced by the comment er is relevant to the final rule. The 111(d) final rule requires that states develop plans that establish emission standards for affected EGUs. We are providing states with substantial flexibilit y as to how they structure those plans to achieve the 111(d) requirements. The flexibility in cludes, for example, the choice of approaches, trading, time to develop plans, additional time bef ore the start of the interim performance period (postponed from 2020 until 2022), and the ability t o shift emission rate achievement between performance periods. In response to additional anal ysis and many comments, we have modified the proposal and RIA – the establishment of CO2 emi ssion reduction standards is regionally based. The Building Blocks are not prescriptive, an d states may consider local circumstances as they develop their plans, including system reliabil ity, fuel diversity, the “useful life” of generation assets, other regulatory requirements an d infrastructure. See sections V.A, V.D, VIII.A, VIII.C.1 and VIII.G.2 of the final rule pre amble of the CPP and Chapter 3 of the GHG Mitigation Measures TSD for the CPP Final Rule supp orting the final CPP.

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

Commenters stated that the BB2 requirement to incre ase the generation of existing NGCC units to a 70% capacity factor and displace generation fr om existing coal plants in the interim compliance period requires a profound shift in gene ration in Michigan that will require significant investment in natural gas supply infras tructure that may not be achievable in the short time leading up to 2020. The commenters asserted th at dialing up capacity from 2012 levels to 70% would increase NGCC generation in Michigan by 1 2.2 TWh, a 66% increase in natural gas generation for the state, according to EPA's buildi ng block calculations. Concerned about the feasibility and cost impacts for this, the commente rs stated they asked Pace Global to evaluate the feasibility of this rapid shift to natural gas for generation.

Comment 25: Commenters stated that the cost of implementing BB2 will necessitate high CO2

fees.

Response 25: The EPA disagrees. The 111(d) final rule does not require that implementation requires “high CO2 fees.” The rule requires that st ates develop plans that establish emission390

standards for affected EGUs. We are providing state s with substantial flexibility as to how they structure those plans to achieve the 111(d) require ments. The flexibility includes, for example, the choice of approaches, trading, time to develop plans, additional time before the start of the interim performance period (postponed from 2020 unt il 2022), and the ability to shift emission rate achievement between performance periods. In re sponse to additional analysis and many comments, we have modified the proposal and RIA – t he establishment of CO2 emission reduction standards is regionally based. The Buildi ng Blocks are not prescriptive, and states may consider local circumstances as they develop their plans, including system reliability, fuel diversity, the “useful life” of generation assets, other regulatory requirements and infrastructure. See sections V.A, V.D, VIII.A, VIII.C.1 and VIII.G. 2 of the final rule preamble of the CPP and Chapter 3 of the GHG Mitigation Measures TSD for th e CPP Final Rule supporting the final

CPP.

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

Commenters stated BB2 entails significant cost, as reflected in the modeling projection that Pennsylvania would need to impose a $50/ton CO 2 charge in 2030 to meet its mandated emission

rate.

Comment 26: Commenters stated that coal generation and natural gas generation are not fully fungible.

Response 26: The EPA disagrees with the commenters’ interpretati on of the rule. Our analysis addresses recognizes that different types of EGU’s perform different functions in the market. The 111(d) final rule requires that states develop plan s that establish emission standards for affected EGUs. We are providing states with substantial flex ibility as to how they structure those plans to achieve the 111(d) requirements. The flexibility in cludes, for example, the choice of approaches, trading, time to develop plans, additional time bef ore the start of the interim performance period (postponed from 2020 until 2022), and the ability t o shift emission rate achievement between performance periods. In response to additional anal ysis and many comments, we have modified the proposal and RIA – the establishment of CO2 emi ssion reduction standards is regionally based. The Building Blocks are not prescriptive, an d states may consider local circumstances as they develop their plans, including system reliabil ity, fuel diversity, the “useful life” of generation assets, other regulatory requirements an d infrastructure. See sections V.A, V.D, VIII.A, VIII.C.1 and VIII.G.2 of the final rule pre amble of the CPP and Chapter 3 of the GHG Mitigation Measures TSD for the CPP Final Rule supp orting the final CPP.

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

Commenters asserted that BB2 erroneously assumes th at coal generation and natural gas generation are fungible, with each KWh of increased natural gas generation substituting for a KWh of coal generation, when in reality coal genera tion and natural gas generation serve different functions. Commenters stated first, coal generators provide local reliability support,391

including the ability to restart without any electr ical input, voltage stability, and ancillary services. Thus, the commenters stated, certain coal facilities may be "reliability must run" units that cannot be retired without imperiling local gri d reliability. For example, the commenters cited a Western Electricity Coordinating Council study th at stated:

The path rating for Path 8 [the Montana to Pacific Northwest corridor] is currently highly dependent on remedial action schemes that are direc tly linked with the coal-fired and hydro generation in Montana. There are inertial concerns in the area. The local balancing authorities have advised caution when running studies that disp atch renewable generation before coal-fired and hydro generation. In reality, the rating on Pat h 8 may have to be decreased when these conventional resources are backed down, or turned o ff completely.

Second, the commenters asserted that coal-fueled EG Us have the ability to stockpile fuel onsite, whereas natural gas units receive their fuel throug h pipelines vulnerable to disruptions. The commenters noted that, according to FERC, during la st winter's cold weather, numerous natural gas generators were forced to cease generation beca use of interruptions in pipeline deliveries, due to the physical inability of frozen pipelines t o deliver natural gas and because suppliers cut off interruptible load to serve other load under mu ch higher spot prices. The commenters stated EPA failed to consider these real and negative circ umstances in determining that every state's "best" utility system should entail the wholesale s ubstitution of natural gas for coal. The commenters added that, based on EIA data, coal pric es have historically been low and stable, whereas natural gas prices have been volatile.

Comment 27: Commenters stated that the EPA modeling does not pr operly account for

transmission-related constraints and costs.

Response 27: The EPA disagrees. We recognized transmission relat ed constraints and costs, and believe that the commenter has not interpreted the flexility the final rule provides. The 111(d) final rule requires that states develop plans that establish emission standards for affected EGUs. We are providing states with substantial flexibilit y as to how they structure those plans to achieve the 111(d) requirements. The flexibility in cludes, for example, the choice of approaches, trading, time to develop plans, additional time bef ore the start of the interim performance period (postponed from 2020 until 2022), and the ability t o shift emission rate achievement between performance periods. In response to additional anal ysis and many comments, we have modified the proposal and RIA – the establishment of CO 2 emission reduction standards is regionally based. The Building Blocks are not prescriptive, an d states may consider local circumstances as they develop their plans, including system reliabil ity, fuel diversity, the “useful life” of generation assets, other regulatory requirements an d infrastructure. See sections V.A, V.D, VIII.A, VIII.C.1 and VIII.G.2 of the final rule pre amble of the CPP and Chapter 3 of the GHG Mitigation Measures TSD for the CPP Final Rule supp orting the final CPP. Commenters stated the conclusions reached in the BB2 analysis that su ggest Louisiana could, and should, improve its generator efficiency performance, and that the IPM assumptions and results simply reflect these efficiency opportunities are inconsonant with conclusions reached in prior LPSC investigations.392

The commenters stated that over the past decade, LP SC has investigated opportunities for better utilizing NGCC generation that included leveraging a considerable amount of CHP-based generation at many of the state's large industrial facilities, and consistently concluded that in most of these investigations expanding newer NGCC g eneration and ramping down older, less efficient natural gas-fired steam generation, come at a cost of billions in transmission-related and bulk power sector investments. The commenters noted that LPSC's investigations were based upon very detailed multi-area electric generation d ispatch modeling with utility-specific data and operational input that go well beyond any generaliz ed model like the IPM used in the development of the CPP.

In theory, the commenters stated the EPA correctly notes efficiency opportunities and opportunities for reduced emissions across a range of pollutants (not just CO 2 ) through the increased utilization and redispatch of NGCC genera tion are considerable. However, the commenters stated that equally important are the po ssibilities for lowering overall generation costs for Louisiana ratepayers by utilizing more ef ficient and lower-cost natural gas based generation.

The commenters added that while the EPA calculates costs based on the cost of compliance, it did not consider the upgrades in transmission requi red for the increase in NGCC dispatch nor consider the potential for significant stranded cos ts associated with the reduced production, or premature retirement of Louisiana's existing oil an d gas-fired steam EGUs. The commenters asserted the midrange estimate for new transmission is $1.0 billion and associated stranded costs - increased NGCC dispatch and decreased oil/gas ste am generation (i.e., stranded facilities costs) results in a potential mid-range estimate of $986.4 million. According to the commenters, when
these costs are added to the costs calculated for B uilding Block 1, the total potential costs eligible for recovery from Louisiana ratepayers inc reases to almost $3.5 billion.

Comment 28: Commenters stated that there will be higher than an ticipated costs due to transmission issues, natural gas prices and forced closures.

Response 28: The EPA thanks the commenters. The EPA believes tha t the 111(d) final rule provides states with the flexibility to develop pla ns that consider reliability and local circumstances, including infrastructure. The Buildi ng Blocks are not prescriptive, but rather were used to calculate CO2 emission performance rates. T he EPA believes the IPM model to be useful in regulatory analysis, but the specific model resu lts are not prescriptive for the CPP. States may choose any of a variety of approaches. The flexibil ity that states have includes, for example, the choice of approaches, trading, time to develop plan s, additional time before the start of the interim performance period, and the ability to shif t emission rate achievement between performance periods. See sections V.D, VIII.A, VIII .C and VIII.G of the final rule preamble of the CPP and Chapter 3 of the GHG Mitigation Measure s TSD for the CPP Final Rule supporting

the final CPP.

The following are summaries of the specific public comments under this comment:393

Two commenters stated that costs of BB2 may be high er than anticipated due to transmission issues, increased price of natural gas due to incre ased demand and forced closure of coal plants. Commenters stated that though NGCCs are not transmi ssion-constrained in New Mexico, capacity of pipelines and location of NGCC plants r elative to electricity demand require further consideration and technical analysis. Commenters st ated that as natural gas demand increases, so will its price, especially in light of anticipated EPA rules addressing methane from oil and gas operations. Commenters asserted that reducing usage of coal-fired EGUs lowers their efficiency and, thus, their cost-effectiveness, while potentia lly increasing emissions of ozone precursors. Commenters believed this creates pressure for early retirements, raising the risk of stranded assets and higher costs for electricity consumers.

Comment 29: Commenters noted factors influencing power decision s - regulatory/investment

risks.

Response 29: The EPA believes that the 111(d) final rule provide s states with the flexibility to develop plans that consider reliability and local c ircumstances, including providing market stability. The EPA reviewed the Lazard analysis for the final Rule. The Building Blocks are not prescriptive, but rather were used to calculate CO2 emission performance rates. The EPA believes the IPM model to be useful in regulatory a nalysis, but the specific model results are not prescriptive for the CPP. States may choose any of a variety of approaches. The flexibility that states have includes, for example, the choice of ap proaches, trading, time to develop plans, additional time before the start of the interim per formance period, and the ability to shift emission rate achievement between performance perio ds. See sections V.D, VIII.A, VIII.C and VIII.G of the final rule preamble of the CPP and Ch apter 3 of the GHG Mitigation Measures TSD for the CPP Final Rule supporting the final CPP

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

Commenters noted challenges faced in making energy investments. Commenters stated that investment risk, price volatility, project size, ti me to market and sunk capital costs are important concerns in in resource selection, reinforced by th e urgency of dealing with the challenge of climate change. Commenters stated the Lazard analys is provides estimates for key characteristics of deploying various low carbon technologies that h ave played an important part in the ongoing debate of resource selection, although they have no t entered into the EPA analysis. Commenters asserted that small, quick to market, nimble assets are considered much more attractive investments as they are more flexible and better ab le to meet small load increases more quickly and would be easier to finance. According to commen ters, the investment risk aspect of resource acquisition is increasingly dealt with by applying a portfolio approach to decision making, to reduce the overall risk of the portfolio by includi ng assets that have different levels of risk, particularly when the risks are not positively corr elated. Commenters stated the assumption is
that there is a risk/cost tradeoff that defines an efficient frontier and investors want to be on the efficient frontier, where risk and reward are balan ced. In applying this framework to the evaluation of generation options, the commenters st ated that analysts frequently measure reward as kilowatts per dollar (a measure of economic effi ciency), which is the inverse of cost.394

Commenters believed that options that move the port folio toward the efficient frontier should be adopted since they embody lower cost and/or risk.

Commenters stated that decisions made by utility an d independent power producers regarding the need for new generation can take years to devel op and investments routinely exceed hundreds of millions of dollars, and their life exp ectancy spans 40-50 years. Thus, commenters
stated that investors and financiers look to stable markets/rates and long-term contracts to minimize risk and justify these large investments. Commenters believed one of the greatest risks in recent years is the regulatory risk that puts th ose investment decisions in jeopardy. For BB2 to succeed, commenters stated investors need clear, un ambiguous signals from EPA that this proposed rule is the last and final rule regarding power plant emissions. Commenters believed fuzzy rulemaking commitments and shifting standards hinder any plans to finance new gas-fired
EGUs and that investors are concerned that environm ental groups will next challenge natural gas. Commenters urged EPA to provide a clear regula tory framework whereby long-term capitalintensive decisions can be made.

Comment 30: Commenters stated that changing economic dispatch to environmental dispatch would raise wholesale market prices by 39% and cost Ohioans $2.5 billion more per year in

electric costs in 2025.

Response 30: The EPA disagrees with the commenter’s interpretati on of the rule, and we believe the commenter’s analysis does not reflect the flexi bilities of the final rule. The 111(d) final rule requires that states develop plans that establish e mission standards for affected EGUs. We are providing states with substantial flexibility as to how they structure those plans to achieve the 111(d) requirements. The flexibility includes, for example, the choice of approaches, trading, time to develop plans, additional time before the s tart of the interim performance period (postponed from 2020 until 2022), and the ability t o shift emission rate achievement between performance periods. In response to additional anal ysis and many comments, we have modified the proposal and RIA – the establishment of CO2 emi ssion reduction standards is regionally based. The Building Blocks are not prescriptive, an d states may consider local circumstances as they develop their plans, including system reliabil ity, fuel diversity, the “useful life” of generation assets, other regulatory requirements an d infrastructure. See sections V.A, V.D, VIII.A, VIII.C.1 and VIII.G.2 of the final rule pre amble of the CPP and Chapter 3 of the GHG Mitigation Measures TSD for the CPP Final Rule supp orting the final CPP.

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

Commenters stated that to quantify costs associated with implementing environmental dispatch in the PJM footprint, the PUCO utilized the Ventyx PROMOD IV modeling software, which they considered superior to EPA's IPM for a number of reasons. Specifically, the commenters asserted PROMOD IV accounts for losses and congesti on that occur in the grid and the constraints that these impose on the reliable opera tion of electricity markets, while any model that does not fully account for these factors on a regional and sub-regional level, including IPM, would underestimate the impact of the proposed rule . Additionally, the commenters stated395

PROMOD IV allows for analysis to be conducted undercurrent conditions and for forwardlooking transmission cases to be incorporated into the dispatch algorithm, facilitating long- and short-term analysis.

According to the commenters, PUCO's modeling demons trates that the switch from economic to environmental dispatch, as a result of BB2, would c ause wholesale market energy prices to be 39% higher in calendar year 2025 than prices would be without BB2. The commenters provided a graph (titled: "Wholesale Market Impacts from the Clean Power Plan (based on 2025 projected powerflows and prices)"), which shows changes in ma rginal price per month. The commenters asserted that BB2 compliance would cost Ohioans app roximately $2.5 billion more for electricity in 2025 alone. The commenters added that, when cons idering economic impacts beyond the price of electricity, the CPP would impose more str ain on Ohioans as the cost of goods and
services would increase as businesses are forced to pass on higher electricity costs.

Comment 31: Commenters stated that the CPP's volatility snapsho t is inappropriate.

Response 31: The EPA disagrees. We believe that our characteriza tion of volatility is adequate. In response to additional analysis and many comment s, we have modified the proposal and RIA See sections Chapter 3 of the GHG Mitigation Measur es TSD for the CPP Final Rule supporting the final CPP and the Regulatory Impact.

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

Commenters stated the CPP seems to conflate the con cepts of volatility and affordability in its attempt to depict expected price increases as withi n acceptable, normal limits. The commenters asserted that while, historically, electricity pric es exhibit a high degree of volatility, largely due to the volatile nature of fuel costs, it manifests itself in both the upward and downward direction. In 2008, according to the commenters, energy price volatility resulted in significant decreases in
end-user consumer costs. The commenters asserted th at energy prices may be significantly volatile from year to year with no appreciable net trend either upwards or downwards in consumer costs and believed that conflating the con cept of volatility with affordability is insufficient justification of whether the economic implications of the proposed rule are tolerable.

Comment 32: Commenters stated that there are unique redispatch challenges for SMMPA and

the state of Minnesota due to lack of an NGCC in fl eet.

Response 32: The EPA disagrees with the commenter’s interpretati on of the final rule. The 111(d) final rule requires that states develop plan s that establish emission standards for affected EGUs. We are providing states with substantial flex ibility as to how they structure those plans to achieve the 111(d) requirements. The flexibility in cludes, for example, the choice of approaches, trading, time to develop plans, additional time bef ore the start of the interim performance period (postponed from 2020 until 2022), and the ability t o shift emission rate achievement between performance periods. In response to additional anal ysis and many comments, we have modified the proposal and RIA – the establishment of CO2 emi ssion reduction standards is regionally396

based. The Building Blocks are not prescriptive, an d states may consider local circumstances as they develop their plans, including system reliabil ity, fuel diversity, the “useful life” of generation assets, other regulatory requirements an d infrastructure. See sections V.A, V.D, VIII.A, VIII.C.1 and VIII.G.2 of the final rule pre amble of the CPP and Chapter 3 of the GHG Mitigation Measures TSD for the CPP Final Rule supp orting the final CPP.

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

Commenters stated that Blocks 2 and 3 will signific antly increase costs and impair their ability to provide affordable power to members. The commenters believed the assumption that utilities can increase the average utilization of existing and un der-construction NGCC is flawed with respect to SMMPA, as NGCC plants are non-existent in its fl eet. Thus, the commenters asserted, there is no opportunity for SMMPA to redispatch among its ow n units under BB 2. If EPA insists on implementing BB 2, the commenters stated they would have to depend on the purchase of NGCC generation from other utilities, resulting in signi ficant additional costs under PPAs after having already invested millions of dollars in the constru ction and improvement of Sherco 3.

Comment 33: Commenters stated that the EPA modeling does not ac curately reflect the changing TVA fossil fuel-fired EGU portfolio.

Response 33: The EPA has updated the database. In response to a dditional analysis and many comments, we have modified the proposal and RIA – t he establishment of CO2 emission reduction standards is regionally based. See sectio n V.D of the final rule preamble of the CPP, Chapter 3 of the GHG Mitigation Measures TSD for th e CPP Final Rule supporting the final CPP, and the Regulatory Impact Assessment of the fi nal CPP. Commenters stated that TVA, like most utilities and system operators, operates under least cost dispatch principles - seeking to meet demand by dispatching lower-cost generation re sources before higher-cost resources. With regard to energy oversight and rate regulation, the commenters asserted that TVA and Tennessee are unique compared to other states. The commenters stated EPA's modeling using the NEEDS Database 5.13v3, as an input for planned and future retirements of EGUs in states, does not accurately reflect the changing TVA fossil fuel-fir ed EGU portfolio and past and future

commitments made to retire and idle units in the st ate. The commenters recommended EPA update its modeling with current data inputs prior to finalizing the guidelines.

Comment 34: Commenters stated that the modeling demonstrates th at BB2, as proposed, is not cost-effective for electric generation.

Response 34: EPA believes the commenter’s analysis does not ref lect the 111(d) final rule. In response to additional analysis and many comments, we have modified the proposal and RIA. See section V.D of the final rule preamble of the C PP, Chapter 3 of the GHG Mitigation Measures TSD for the CPP Final Rule supporting the final CPP and the Regulatory Impact Analysis of the final CPP.397

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

Commenters stated comparison of Model Run (b) with Model Run (c) shows that the EGEAS model selects installation of new NGCC capacity ins tead of operating existing NGCC capacity above a 15% capacity factor in 2020, resulting in n ew NGCC units operating at over 80% capacity factor in comparison to existing NGCC unit s, which run below 20%, because emission from the new units do not count toward the goal and are, therefore, lower cost. This makes it impossible for existing NGCC units to operate at a 70% capacity factor, as required by BB2, asserted the commenters, and encourage construction of new NGCC units that would not otherwise be necessary to meet load. The commenters concluded that market dynamics of the proposal significantly disadvantages existing NGCC facilities, regardless of their emissions level relative to a new NGCC facility.

Comment 35: Commenters commented on the cost effectiveness of R PS.

Response 35: See sections V.D, VIII.A, VIII.C and VIII.G of the final rule preamble of the CPP and Chapter 3 of the GHG Mitigation Measures TSD fo r the CPP Final Rule supporting the final CPP. The RPS in Wisconsin is outside of the scope o f the final CPP.

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

Commenters stated that their preliminary analysis s hows that Wisconsin can meet EPA's CO 2 reduction targets by pursuing two compliance option s, a 30% by 2030 RPS, or a statewide shift to displace coal with increased dispatch of existin g natural gas units. While the 30% RPS will require significant construction of new renewable g eneration, the commenters asserted it is costcompetitive with the natural gas fuel switching alt ernative by 2030 (though actual costs could vary widely depending on many variables that were n ot tested in this initial analysis). According to the commenters, the 30% RPS scenario will also r esult in highly diversified generation mix
that will insulate Wisconsin's utilities and electr ic ratepayers against volatile fuel prices and potential CO 2 compliance costs.

Comment 36: Commenters stated that the cost of compliance will lead to unit retirements.

Response 36: The EPA disagrees that the commenter’s assessment r eflects the 111(d) final rule.

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

Commenters stated that PJM analysis concludes that it would likely not be able to meet the winter peak requirement if comparable generator out ages that occurred in January 2014 were to occur in the winter of 2015/2016 coupled with extre mely cold temperatures and expected coal plant retirements. If market conditions continue to be depressed, the commenters stated that generation resources on the margin that are forced to decide between investments to maintain398

viability or retirement, will choose retirement, fu rther exacerbating reliability concerns and consumer cost volatility.

Comment 37: Commenters stated that redispatch causes economic h arm and amounts to a ban on coal-fired generation.

Response 37: The EPA disagrees with the commenter’s assessment o f the final rule. The 111(d) final rule requires that states develop plans that establish emission standards for affected EGUs. We are providing states with substantial flexibilit y as to how they structure those plans to achieve the 111(d) requirements. The flexibility in cludes, for example, the choice of approaches, trading, time to develop plans, additional time bef ore the start of the interim performance period (postponed from 2020 until 2022), and the ability t o shift emission rate achievement between performance periods. In response to additional anal ysis and many comments, we have modified the proposal and RIA – the establishment of CO2 emi ssion reduction standards is regionally based. The Building Blocks are not prescriptive, an d states may consider local circumstances as they develop their plans, including system reliabil ity, fuel diversity, the “useful life” of generation assets, other regulatory requirements an d infrastructure. See sections V.A, V.D, VIII.A, VIII.C.1 and VIII.G.2 of the final rule pre amble of the CPP and Chapter 3 of the GHG Mitigation Measures TSD for the CPP Final Rule supp orting the final CPP.

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

Commenters stated that the EPA's proposal to re-dis patch coal-fired steam generating units to NGCC units will result in significant economic harm to the 49 public power communities in Georgia that receive their wholesale electric power from MEAG. The commenters asserted "environmental dispatch" creates winners (NGCC owne rs) and losers (coal unit owners) without regard to the associated economic harm. The comment ers believed the rule amounts to a ban on a certain percentage of coal fired generation which i s currently in use and operating to serve the country's energy needs.

Comment 38: Commenters commented on the treatment of the emissi ons from under construction NGCC units that are not subject to the EPA's 111(b) NSPS requirements.

Response 38: See Preamble Sections IV and V.A for discussion of affected sources and BSER.

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

Commenters recommended that the EPA allow NGCC unit s under planning and construction that are not subject to section 111(b) of the CAA requir ements to emit CO 2 annual emissions reflecting unimpeded operation across their full op erating range. The commenters asserted this sort of unimpeded planning and operation would be a llowed if the unit was subject to CAA section 111(b) NSPS requirements and stated that th e difference between under deployment new NGCC heat rate performance and CAA section 111(b) N SPS affected unit heat rate performance is not significant enough to warrant impeding the o peration of these under construction NGCC units. The commenters suggested the EPA acknowledge that those resources already in approved399

state integrated resource plans or under permitting and/or physical construction pre-date the timing of CPP applicability, represent a small popu lation of generating units and represent good
CO 2 emitting performance regardless of CO 2 NSPS not being applicable.

Comment 39: Commenters stated that the NGCC capacity factor is higher than the EPA states but should be determined considering system-wide tr ansmission constraints and consumer costs.

Response 39: The EPA believes that the 111(d) final rule provide s states with the flexibility to develop plans that consider reliability and local c ircumstances. The Building Blocks are not prescriptive, but rather were used to calculate CO2 emission performance rates. The EPA believes the IPM model to be useful in regulatory a nalysis, but the specific model results are not prescriptive for the CPP. States may choose any of a variety of approaches. The flexibility that states have includes, for example, the choice of ap proaches, trading, time to develop plans, additional time before the start of the interim per formance period, and the ability to shift emission rate achievement between performance perio ds. See sections V.D, VIII.A, VIII.C and VIII.G of the final rule preamble of the CPP and Ch apter 3 of the GHG Mitigation Measures TSD for the CPP Final Rule supporting the final CPP

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

Commenters stated that while the EPA estimates that NGCC power plants can achieve a 70% capacity factor, in fact, their availability is in the 85-95% range. The commenters further stated that the feasibility of higher NGCC utilization sho uld be determined by modeling system-wide
transmission constraints. Given that the EPA is con cerned with consumer costs, the commenters stated that the EPA should carefully consider how l ocational marginal prices are affected in order to achieve these higher capacity factors and also s ays that their research indicates consumer costs (and capacity markets) could be profoundly affected by market-based mechanisms needed to achieve this goal.

Comment 40: Commenters stated that the gas turbine peaking gene rator is limited due to insufficient gas supply and the inability to establ ish firm pricing.

Response 40: The EPA disagrees. Gas turbine peaking generators a re not affected sources.

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

Commenters stated that as a municipal generator Fre mont has very little flexibility. Although the commenters said it has a gas turbine peaking genera tor, there is not adequate gas supply to dispatch that unit in the winter months. Also, beca use of the limited and unpredictable use of the peaking turbine, Fremont is unable to secure firm p ricing for gas which results in higher operating costs, the commenters explained. The comm enters added that fuel switching to natural gas as a fuel instead of coal at today's prices wou ld result in a 40% increase in the cost per MW to generate the power. According to the commenters, the increase does not count the capital cost400

for additional pipeline capacity to get the gas to its natural gas distribution system and then across the City to the power plant. These costs cou ld easily exceed $15-20 million.

Comment 41: Commenters suggested there is an error in the data for Louisiana that calls into questions whether compliance can be met by states i n a cost effective manner.

Response 41: The EPA disagrees with the commenter’s interpretati on of the rule – the IPM analyses of the proposal is not prescriptive. In re sponse to additional analysis and many comments, we have modified the proposal and RIA. We are providing states with substantial flexibility as to how they structure those plans to achieve the 111(d) requirements. The flexibility includes, for example, the choice of approaches, tr ading, time to develop plans, additional time before the start of the interim performance period (postponed from 2020 until 2022), and the ability to shift emission rate achievement between performance periods. The Building Blocks are not prescriptive, and states may consider local cir cumstances as they develop their plans, including system reliability, fuel diversity, the “ useful life” of generation assets, other regulatory requirements and infrastructure. See sections V.A, V.D, VIII.A, VIII.C.1 and VIII.G.2 of the final rule preamble of the CPP and Chapter 3 of the GHG Mitigation Measures TSD for the CPP Final Rule supporting the final CPP, and the Regula tory Impact Assessment of the final CPP.

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

Commenters stated that it has identified an inconsi stency, in addition to those pointed out by the LDEQ, which casts further doubt on the validity of the assumptions included within the CPP and that compliance can be met by the states in a cost effective manner. In the IPM output data summary provided in EPA-HQ-OAR-2013-0602-220.xls, t he commenters noted that all of the coal or petroleum coke-fired units in Louisiana, ex cept for Cleco's Dolet Hills Unit 1 and Brame Unit 3, are designated as "Coal Unit Retirement." T he commenters further noted that this leaves only the 634 net MW provided by Dolet Hills and the 516 net MW provided by Brame Unit 3 (presented as two separate 258 MW boilers) to provi de a total of 1,150 net MW of coal-fired generation after 2020. The commenters also noted th at at a 100% capacity factor, these two units could provide only 10,074 GWH of coal-fired generat ion; however, the data provided in 2014- 0602tsd-state-goal-data-computation.xls shows that the redispatch of even the inflated amount of NGCC proposed by the EPA to a 70% capacity factor s till leaves 11,539 MWh to be served by coal-fired units - an amount that would require 1,5 50 MW of capacity operating at an 85% capacity factor - 400 MW more than the EPA spares f rom retirement. The commenters stated that at the very least, this disconnect must be exp lained by the EPA, and at worst it calls into question the logic embedded in EPA's models.

Comment 42: Commenters stated that the EPA's assumptions substa ntially overstate the amount of NGCC generation that would be available technica lly or economically to offset the coal generation the proposal will retire or force off th e grid.401

Response 42: The EPA disagrees. In response to additional analys is and many comments, we have modified the proposal and RIA and revisted the calculations – we don’t believe the commenter’s analysis reflects the final rule. The 1 11(d) final rule requires that states develop plans that establish emission standards for affecte d EGUs. We are providing states with substantial flexibility as to how they structure th ose plans to achieve the 111(d) requirements. The flexibility includes, for example, the choice o f approaches, trading, time to develop plans, additional time before the start of the interim per formance period (postponed from 2020 until 2022), and the ability to shift emission rate achie vement between performance periods. The Building Blocks are not prescriptive, and states ma y consider local circumstances as they develop their plans, including system reliability, fuel diversity, the “useful life” of generation assets, other regulatory requirements and infrastru cture. See sections V.A, V.D, VIII.A, VIII.C.1 and VIII.G.2 of the final rule preamble of the CPP, Chapter 3 of the GHG Mitigation Measures TSD for the CPP Final Rule supporting the final CPP , and the Regulatory Impact Assessment of
the final CPP.

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

Commenters stated that there is no technical or eco nomic evidence that NGCC power plants can sustain generation at a 70 percent capacity factor, as the EPA assumes. The commenters stated that the EPA's assumption is derived by using an ar bitrary $30/ton CO2 price (tax) as a reasonable cost a consumer should pay for fuel swit ching from lower cost coal generation to higher cost sources. The commenters further stated that the EPA would fundamentally convert the current electric grid from an economic dispatch to a carbon dispatch model. The commenters asserted that the EPA's assumptions also incorrectl y use nameplate capacity rather than net capacity (i.e., the amount of output that can be su pplied to system load), and that this error demonstrates a lack of understanding of how electri c utilities plan and operate to meet demand and insure reliability. The commenters also asserte d that as a result of this mistake, NGCC plants in many states will have to run at or well above 80 percent capacity. The commenters also stated that the EPA's analysis erroneously indicates that 11 states can replace all of their coal generation capacity with NGCC generation. Further the commente rs stated that the EPA's 2012 baseline inventory includes NGCC units that have been either out of service for several years or retired. The commenters also noted that the EPA acknowledges a serious gap of at least 10 percent between the amount of natural gas needed to sustain this assumption and the current natural gas pipeline delivery network. The commenters finally s tated that the EPA's assumptions substantially overstate the amount of NGCC generati on that would be available technically or economically to offset the coal generation the prop osal will retire or force off the grid.

Comment 43: Commenters requested that the EPA clarify how natu ral gas factors into reduction targets when coal plants are retired and transition ed to different gas plants.

Response 43: In response to additional analysis and many comment s, we have modified the proposal and RIA. The final rule does not include n ew NGCC units. See sections V.A and V.D final rule preamble of the CPP, and Chapter 3 of th e GHG Mitigation Measures TSD, and Chapter 3 of the Goal Setting TSD for the CPP Final Rule supporting the final CPP for the EPA’s response to this comment.402

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

Commenters indicated that states like Kentucky, tha t are almost entirely dependent on coal and do not yet have new gas online, need more clarity o n how the CPP addresses a transition in situations where coal plants are retired and transi tion into new gas. Ideally the plan will factor both gains from shutting down coal plants and add b ack in the impacts of new gas when calculating compliance, the commenters hoped.

Comment 44: Commenters commented on the impacts of the CPP on s pecific plants in

Delaware.

Response 44: The EPA disagrees with the commenter’s interpretati on of the rule, and we believe the commenter’s analysis does not reflect the flexi bilities of the final rule. The 111(d) final rule requires that states develop plans that establish e mission standards for affected EGUs. We are providing states with substantial flexibility as to how they structure those plans to achieve the 111(d) requirements. The flexibility includes, for example, the choice of approaches, trading, time to develop plans, additional time before the s tart of the interim performance period (postponed from 2020 until 2022), and the ability t o shift emission rate achievement between performance periods. In response to additional anal ysis and many comments, we have modified the proposal and RIA – the establishment of CO2 emi ssion reduction standards is regionally based. The Building Blocks are not prescriptive, an d states may consider local circumstances as they develop their plans, including system reliabil ity, fuel diversity, the “useful life” of generation assets, other regulatory requirements an d infrastructure. See sections V.A, V.D, VIII.A, VIII.C.1 and VIII.G.2 of the final rule pre amble of the CPP, Chapter 3 of the GHG Mitigation Measures TSD for the CPP Final Rule supp orting the final CPP, and the Regulatory Impact Assessment of the final CPP.

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

The commenters stated that, for the Calpine Hay Roa d facility, the CPP would require increasing generation by 42 percent of the plant's capacity fa ctor from 50 to 70 percent. The commenters explained that these increases do not match the EPA 's goal for a national average of 51 percent by 2030, and that the plant recently dropped its ca pacity factor to 43 percent in 2013 due to the limited natural gas supply in winter months. Regard ing the NRG Indian River plant, Commenters remarked that the CPP would require redu cing generation 13 percent and reducing the capacity factor to 34 percent. The commenters e xplained that the EPA is expecting coal-fired power plants to hit a national average capacity fac tor of 73 percent by 2030, but the Indian River facility is currently tied for the cleanest coal-fi red power plant in the country. The commenters questioned why the EPA would want this facility to run at half the capacity factor of the national average. Finally, commenters stated that the CPP di d not account for a new power plant in Dover being constructed by Calpine and did not include em issions or power production for two small power plants in Dover.403

3.2.6 Natural Gas Price Impacts

This section addresses comments on the natural gas price impacts that would be caused by the CPP. The issues include potential price increases a nd volatility.

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

Comment 1: Commenters described why price volatility in natur al gas due to the increase in demand by the power sector is not a concern.

Response 1: The EPA agrees to the extent that natur al gas supplies are sufficient and increasing. The EPA believes that the 111(d) final rule provide s states with the flexibility to develop plans that consider reliability and local circumstances. The Building Blocks are not prescriptive, but rather were used to calculate CO2 emission performa nce rates. The flexibility that states have includes, for example, the choice of approaches, tr ading, time to develop plans, additional time before the start of the interim performance period, and the ability to shift emission rate achievement between performance periods. See sectio ns V.D, VIII.A, VIII.C and VIII.G of the final rule preamble of the CPP and Chapter 3 of the GHG Mitigation Measures TSD for the CPP Final Rule supporting the final CPP.

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

Commenters rejected claims that increased use of na tural gas in the power sector will increase natural gas price volatility. Commenters specifical ly rejected claims that natural gas is inherently volatile and should not be increasingly relied upon for power generation. Commenters stated that none of the root causes of volatility would be exac erbated by increased use of gas in the power sector. Commenters stated that natural gas producer s and pipeline companies have invested heavily to enhance gas deliverability and mitigate supply shocks.

Commenters stated that concerns that increased natu ral gas demand "could add upward pressure on natural gas prices" are unwarranted. Commenters referred to Figure 8, Henry Hub Natural Gas Price (2011$/MMBTU), which shows a range of dif ferent price forecasts relative to EIA's outlook since 2009. Commenters stated that, as the EPA notes in the RIA, "current and projected natural gas prices are considerably lower than the prices observed over the past decade." Commenters stated that recent EIA projections suppo rt continued growth in natural gas supply, and natural gas pipelines and infrastructure have t he capacity to support this growth and quickly ramp up production as needed. Commenters stated the vast supplies of natural gas as a result of U.S. shale plays mean that there is enough natural gas available to power and heat homes and businesses and run vehicles for generations to come . Commenters stated that a stable and abundant supply of natural gas will provide for mar kets, making natural gas an attractive option for power generation, transportation, industrial an d residential uses.404

Commenters stated that natural gas price volatility is defined as "sustained, unpredictable price movements" that cause uncertainty for both users an d producers of natural gas. Commenters stated that expected seasonal price fluctuations (e .g., due to greater demand for heating) do not constitute "volatility" in the proper use of the te rm. Commenters stated that, apart from localized price impacts experienced in the Northeast during t he polar vortex as a result of regional pipeline constraints, since 2000, the U.S. has experienced t hree noteworthy periods of price volatility: (1) the California energy crisis in 2000-2001; (2) the hurricanes of 2005; and (3) the price spike in 2008. Commenters stated each of these events provid ed a different lesson in potential causes of price volatility: deliverability issues, supply sho cks, and erratic market behavior. Commenters stated that, in each case, as described below, circ umstances have changed such that similar events, if they occurred today, would not lead to s imilar volatility.

• First, in the case of the California energy crisis, a steep rise in demand for natural gas-fired power generation was followed by erratic trading behavior and asymmetric management of physical infrastructure. T his behavior significantly hindered "deliverability" - the ability of supplier s to meet natural gas demand. As described previously in this section, deliverabilit y of gas throughout the U.S. has improved markedly since 2000, with over 150 Bcf/d o f pipeline capacity added from 2001 to 2011. The industry has continued to in vest in additional pipeline capacity, adding 2,400 miles in 2011 alone. A robus t pipeline infrastructure and expanded storage capacity ensures that natural gas is available when and where it is needed, and helps avert price spikes caused by d eliverability problems.

• In the second period of price volatility, extreme w eather conditions knocked out production and transportation facilities and caused a sudden, prolonged loss of 6 Bcf/d of natural gas production from the Gulf of Me xico. The price volatility caused by Hurricane Katrina is indicative of a supp ly problem that bears no resemblance to the supply impact of potential expan ded power sector demand. Long lead times for compliance with the proposed gr eenhouse gas regulations will give the market several years to anticipate th e demand increase. With a hurricane, the market has only days to react. In ad dition, were another hurricane or major weather event to occur, we would expect ve ry different fuel supply response. Increasing onshore unconventional natural gas production in diverse geographic locations combined with significant infr astructure investment to move that gas to markets has resulted in diversified sup plies and redundancy in the system that would minimize the impact of regional w eather events.

• During the third period, a natural gas price rise f ollowed general global commodity price inflation. Prices rose steeply in e verything from oil to wheat, and then returned back to pre-inflation levels. The market's reaction to the global commodity price bubble was explained in part by an expectation on the part of commodity traders that natural gas and oil prices w ere inextricably linked. But in the ensuing years, natural gas and oil prices in th e U.S. have definitively decoupled from one another. The narrowing of the co rrelation range as shown in Figure 9 (Correlation between natural gas and crude oil, 1997-2013) demonstrates that natural gas prices have become less correlated with the price of oil over the past 15 years. In today's market, a dramatic and sh arp increase in the price of oil405 would not have the same impact on the price of natu ral gas as it would have had historically.

Commenters stated that, outside of these three anom alous events, prices in the period from 2000 to 2010 were relatively stable, and considering the mitigating factors discussed above, there is nothing to suggest that increased use of natural ga s in the power sector would cause a market disruption similar to these episodes. Commenters st ated this confirms that natural gas will remain a stable, reliable fuel source such that it is appr opriate to rely increasingly on the fuel for power generation.

Commenters stated that, in addition to the changes to deliverability and market pricing, production from shale formations distributed throug hout the U.S. has fundamentally changed the industry's ability to respond to price signals. Com menters stated that, in conventional production, higher prices drive producers to increase explorati on, but the link and timing to actual production is lagged and imperfect. Commenters stated producti on from shale formations reduces exploration risk significantly, and allows producer s to increase production far more responsively. Commenters stated that, given the size of the techn ically recoverable resources in the U.S., producers will be able to respond quickly to market signals in order to meet increasing demand. Commenters stated that, with the ability to react e fficiently to price signals, production volumes should further significantly reduce the risk of sus tained, unpredictable price movements. Commenters stated this is a major benefit of the si ze of the technically recoverable total natural gas resource base. Commenters stated the rapid repl enishment of natural gas storage levels this past injection season is a perfect, real-world exam ple of how quickly producers are able to respond to market needs. Commenters stated the 2013 -2014 winter was severe and the rare, 1-in30 winter caused natural gas storage volumes to be depleted to levels not seen since 2003. Commenters stated that, due to significant producti on increases from natural gas producers, storage injections set weekly records throughout th e injection season; the April 1 to October 31, 2014 total injection volume set a new season record at 2,734 Bcf.

Comment 2: Commenters stated the EPA's proposal for increasing the dispatch of natural gas combined cycle units will lead to increases in natu ral gas prices and/or price volatility.

Response 2: The EPA disagrees with the commenters’ interpretati on of the rule, and we believe the commenters’ analyses do not reflect the flexibi lities of the final rule. The rule does not require specific EGUs to take specific actions, and we believe our analysis to be appropriate. The 111(d) final rule requires that states develop plan s that establish emission standards for affected EGUs. We are providing states with substantial flex ibility as to how they structure those plans to achieve the 111(d) requirements. The flexibility in cludes, for example, the choice of approaches, trading, time to develop plans, additional time bef ore the start of the interim performance period (postponed from 2020 until 2022), and the ability t o shift emission rate achievement between performance periods. In response to additional anal ysis and many comments, we have modified the proposal and RIA – the establishment of CO2 emi ssion reduction standards is regionally based. The Building Blocks are not prescriptive, an d states may consider local circumstances as they develop their plans, including system reliabil ity, fuel diversity, the “useful life” of generation assets, other regulatory requirements an d infrastructure. See sections V.A, V.D,406

VIII.A, VIII.C.1 and VIII.G.2 of the final rule pre amble of the CPP and Chapter 3 of the GHG Mitigation Measures TSD for the CPP Final Rule supp orting the final CPP.

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

Price increase and increased costs

Commenters stated that independent analysts project the utility gas demand may rise threefold above the EPA's forecast and suggested that consume rs and energy intensive industries will bear the brunt of these gas price increases.

Commenters referenced a July 2010 APPA report and s tated that if we fully implement this building block, it would double the amount of natur al gas used in power production, which would necessitate increasing gas production from al l sources in the market by 33%. Commenters stated such an increase may be pos sible but would certainly have profound effect on market pricing and supply distribution as well as general competition for supply.

Commenters stated the EPA failed to fully account f or impacts to fuel price-stability in the evaluation of impacts resulting from removing coal generation from the generating portfolio mix. Commenters stated that, due to the shift in the gen erating portfolio mix resulting from the proposed rule, delivered electricity costs will inc rease by between 12% and 17% between 2017
and 2031. Commenters stated this increase in the co sts of electricity would have a direct effect on NvMA's members, for whom electricity is already a substantial cost.

Commenters stated that one example of risk associat ed with artificially accelerated changes in dispatch is that existing facilities may be forced to purchase additional gas outside of their existing contracts; thus incurring additional costs on the spot market. Commenters stated spot market pricing is volatile and usually higher than long term contract pricing.

Commenters claimed that the proposed rule will affe ct PUCs' statutorily-defined rate-setting and resource planning objectives. Commenters stated tha t EPA's application of its interpretation of its authority under Section 111(d) of the Act will like ly force existing source retirements and the redistribution of electric generation from higher e mitting, more affordable supply-side sources to lower emitting, high cost supply-side sources, whic h the commenters believed will result in increased public utility rates and changes to utili ty resource plans.

Commenters claimed that the proposed rule will affe ct PUCs' statutorily-defined rate-setting and resource planning objectives. Commenters stated tha t EPA's application of its interpretation of its authority under Section 111(d) of the Act will like ly force existing source retirements and the redistribution of electric generation from higher e mitting, more affordable supply-side sources to lower emitting, high cost supply-side sources, whic h the commenters believed will result in increased public utility rates and changes to utili ty resource plans.

Price volatility407

Commenters expressed concern that the EPA's proposa l for increasing the dispatch of natural gas combined cycle units will lead decreased diversity in electric generation and to high price volatility.

Commenters expressed concern that the phasing out o f older coal-fired power plants by increasing electricity generation at natural gas-fi red power plants will increase historically volatile fuel prices.

Commenters stated that such an unbalanced generatio n mix leaves Florida extremely vulnerable to natural gas price volatility and supply constrai nts. Commenters, citing a November 2014 NERC report, stated that with greater reliance on n atural-gas-fired generation, the resiliency and fuel diversification that is currently built into t he electric system may be degraded.

Commenters stated that EPA's proposal to increase t he dispatch of natural gas combined-cycle (NGCC) units up to 70%, with corresponding reductio ns in the output of coal plants, would expose consumers and energy-sensitive industries to highly volatile electric prices. Commenters stated that, without a diverse electric generation portfolio, sustained cold weather events such as those experienced in past winters could lead to nat ural gas supply disruptions that could compromise the electric system and could have serio us adverse repercussions for energy security and electric reliability. Commenters recommended th at the re-dispatch building block be eliminated to reduce the risk of natural gas price volatility and related electric price spikes that this option would entail.

Commenters stated that Building Block 2 ignores the importance of portfolio diversity.
Commenters stated the retirement of coal-fired EGUs places more emphasis on NGCC EGUs, thereby limiting portfolio diversity and creating s ignificant vulnerability to natural gas price fluctuations. Commenters stated that natural gas pr ices have seen significant variability over time and provided a Chart 3 which shows natural gas pric e volatility from 1990 to 2012. Due to the historic price volatility, the commenters stated it important to maintain portfolio diversity in order to minimize cost volatility to ratepayers. Co mmenters stated that, while recently the United States has enjoyed low natural gas prices, those pr ices are likely to rise in the face of increased competition for supply due to nationwide increased utilization of existing NGCC EGUs and
construction of new NGCC EGUs. Commenters stated th at additional environmental regulation may also cause natural gas prices to rise.

Commenters stated that, because the natural gas mar ket is incredibly volatile, the EPA's assumption that gas prices will stay at the current low price (GHG Abatement Measures TSD at 3-8 to 3-11) is arbitrary and capricious. Commenter s stated that this volatility is likely to be particularly true upon the implementation of EPA's Proposed Rule, which would drastically increase the demand for natural gas, despite EPA's cursory statement otherwise.

Commenters stated that, historically, natural gas p rices are highly volatile and increased use of natural gas for electricity generation is constrain ed by transmission capacity, particularly in the U.S. Northeast. Commenters stated that, while the e conomics for increased natural gas generation are favorable presently, the history of natural gas prices in the U.S. has shown that current natural gas price trends can shift rapidly and unpredictably. By creating goals for states to increase their natural gas consumption, commenters stated the EPA is only increasing the408

likelihood of potential steep natural gas price inc reases that would be passed on to ratepayers across the country as higher electricity prices. Co mmenters stated that the more electricity that is natural gas fired, the greater would be the effect on ratepayers of a steep increase in natural gas prices.

Commenters stated that, as coal units are forced to retire to meet the CPP goals, this will cause more volatility in the price of natural gas, which will begin a never-ending trend upward as demand outstrips supply. Commenters stated the MISO has conducted an economic-only analysis that has estimated that in its region alon e, the EPA proposal will cause the retirement of
an additional 14 GW of coal units within the MISO f ootprint. While natural gas is likely to be substituted for lost inexpensive coal resources, th ere will be a rush to gas as utilities and
merchants scramble to fill the void with NGCC resou rces.

Commenters expressed concern that the cost of spot energy can be difficult to control, especially during inclement weather. Commenters noted that, du ring last year's polar vortex Hoosier Energy was subject to natural gas constraints and c ould not run its owned natural gas generation, yet Merom, on the other hand, is able to stockpile months of coal to avoid market and fuel price volatility.

Commenters expressed concern that, while the recent natural gas renaissance has provided a stable and relatively clean fuel source, history sh ows the price and availability of natural gas to be extremely volatile over time. Commenters noted t hat last spring during the polar vortex event, many municipal gas plants were called upon to gener ate but could not do so due to the unavailability of natural gas supply due to supply deficiencies and pipeline constraints.

Commenters expressed concerned that natural gas is subject to substantial price fluctuations that create market uncertainty. Commenters suggested the EPA should consider the consequences of using a price-volatile fuel such as natural gas to meet our needs year-round. Commenters stated that renewable energy is a more price-stable form o f electricity generation. Commenters stated that natural gas is more price volatile than renewa ble energy or coal power generation, and is particularly susceptible to spiking during cold wea ther.

Commenters stated that, while the EPA assumes natur al gas prices will remain low and supplies high, the natural gas market is becoming increasing ly volatile. Commenters suggested the EPA lower the NGCC capacity factor to a more realistic goal.

Commenters expressed concern that future increased gas prices may render NGCC generation less economic and adequate coal-fired resources may not be available to meet resource adequacy requirements in PJM. Commenters contended that PJM' s existing coal fleet may not be able to provide adequate flexible operations as most existi ng coal plants were not originally designed for load following and/or extended low output generatio n. Commenters are also concerned that establishing a dispatch-based mitigation goal that impacts other existing generation types without thorough consideration of the impacts to resource a dequacy may significantly degrade reliability. Commenters stated this concern is best exemplified by the experiences in the PJM region during the January 2014 polar vortex event, when a signifi cant percentage of PJM's entire generation portfolio was out of service during that period whi ch included 9,700 MW of gas generation (36% of PJM's total gas generation capacity) due to plan t outages and gas supply disruption.409

Commenters stated that, despite these challenging c onditions, PJM's robust generation portfolio was able to weather the period without major servic e outages. Commenters stated they are concerned that, under a future scenario where the E PA's BB1 and BB2 proposals have restructured the PJM generation portfolio, there ma y be significant declines in resource adequacy, reserve margins and less overall flexibil ity to manage an extreme cold weather event.

Commenters did not agree that natural gas prices wi ll remain relatively flat through 2030. Commenters stated that, historically, natural gas p rices have been volatile due to federal policies limiting the use of gas, imbalances between supply and demand, and infrastructure issues, among other issues. Commenters provided Figure 4 showing the volatility of natural gas as compared to coal since the late 1990's. Commenters stated the p roposed rule would expose OMU's ratepayers to significantly more natural gas price risk. Comme nters stated the impact of natural gas price volatility was recently demonstrated during the Pol ar Vortex of 2014. Commenters stated that were OMU's ratepayers exposed to these high natural gas prices during the Polar Vortex, they
would have had electric bills that were more than 3 0% higher than normal. Commenters provided Figure 5 and Figure 6 to show the extreme volatility of natural gas and the stability of coal prices during the 2014 "Polar Vortex."

Commenters stated the move to a greater dependence on natural gas places Florida and the City's electric grid at a greater risk to price spikes, du e to the volatility of natural gas, or inability to meet demand if there is a significant curtailment o f natural gas within the state, region or country (similar to that experienced by Florida and other r egions during the oil embargos of the 1970's).

Commenters stated that, as building block 2 is empl oyed to displace coal, electric power and its consumers will be subject to large swings in fuel p ricing. Commenters stated TVA passes along all fuel costs used in the production of electricit y to its customers every month via a fuel cost adjustment mechanism and these fuels (coal, natural gas, uranium, purchased power, etc.) constitute about one-third of TVA's operating costs . Commenters stated that natural gas price volatility, in stark contrast to coal price stabili ty, will be experienced by consumers every month through the fuel cost adjustment mechanism as the r esult of the proposed rule's building block 2. Commenters referred to EIA data comparing the price fluctuation between natural gas and coal and stated the price volatility of natural gas stan ds in stark contrast to coal's historically stable price. Commenters stated this natural gas volatilit y continues in spite of growing natural gas production.

Commenters expressed concern that increased use of natural gas nationally could lead to increased market dislocations, such those as seen i n the winter of 2013-2014, as well as overall increasing prices and price volatility due to highe r gas demand. Commenters stated that, depending on the magnitude of these Issues, there c ould be implications for maintaining reliable natural gas supply in the ERCOT region for electric generation in the future.

Comment 3: Commenters stated that the increased reliance on na tural gas that is associated with a 70 percent NGCC generation utilization rate in th e CPP ignores the economic realities of procuring natural gas, as well as the physical chal lenges of fuel delivery to NGCC units.410

Response 3: The EPA disagrees with the commenter’s interpretati on of the rule, and we believe that the commenter’s analysis does not reflect the flexibilities of the final rule. The 111(d) final rule requires that states develop plans that establ ish emission standards for affected EGUs, but it not require that specific plants achieve specific c apacity factors. We are providing states with substantial flexibility as to how they structure th ose plans to achieve the 111(d) requirements. The flexibility includes, for example, the choice o f approaches, trading, time to develop plans, additional time before the start of the interim per formance period (postponed from 2020 until 2022), and the ability to shift emission rate achie vement between performance periods. In response to additional analysis and many comments, we have modified the proposal and RIA –
the establishment of CO2 emission reduction standar ds is regionally based. The Building Blocks are not prescriptive, and states may consider local circumstances as they develop their plans, including system reliability, fuel diversity, the “ useful life” of generation assets, other regulatory requirements and infrastructure. See sections V.A, V.D, VIII.A, VIII.C.1 and VIII.G.2 of the final rule preamble of the CPP and Chapter 3 of the GHG Mitigation Measures TSD for the CPP Final Rule supporting the final CPP.

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

Commenters stated that firm fuel arrangements and s pot market natural gas procurement can be volatile and costly. Commenters provided the follow ing additional points:

The CPP is devoid of any analysis discussing the ec onomic reality of procuring natural gas for NGCC units. If NGCC generators are to achieve a 70 percent utilization rate, these generators must consider purchasing firm fuel from a supplier via a firm-fuel contract. These firm fuel arrangements are not presently the industry standar d due to their exorbitant costs and practical difficulties. Natural gas suppliers are generally b etrothed first to natural gas distribution utilitie s and their consumers regarding the delivery of fuel. Electric generators take a subordinate role to gas utilities even if the generator has a firm fuel contract. NGCC units that do not have firm fuel arrangements rely on the spot market to acquire fue l. This spot market can be volatile, especially during periods of high demand. This scenario presen ted itself during the polar vortex this past winter. Natural gas units that did not go offline d uring the polar vortex were required to purchase fuel at high spot prices during the month of Januar y, resulting in a record setting amount of uplift payments in excess of $650 million in the PJM footp rint.

Comment 4: Some commenters focused mainly on fossil portfolio diversity, while others insisted that portfolio diversity is critical.

Response 4: The EPA believes that the 111(d) final rule provid es states with the flexibility to develop plans that consider reliability and local c ircumstances. See sections V.D of the final rule preamble of the CPP,Chapter 3 of the GHG Mitigation Measures TSD for the CPP Final Rule supporting the final CPP, and the Regulatory Impact Assessment of the final CPP..

The following are summaries of the specific public comments under this comment:411

Commenters stated the portfolio diversity of the 21 st century must be a combination of renewable energy generation and demand-side resourc es including efficiency, demand response, storage, etc. Commenters stated that actual diversi ty provides essential economic and reliability certainty that cannot be achieved through fossil fu el means alone.

Comment 5: Commenters suggested the CPP must maintain fuel div ersity to minimize cost.

Response 5: The EPA disagrees with the commenters’ interpretati on of the rule, and we believe the commenters’ analyses do not reflect the flexibi lities of the final rule. The 111(d) final rule requires that states develop plans that establish e mission standards for affected EGUs. We are providing states with substantial flexibility as to how they structure those plans to achieve the 111(d) requirements. The flexibility includes, for example, the choice of approaches, trading, time to develop plans, additional time before the s tart of the interim performance period (postponed from 2020 until 2022), and the ability t o shift emission rate achievement between performance periods. In response to additional anal ysis and many comments, we have modified the proposal and RIA – the establishment of CO2 emi ssion reduction standards is regionally based. The Building Blocks are not prescriptive, an d states may consider local circumstances as they develop their plans, including system reliabil ity, fuel diversity, the “useful life” of generation assets, other regulatory requirements an d infrastructure. See sections V.A, V.D, VIII.A, VIII.C.1 and VIII.G.2 of the final rule pre amble of the CPP and Chapter 3 of the GHG Mitigation Measures TSD for the CPP Final Rule supp orting the final CPP, and the Regulatory Impact Assessment of the final CPP.

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

Commenters stated the EPA's proposal to increase th e dispatch of NGCC units to 70% while reducing the output of coal plants would require a fundamental revision to the economic dispatch process used by RTOs in both regulated and unregula ted states, and would expose consumers and energy-sensitive industries to highly volatile electric prices. Commenters stated that, while West Virginia does not have natural gas combined-cy cle units, the impact of this building block
on other states would lead to reductions of West Vi rginia's coal and electricity exports to other

states.

Commenters stated that fuel diversity ensures compe tition and lower prices. Commenters stated that, when demand increases throughout the US, in a ll industrial sectors, not just the utility sector, higher gas prices will result in increased prices for electric power. Commenters noted that EIA projects that the RFC region, which includes Oh io, confronts one of the highest growth demands for natural gas as utilities shift from coa l. Commenters stated that it is unwise to rely too heavily on any single source of energy because, like any other commodity, natural gas is susceptible to fluctuations in supply, demand and p rice - not to mention the specter of additional environmental and drilling regulations, which could have a serious impact on future production and price levels.412

Commenters stated that the lack of fuel diversity w ould negatively impact on cost. Commenters stated that, by increasing reliance on natural gas, the proposed rule creates a market in which many participants want the same product which will likely increase the price demanded. Commenters stated the upper Midwest relies heavily on natural gas for winter heating, and it is also used in industrial processes such as ethanol p roduction. Commenters stated that additional build-up of natural gas to support grid reliability will increase the price for the product and could decrease the availability that some parts of the na tion have enjoyed in recent years. Commenters stated that natural gas contracts to fuel natural g as-fired electric generation are usually limited by the natural gas providers to 3 to 5 years and, with the anticipated increased reliance on natural gas, there will now be a strong incentive for gas p roviders to negotiate for higher prices each
time contracts are discussed for renewal.

Commenters stated that mandating a 70 percent capac ity factor will erode the system's ability to optimize around economics and ultimately drive up s ystem costs for Southern Company customers because previously Southern Company has u tilized its ability to dispatch its generation fleet to reliably serve customers in the lowest cost manner. Commenters stressed the danger of disregarding the uncertainty of future fu el prices and the potential benefits of utilizing a variety of fuels to mitigate those uncertainties. Commenters indicated that Southern Company is dedicated to providing a diverse electricity gen eration portfolio to the benefit of approximately 4.4 million customers in the Southeast, nearly half of whom earn less than $40,000 per year. According to the commenters, in 2012, across the So uthern Company system, fuel costs were reduced by over $1 billion by leveraging a diverse fuel mix to the benefit of its customers. 246 Commenters added that while natural gas has been re latively cheap in the past few years, the ability to invest in and dispatch other generation resources (e.g., coal) is vitally important to maintaining a reliable and cost effective electrici ty supply when natural gas prices fluctuate. Commenters stated that history, especially recent e vents this past winter, proves natural gas fluctuations are inevitable, and that in the first quarter of 2014, Southern Company took advantage of its fuel diversity during a period of higher natural gas prices to deliver over $100 million in fuel cost savings to its customers by in creasing its reliance on coal.

Commenters stated that it is in the national intere st for utilities to have the opportunity to maintain generation fleet diversity in order to hed ge against fuel price fluctuations, and thereby protect customers. Commenters indicated that for de cades available coal generation has mitigated against natural gas price increases and v ice versa - the wide pendulum swing of fuel costs can only be damped by maintaining a diverse p ortfolio of generation assets. Commenters asserted that for Southern Company, a balanced gene ration portfolio is not merely an objective - it is an obligation that comes with the Company's d uty to serve its customers.

Commenters stated that recent analysis conducted by Georgia Power assessed the impact that plausible natural gas price forecasts for the year 2020 would have on the most cost-effective mix of generation resources. According to the commenter s, the analysis showed that natural gas prices on the lower end of the expected range were projected to result in as much as 50 percent of generation being provided by natural gas and onl y 18 percent from coal, but under a higher natural gas price scenario, the company would minim ize costs for its customers by generating only 28 percent from natural gas and 40 percent fro m coal. Commenters indicated that the EPA's proposal would prevent utilities from continuing to develop a fleet that relies on diverse fuel
mixes for the benefit of their customers. Commenter s provided a table depicting Southern413

Company's historical generation mix in terms of the percent contribution to total power generation by coal, gas, nuclear, and hydro/other o ver the time period of 2007 through September 2014.

Commenters provided an example which commenters cha racterized as is a microcosm of Southern Company's ability to economically dispatch and therefore rely on a diverse fuel mix to ensure the lowest possible costs for Southern Compa ny's customers: Mississippi Power and Gulf Power's Plant Daniel Plant which consists of four g enerating units - two coal-fired sub-critical drum type units (Units 1 and 2) and two NGCC units (Units 3 and 4), with Units 1 and 2 each approximately 510 MW (net summer capacity) and Unit s 3 and 4 approximately 486 MW (net summer capacity). Commenters provided a figure show ing the capacity factors for Plant Daniel's four units over the period of 2002 to 2013. Accordi ng to the commenters, the EPA's proposed rule would turn this historic trend on its head, ma ndating that Plant Daniel Units 3 and 4 operate at a 70 percent capacity factor even when economics , logic and common sense would suggest
that Plant Daniel Units 1 and 2 should bear the bur den of generation.

Comment 6: Commenters indicated that increased demand for nat ural gas will likely increase prices, thus raising costs for customers.

Response 6: The EPA disagrees with the commenters’ interpretati on of the rule, and we believe the commenters’ analyses do not reflect the final r ule. We believe our analysis of natural gas prices is appropriate. The 111(d) final rule requir es that states develop plans that establish emission standards for affected EGUs. We are provid ing states with substantial flexibility as to how they structure those plans to achieve the 111(d ) requirements. The flexibility includes, for example, the choice of approaches, trading, time to develop plans, additional time before the start of the interim performance period (postponed from 2 020 until 2022), and the ability to shift emission rate achievement between performance perio ds. In response to additional analysis and many comments, we have modified the proposal and RI A – the establishment of CO2 emission reduction standards is regionally based. The Buildi ng Blocks are not prescriptive, and states may consider local circumstances as they develop their plans, including system reliability, fuel diversity, the “useful life” of generation assets, other regulatory requirements and infrastructure. See sections V.A, V.D, VIII.A, VIII.C.1 and VIII.G. 2 of the final rule preamble of the CPP and Chapter 3 of the GHG Mitigation Measures TSD for th e CPP Final Rule supporting the final CPP, and the Regulatory Impact Assessment of the fi nal CPP.

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

Commenters stated the costs of natural gas have his torically been extremely volatile and, with the increase in the demand for gas nationally, are expected to increase. Commenters stated the EPA has not adequately addressed the potential incr ease in the cost of compliance which is tied to the future price of natural gas.

Commenters stated that increases in natural gas dem and resulting from implementation of the Clean Power Plan are likely to raise gas prices and overall consumer prices nationally and in414

Arizona. Commenters stated the EPA Building Block s cenario would require a wholesale retirement of the coal capacity in Arizona, shiftin g the cost of fuel for ratepayers from coal to more expensive natural gas. Commenters stated the i mpact of additional gas demand required for compliance would come at a time when exports (lique fied natural gas and pipeline exports to Mexico) are also growing rapidly. Commenters referr ed to a study by Pace Global.

• Pace Global estimated costs of both fuel and purcha sed power for electric ratepayers in the Arizona Glide Path scenario and t he EPA Building Block scenario. Commenters stated that, noting the uncert ainty associated with the longterm impacts to natural gas pricing associated with the incremental demand under a Clean Power Plan compliance scenario, these costs were assessed both with and without the impacts of potential higher gas pricing . Commenters referenced their Exhibit 22, which compares these costs, and stated the analysis shows that the current building block plan would cost electric rat epayers up to 40% more in fuel and purchased power costs between 2020 and 2030 as a result of fuel switching and expected increases in natural gas prices over t ime.

• Pace Global estimates that all other things constan t, power sector consumption could increase from approximately 24 Bcf/d in 2015 to 47 Bcf/d by 2030 under the EPA Building Block scenario. Commenters stated that Pace Global estimates that this incremental increase in national consumpt ion levels would result in price increases nationally at the Henry Hub pricing point . When compared to a reference case outlook of Henry Hub pricing, commen ters stated the price increase under the Clean Power Plan is around $1.35 on average between 2020 and 2030, with deltas in the $1.50-2.00/MMBtu range by the end of the 2020s. Commenters noted Henry Hub pricing projections for the reference case and the EPA Building Bock scenarios are presented in Exhibi t 24.

Commenters stated that natural gas utilities would be negatively affected by the Proposal. Commenters stated that UNSG customers would be impa cted by higher costs of service driven by a combination of higher gas commodity costs, tra nsportation price increases, and storage development costs and provided the following additi onal information:

• The impact of gas commodity price increases alone, assuming an average increase in Henry Hub pricing of $1.35/MMBtu (PACE Global As sessment, Appendix B) between 2020 and 2030, would be $18 million annuall y, totaling $200 million for 2020 through 2030.

• Transportation costs for UNSG customers would incre ase on an explicit basis, as well as from implied risk. Explicitly, the costs fo r transportation would increase as market demand for firm transportation increases and pipeline companies seek recovery of pipeline system expansion costs. While UNSG is not a power producer, pipeline companies spread the costs of sy stem expansion across all their users. Therefore, UNSG customers will bear the cost s of recovery of new pipeline construction, even though their own demand is not e xpected to materially
increase.415 • Increased demand for transportation capacity will i ncrease the bid price for available capacity. In addition to bidding higher r ates for capacity, utilities and other system users also will be required to bid lon ger terms to secure the capacity. Recently, the duration of winning bids has expanded from 10 years to more than 25 years on Kinder Morgan's system. Bids of this du ration expose utilities and other system users to additional risk due to unfore seeable future conditions.

• Commenters stated that UNSG customers will bear the costs of gas storage, which will need to be developed to support the increased natural gas-fired generation resulting from the proposed rule. Existing storage facilities in New Mexico and Texas are too remote to assist in managing pipeline reliability in Arizona; therefore, storage will need to be built in or near Arizona. Without any change in UNSG customers' usage, the increase in natural gas demand from the power sector will require that UNSG acquire storage to en sure reliability. When combined, these increases in commodity costs, trans portation costs, and storage costs will increase both electric and gas rates for UNSG customers.

Comment 7: Commenters stated the EPA underestimated not only how much the proposed rule will raise electricity prices, but natural gas pric es as well.

Response 7: The EPA disagrees. The analysis cited by the comme nter does not reflect the final rule. The 111(d) final rule requires that states de velop plans that establish emission standards for affected EGUs, and states may consider local circum stances as they develop their plans, including system reliability, fuel diversity, the “ useful life” of generation assets, other regulatory requirements and competing demands for natural gas. We believe our analysis is appropriate and we do not expect the 111(d) final rule to result in large increases in natural gas prices. See sections V.A, V.D, VIII.A, VIII.C.1 and VIII.G.2 of the final rule preamble of the CPP, Chapter 3 of the GHG Mitigation Measures TSD for the CPP Fi nal Rule supporting the final CPP, and the Regulatory Impact Assessment of the final CPP.

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

Commenters referenced an EVA study (EVA, Energy Mar ket Impacts of Recent Federal Regulations on the Electric Power Sector, November 2014) and stated that (1) both "the cost of electricity and natural gas will be impacted in lar ge part due to an almost 135% increase in the wholesale price of natural gas (100% in real dollar s), from $2.82/mmbtu in 2012 to approximately $6.60/mmbtu ($5.63) in 2020"; (2) the se increases are due to baseline market and policy impacts between 2012 and 2020 as well as sig nificantly increased pressure on gas prices resulting from recent EPA regulations on the power sector as well as the proposed rule; (3)
America's industrial sector would be hit the hardes t, seeing their electricity and gas costs soar 64% by 2020 over 2012 costs; and (4) the study note s that skyrocketing "operational costs in the industrial sector are of particular concern for ene rgy intensive industries in the U.S. such as aluminum, steel and chemicals manufacturing, which require low energy prices to compete."416

Comment 8: Commenters generally stated the EPA's proposal woul d lead to significant increases in the cost of natural gas leading to sev ere economic impacts and that EPA has not adequately addressed infrastructure costs.

Response 8: The EPA disagrees with the commenters’ interpretati on of the rule, and we believe the commenter’s analysis does not reflect the final rule. We believe that our analysis is appropriate, and we do not believe that the 111(d) final rule will lead to large increases in gas prices or to large increases in electricity prices. The 111(d) final rule requires that states develop plans that establish emission standards for affecte d EGUs. We are providing states with substantial flexibility as to how they structure th ose plans to achieve the 111(d) requirements. The flexibility includes, for example, the choice o f approaches, trading, time to develop plans, additional time before the start of the interim per formance period (postponed from 2020 until 2022), and the ability to shift emission rate achie vement between performance periods. In response to additional analysis and many comments, we have modified the proposal and RIA –
the establishment of CO2 emission reduction standar ds is regionally based. The Building Blocks are not prescriptive, and states may consider local circumstances as they develop their plans, including system reliability, fuel diversity, the “ useful life” of generation assets, other regulatory requirements, infrastructure, and competing demands for natural gas. See sections V.A, V.D, VIII.A, VIII.C.1 and VIII.G.2 of the final rule pre amble of the CPP, Chapter 3 of the GHG Mitigation Measures TSD for the CPP Final Rule supp orting the final CPP, and the Regulatory Impact Assessment of the final CPP.

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

Commenters stated the EPA's proposal for increasing the use of natural gas combined-cycle units, in addition to 40 gigawatts of new natural g as combined-cycle capacity that the EPA projects to come online form 2020 to 2030, will lea d to significant increases in natural gas prices, well above the EPA's projections. Commenters stated that increasing electricity demand, coupled with decreased supply, is a recipe for skyrocketing electricity prices that will be passed directly
on to the consumers. Commenters stated their area h as already seen increased costs due to renewable standards and mass associated plant closu res. Commenters stated their communities
and consumers cannot afford another round of EPA-re lated plant closures.

Commenters stated the EPA's proposal would lead to a significant increase in the cost of natural gas for both electricity generators and other consu mers. Commenters stated that the EPA's own projections demonstrate that this cost increase wou ld be especially severe in the near term.
Commenters stated these increased costs will make i t more difficult for companies to maintain low prices, more difficult for some families to mak e ends meet, and will lead to significant job losses in industries that are sensitive to the pric e of natural gas. Commenters stated these impacts, in combination with the up to 49 gigawatts of additional coal retirements that EPA projects by 2020 (Regulatory Impact Analysis at 3-3 2), could deal a severe blow to American
workers.

Commenters noted that the EPA projects that the Cle an Power Plan will lead to further increases in delivered natural gas prices of 7.5% to 11.5% in 2020 (CPP RIA, June 2014). Commenters stated that the U.S. DOE's projection for Henry Hub wellhead natural gas prices do not account for the increase in natural gas demand expected to result from EPA's proposed Clean Power417

Plan. Commenters stated that the Henry Hub wellhead prices are a key determinant of future electricity prices. Commenters stated the EPA's CPP will substantially increase electric prices for
America's 65+ households. Commenters stated the add itional baseload generation capacity projected to retire due to the Clean Power Plan wou ld increase the risks of brownouts, load curtailments, and other power disruptions in region s impacted by these retirements. Commenters stated the existing EPA rules are already driving u p the costs of natural gas and electricity prices and the new proposal will add even more unacceptabl e costs.

Commenters stated MRES expects future demand for tr ansmission expansion to be great under
the Clean Power Plan. Commenters stated the time an d money associated with expanding the natural gas infrastructure needed to fuel these exp ansions is beyond substantial, and has the potential to cripple the U.S. economy and put basic electricity service beyond the reach of the poorest Americans. Commenters stated the EPA has no t included in its cost estimates the expense to build this essential infrastructure, and is a major shortcoming of its economic analysis.

Commenters stated the proposed rule does not proper ly account for infrastructure from either a timing or a cost perspective. Commenters stated the costs of this shift in generation toward NGCC would require an unprecedented investment in i nfrastructure, including construction of new NGCC capacity, natural gas pipelines, and trans mission infrastructure. Commenters stated that any new infrastructure project that would deli ver electricity to northern Nevada is complicated by the predominance of federal lands; a ny such project would require lengthy National Environmental Policy Act analyses and coul d trigger review under the Endangered Species Act.

Commenters expressed concern that that prices of na tural gas are projected to increase significantly, and this could affect millions of lo w-income households where energy bills represent 10 percent or more of income. Commenters noted the EIA's Annual Energy Outlook estimates that residential natural gas prices will increase by about 1.4 percent per year, from $10.69 to $13.80 per 1,000 cubic feet (in 2012 doll ars), between 2012 and 2030 in the reference
case. Commenters stated a Clean Power Plan that doe s not resort to significant increases in natural gas use and achieves CO2 reductions by low cost methods, starting with efficiency, would have significantly less overall impact and mu ch less impact on low-income households than the draft CPP. Commenters stated the trajector y proposed by the CPP is about the same as the natural gas reference case in EIA AEO 2014 (Tab le 13). Commenters stated the price increases estimated there would cause significant h ardship to low-income households, especially those using natural gas for heating, which is the c ase for about half of U.S. households.
Commenters stated the EIA estimates that residentia l natural gas prices will increase by almost 30 percent between 2012 and 2030, which could be de vastating for low income households especially if the median household income continues the downward trend it has exhibited since
about 2006. Commenters stated increased use of natu ral gas at higher prices than the reference year of 2012 would also put pressure on electricity prices.

Comment 9: Commenters stated that the EPA should conduct addit ional natural gas supply and pricing analysis including different model years an d state-specific analyses.418

Response 9: The EPA disagrees to the extent that we believe our analysis appropriately considers natural gas supplies, infrastructure and competing demands. The IPM model includes a natural gas supply module that includes demand and supply of natural gas nationwide. In response to additional analysis and many comments, we have modified the proposal and RIA. States may consider local circumstances as they dev elop their plans, including system reliability, fuel diversity, the “useful life” of generation ass ets, other regulatory requirements, competing demands for natural gas, and infrastructure. See se ctions V.A, V.D, VIII.A, VIII.C.1 and VIII.G.2 of the final rule preamble of the CPP and Chapter 3 of the GHG Mitigation Measures TSD for the CPP Final Rule supporting the final CPP , and the Regulatory Impact Assessment of
the final CPP.

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

Commenters stated that natural gas is a globally tr aded commodity and the price will eventually more closely reflect the global prices. Commenters stated that cheap, domestic natural gas prices are likely a short-term phenomenon and will move cl oser to either the historic domestic price volatility or possibly even soar to a level much hi gher based on global demand. Commenters asked whether the EPA and Department of Energy (DOE ) along with the Federal Energy Regulatory Commission (FERC) adequately modeled nat ural gas price scenarios given this likely market change?

Commenters stated the 2012 model year does not take into consideration variations in natural gas prices and how states will dispatch NGCC units econ omically. Commenters suggested the following analyses are needed: (1) natural gas pric ing sensitivities should be taken into consideration in the CPP cost benefit analysis and the CPP should identify how NGCC dispatch to displace coal will impact electricity rates in e ach state and (2) the CPP should include in their cost benefit analysis a forecasted price for carbon reductions per ton or other methods to artificially inflate gene ration cost to drive econ omic dispatch by states to facilitate the NGCC generation required to meet emission targets.

Commenters stated the EPA should evaluate any varia nce in natural gas supply or pricing under this proposal. Commenters stated this variable need s to be explored through sensitivity analysis and reporting of potential costs. Commenters noted that it has been well understood and documented within the electric power sector that na tural gas supply and prices play a pivotal role in determining both the current and projected futur e electricity mix, as well as electricity costs. Commenters stated that the EIA, whom EPA relies upo n for a number of key data points, routinely produces alternative scenarios in its Ann ual Energy Outlook to examine some of these alternative futures given the importance.

Commenters stated the EPA should conduct a thorough analysis of the proposed rule's impact on natural gas prices in Indiana and the effects that will have on Indiana consumers and the state's economy. Commenters stated proposed rule will great ly increase demand for natural gas, creating upward pressure on prices and operating co sts. Commenters stated the EPA's modeling shows spot prices increasing by an average of no mo re than ten percent over the 2020-2029 period (79 FR 34865). This projected increase in ga s prices is a major contributor to the increase in wholesale electricity prices EPA and others anti cipate taking place as a result of the proposed rule. Commenters stated the EPA views these project ed impacts as not unreasonable because the419

price increases in question are well within the ran ge of historical natural gas price variability (79 FR 34865). Commenters stated that the fact that har mful increases in the wholesale price of natural gas have occurred before is of little comfo rt to the Indiana consumers who will bear the brunt of EPA's proposed rule. Commenters referred t o a study by the State Utility Forecasting Group at Purdue University (SUFG) and provided the following information (Natural Gas Market Study, State Utility Forecasting Group. Nove mber 2013. http://www.in.gov/iurc/files/Natural_Gas)_Market_St udy.pdf.):

From the customer perspective, the commodity price accounts for approximately 62 percent of the average residential bill in Indiana, with the r emainder stemming from costs associated with the distribution system and trackers. Since the cos t of procuring the natural gas in the open market is passed directly to the customer in the ca ptive market with no profit to the utility, there is a direct dollar for dollar impact of changes in natural gas prices to changes in a customer's bill. Thus, if natural gas prices increase (or decrease) by $1/mmBtu, a customer's bill will increase (decrease) by $1 for every mmBtu of natural gas con sumed. To put this in perspective, consider a customer who consumes 200 therms in a month (10 the rms equal one mmBtu). For every $1/mmBtu change in the natural gas price, the custo mer's bill will change by $20.

Comment 10: Commenters stated the EPA needs to take several iss ues related to natural gas price volatility into account, adjust its assumptio ns, and then modify the states' emission reduction goals accordingly.

Response 10: The EPA disagrees to the extent that we believe our analysis appropriately considers natural gas supplies, infrastructure and competing demands. The IPM model includes a natural gas supply module that includes demand and supply of natural gas nationwide. In response to additional analysis and many comments, we have modified the proposal and RIA. States may consider local circumstances as they dev elop their plans, including system reliability, fuel diversity, the possibility of extreme events, the “useful life” of generation assets, other regulatory requirements, competing demands for natu ral gas, and infrastructure. See sections V.A, V.D, VIII.A, VIII.C.1 and VIII.G.2 of the fina l rule preamble of the CPP, Chapter 3 of the GHG Mitigation Measures TSD for the CPP Final Rule supporting the final CPP, and the Regulatory Impact Assessment of the final CPP, and the Regulatory Impact Assessment of the

final CPP.

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

Commenters stated this volatility has impacted not only the prices utilities pay for natural gas, but also the wholesale price of electricity. Commen ters cited several reported prices including above $200 per megawatt hour (MWh) during a brief c old spell in mid-December 2013 and up to $237.75/MWh during the early January 2014 freeze, a nd stated that it is very likely further price spikes will occur as the demand for natural gas inc reases for electric generation. Commenters stated that the polar vortex highlights the difficu lt economic reality NGCC units face when purchasing fuel: this economic reality is passed th rough to consumers, creating yet another420

unquantifiable, but potentially massive rate increa se as a result of the CPP and impacting reliability as stated by NERC.

Commenters stated the EPA needs to take several iss ues related to NG price volatility into account, adjust its assumptions, and then modify th e states' emission reduction goals accordingly. Commenters listed several factors that could put up ward pressure on natural gas prices, including federal policies, short-term imbalances between sup ply and demand, the availability of necessary infrastructure, and the potential for increased dem and for gas by the transportation sector. Commenters referenced a 2010 study (APPA Natural Ga s Report) and stated that an increase in demand for natural gas could put upward pressure on prices even if natural gas supply were to remain constant. Commenters stated that EPA's Propo sed Rule assumes that prices will remain relatively flat, but nothing in the Proposal or Tec hnical Supporting Documents addresses the question of whether shale gas production can actual ly occur at the levels needed to keep prices
flat.

Commenters stated that the Proposed Rule does not t ake into account the fact that some natural gas supplies come from Canada and suggested that th e EPA should consider how increased demand for Canadian natural gas could put upward pr essure on the prices paid by U.S. electric utilities and consider the impact reduced gas from Canada could have on the ability of utilities to use more gas for electric generation to reduce thei r CO2 emissions.

Commenters cited a July 15, 2010 Navigant Consultin g paper on price instability in the U.S. Natural Gas Industry which concludes that "the vita lity of and responsiveness of the supplydemand balance is the most important factor determi ning whether price volatility in either direction will occur." Commenters stated that, whil e current natural gas supply is ample and prices are relatively low, they are concerned this may not remain the case prospectively and, therefore request the Agency to ensure that its ana lysis of long-term natural gas prices and the corresponding impact on future electricity prices t akes into account historic natural gas volatility and the potential for future volatility. Commenters stated the price of natural gas has increased significantly since the Proposed Rule was announced in June 2014 from about $3.50 to $4.04
Mcf.

Commenters stated that the Proposed Rule does not f actor in new investments by the manufacturing sector of more than $90 billion that will use natural gas and will very likely put upward pressures on the price of natural gas as dem and increases. Commenters stated that the EPA needs to examine the combined impact of greater use of natural gas for electric generation and manufacturing on supply and prices.

Commenters observed there is a secondary issue that needs to be addressed in the RIA: the storage of natural gas and normal demand is met by gas that is purchased on long-term fixed price contracts; however, when situations arise suc h as the winter of 2013-2014, gas supply must be purchased on the spot market and prices that are orders of magnitude higher than fixed-price contract prices are paid. Commenters stated the imp act of this affects the users of natural gas as well as the price of electricity generated using na tural gas.

Commenters urged the EPA to more closely examine th e complex dynamics of the natural gas delivery system and the potential impacts of alteri ng these dynamics on both natural gas and421

electricity costs to the consumer. Commenters state d that, if NGCC units are required to operate at 70% capacity factor, the costs of natural gas to residential and industrial consumers could be impacted in a negative manner. Commenters stated it is also possible that the proposed rule could force natural gas units to secure firm contracts in markets where such action would be uneconomical. Commenters stated that, in Ohio, resi dential and industrial natural gas consumption represented 61% of all natural gas cons umed in the State of Ohio in 2012. Given these numbers, commenters stated, the EPA must cons ider the complex dynamics of the natural gas delivery market, the role of natural gas as an economic source of residential heating, if realistic re-dispatch goals are to be set. Commente rs stated that because residential and electric power natural gas consumption patterns are typicall y counter-cyclical, they have concerns that disruptions to this cycle as a result of the 70% re -dispatch of NGCC units could introduce unforeseen costs to all consumers of natural gas. C ommenters noted they have significant concerns with even a projected 10% increase in deli vered natural gas prices from this proposal
alone.

Commenters expressed concern regarding potential in creases in natural-gas prices caused by the CPP. Commenters stated the EPA failed to fully asse ss the direct and substantial indirect impacts the CPP will have on the economy as well as the day -to-day functioning of society. Commenters stated that natural gas-fired generation in Arkansa s is expected to increase by 157%, thereby placing significant upward pressure on natural gas commodity and transportation prices, and these price increases are directly attributable to the CPP Commenters stated there could also be a significant increase in the price of natural gas ca using harm to consumers and Arkansas businesses. Commenters noted the EPA's own analysis of the CPP reflects a 12% increase in natural gas costs resulting from plan implementatio n. Commenters stated that, while the EPA has asserted that each individual building-block target that is assigned to each state is based on "reasonably achievable rather than maximum performa nce levels," the technology assumptions have yet to be demonstrated as achievable at a reas onable cost or, in some cases, achievable at
any cost.

Commenters stated the market has recently seen a sh arp increase in the volatility of market prices in regions where shale gas development has o utstripped the infrastructure capability to deliver to markets where the gas is needed. Comment ers stated that price spikes in the northeast last winter, for example, exceeded $123.50/MMBtu. C ommenters stated that, as demand increases rapidly, this issue could become a much w ider problem than in just the northeast; volatility could be very significant with growth in power sector natural gas demand projected
under the Clean Power Plan.

Commenters expressed concern that the EPA did not c onsider the significant negative impact of price volatility on energy-intensive, trade-exposed (EITE) manufacturers. Commenters stated that natural gas prices are known for being relativ ely volatile and that sudden increases in demand such as that the proposed rule will generate , coupled with existing strains on infrastructure in parts of the country, will cause price spikes that disproportionately impact
domestic EITE manufacturers. Commenters stated that the EPA's acknowledgement of an increase in natural gas demand prior to 2020, combi ned with a higher-than-expected industrial demand for natural gas, must push natural gas price s higher than EPA estimates.422

Comment 11: Commenters expressed concern that future regulatio ns would impact the price of

NG and should be included in the EPA's evaluation.

Response 11: The EPA disagrees to the extent that we believe our analysis appropriately considers natural gas supplies, infrastructure and competing demands. The IPM model includes a natural gas supply module that includes demand and supply of natural gas nationwide. In response to additional analysis and many comments, we have modified the proposal and RIA. States may consider local circumstances as they dev elop their plans, including system reliability, fuel diversity, the “useful life” of generation ass ets, other regulatory requirements, competing demands for natural gas, and infrastructure. See se ctions V.A, V.D, VIII.A, VIII.C.1 and VIII.G.2 of the final rule preamble of the CPP, Cha pter 3 of the GHG Mitigation Measures TSD for the CPP Final Rule supporting the final CPP, an d the Regulatory Impact Assessment of the final CPP and the Regulatory Impact Assessment of t he final CPP. The EPA considers the EIA Annual Energy Outlook 2015 cases for high and low o il and gas supply. Any comments regarding regulation of the natural gas extraction or supply industry are outside of the scope of
the CPP final rule.

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

Commenters stated that EPA needs to look at the iss ue of future local, state, and federal regulations on the upstream production of natural g as and factor them into the final rule's presumptions about the future of natural gas and th e effects on electricity rates since such regulations increase the costs of doing business an d would be passed on to natural gas users through higher prices. Commenters stated that poten tial regulations include those to capture methane from upstream oil and gas production; contr ols for capturing other volatile organic compounds (VOC) from upstream natural gas productio n; NOx regulations for new nonattainment areas where natural gas production di d not exist before; future treatment requirements for fracking or production water; and U.S. Department of Transportation regulations to improve safety for pipelines, specia lty tank cars and other rail equipment used to transport natural gas.

Commenters expressed concern that increased regulat ion of the natural gas sector, including the primary tool for extraction, hydraulic fracturing o r fracking, is already occurring, and there is no doubt that it will have some impact on the cost and availability of natural gas in the future. Commenters noted that the EPA recently issued the f irst federal emissions regulations for hydraulically fractured natural gas wells, as well as draft Underground Injection Control ("UIC") Class II permitting guidance for oil and gas hydrau lic fracturing activities using diesel fuels and
stated there is no indication that EPA has consider ed the impact of its own actions on forecasted natural gas prices in the proposed rule. Commenters stated that State- and local-level regulation has included fracking bans and moratoria including, for example, a ban on fracking in Vermont and statewide moratoria in New York, Maryland, and North Carolina. Commenters stated that, as a result, it is reckless and short-sighted to rely so heavily on current and projected natural gas availability and prices in proposing this rule.

Commenters stated that simple economics indicates t hat, as natural gas demand increases, so will its price, especially in light of additional EPA ru les expected in the near future addressing methane from oil and gas operations.423

Commenters stated that a related concern regarding natural gas prices is the EPA's plans for possible expanded controls over fracking and natura l gas recovery. Commenters requested the EPA to clarify its regulatory plans for fracking op erations prior to finalizing the CPP.

Comment 12: Commenters stated the EPA should update the gas pri ce and gas price response assumptions that it uses in its IPM compliance mode ling.

Response 12: The EPA disagrees to the extent that we believe our analysis appropriately considers natural gas supplies, infrastructure and competing demands. The IPM model includes a natural gas supply module that includes demand and supply of natural gas nationwide. In response to additional analysis and many comments, we have modified the proposal and RIA. We disagree that natural gas supply or prices will prevent the achievement of the goals of the rule. States may consider local circumstances as th ey develop their plans, including system reliability, fuel diversity, the “useful life” of g eneration assets, other regulatory requirements, competing demands for natural gas, and infrastructu re. See sections V.A, V.D, VIII.A, VIII.C.1 and VIII.G.2 of the final rule preamble of the CPP, Chapter 3 of the GHG Mitigation Measures TSD for the CPP Final Rule supporting the final CPP , and the Regulatory Impact Assessment of

the final CPP. al CPP.

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

Commenters stated that the gas price response (i.e. , gas price elasticity assumptions) built into EPA's IPM model appears to be materially higher tha n those reflected in the February 2014 NorthBridge analysis of the CATF Power Switch appro ach and the October 2014 Rhodium Group analysis of the CPP using the NEMS modeling p latform. Commenters stated that comparing the results demonstrates that the gas pri ce response in EPA's IPM modeling is more sensitive to gas demand than either NEMS or the Nor thBridge modeling platform by at least
factor of 2 to 6. Commenters stated that this indic ates that the gas price elasticities in EPA's IPM modeling may reflect an overly sensitive gas price response that does not fully account for the potentially large quantity of shale gas reserves an d, as a result, EPA's modeling could overstate the natural gas price impact of the CPP policy and needlessly constrain the potentially costeffective role of additional use of natural gas in re-dispatch of existing and new NGCC units as well as through gas co-firing in coal units.

Commenters stated that since the base case prices a ppear high, the increase in gas prices forecasted in the policy cases may well also be ove rstated. Commenters stated that if there is more natural gas available at relatively low prices , then increased demand for natural gas may cause prices to rise by a smaller amount than forec asted in the IPM policy cases. Commenters stated that this overstatement of gas prices raises the estimated cost of the CPP rule and can cause the role of gas in the compliance mix to be u nderstated. Commenters stated that the assumed price forecast for natural gas in EPA's Int egrated Planning Model modeling may not be sustainable in the future due to increased demand p laced on this fuel for both heating and electric generation, as well as offshore sales of liquefied natural gas.424

Commenters stated that the severity of Florida's pr ojected natural gas reliance is unknown beyond 2025 because EPA has not published the parse d files for any other years; however, without these additional parsed files, EPA has not shown how this imbalance might worsen in 2030 and beyond. Commenters stated that natural gas is a globally traded commodity and the price will eventually more closely reflect the glob al prices; thus, cheap domestic natural gas prices are likely a short-term phenomenon and will move closer to either the historic domestic price volatility or possibly even soar to a level m uch higher based on global demand. Commenters asked if the EPA and Department of Energ y (DOE) along with the Federal Energy Regulatory Commission (FERC) adequately modeled nat ural gas price scenarios given this likely market change.

Comment 13: Commenters stated that multi-year forecasts of the price of natural gas have consistently been inaccurate and that establishing a mitigation goal based on an assumption of persistent low gas prices is not a reliable or depe ndable approach to estimating capacity factors for NGCC plants over a long period.

Response 13: See the response to Comment 12 in 3.2.6.

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

Commenters stated that establishing a mitigation go al based on an assumption of persistent low natural gas prices is not a reliable or dependable approach to estimating capacity factors for NGCC plants over a long period. Commenters disagree d with EPA that "changes in generation patterns have been driven largely by changes over t ime in the relative prices of natural gas and coal". Commenters provided data from the EIA and su ggested that history indicates the NGCC capacity factor is a sensitive function of natural gas prices. As a result, commenters stated that the EPA's assumption of high future NGCC capacity f actors could be invalid if significant natural gas price volatility and increases were to be experienced in the future.

Commenters stated that numerous industry studies de monstrate the historical volatility and unpredictability of natural gas prices. Commenters stated that this information illustrates the danger of EPA's reliance on forecasted natural gas prices for its policy choice. Commenters cited in particular, a June 2012 study completed by NERA which addresses the difficulty in accurately forecasting natural gas prices. Commenters stated t he NERA study (1) details the random factors that affect natural gas supply and demand; (2) show s the historic volatility and unexpected changes in natural gas markets; and (3) identifies forecasting models that have proven to be poor indicators of the actual natural gas price with lar ge errors and biases in the most widely used forecasts, including forecasts from the Energy Info rmation Administration (EIA). Commenters stated that, while domestic natural gas prices have been historically low, the swing away from natural gas could be abrupt, especially because the U.S. natural gas market does not reflect current global price trends (citing EIA, 2011). Com menters stated there are uncertainties surrounding: (1) the amount of recoverable reserves in unconventional reservoirs; (2) the regulation of natural gas extraction processes and materials; (3) the pace and degree of natural gas exports; and (4) increased demand for natural g as from other sectors of the economy. Commenters provided data indicating that natural ga s prices have been historically volatile and425

unpredictable. Commenters objected to the proposed rule because it relies on potentially erroneous projections that may not only shift, but may drastically shift, thus exposing the reliability of the nation's energy grid to a highly volatile commodity.

Commenters stated the EPA should not assume that pr esent low prices will sustain their emissions reduction objectives. Commenters stated t hat natural gas facilities typically respond actively to changes in the price of natural gas and the availability of supply given pipeline infrastructure and competing demand. Commenters sta ted the EPA's analysis suggests that low natural gas prices will enable sustained operations at a high capacity factor, but this is a very dubious assumption. Commenters explained that natur al gas has a highly volatile price curve, and multi-year projections are regularly inaccurate . Commenters stated that, even short-term events can cause wild oscillations in the price of natural gas; last winter's polar vortex so stressed natural gas infrastructure in the northeast that ma ny natural gas facilities had to curtail operations or sell power at absurdly high prices.

Commenters expressed concern (in agreement with EPR I's comments), that establishing a mitigation goal based on an assumption of persisten t low gas prices is not a reliable or dependable approach to estimating capacity factors for NGCC plants over a long period. Commenters stated that, historically, natural gas p rices have been volatile and that increasing utility reliance on natural gas generation would re sult in additional economical risk. The commenters stated that, for example, during extreme temperatures across most of the Southern and Eastern United States from January 6 to 8, 2014 , natural gas generating plants did not perform as expected due to both plant outages and n atural gas delivery system inadequacies.

Commenters stated that the assumption that natural gas prices will remain relatively flat through
2030 fails to take into account the historic volati lity of natural gas, the impact on price from future regulations on upstream production, or how i ncreased demand will put upward pressure on prices.

Commenters stated that, in establishing its NGCC ca pacity target, EPA should be sensitive to the long-term impact on natural gas prices. Commenters stated that, while the EPA contends natural gas prices will remain low going forward, the EPA's projection suffers from the same uncertainties that have characterized natural gas p ricing for decades; i.e., no one confidently or accurately predicted the current levels in natural gas prices five, ten or twenty years ago, and
there is no reason to believe that EPA's current lo ng term price forecast will be different. Commenters provided a graph which illustrated the p rice volatility for natural gas rom 1991- 2013 as ranging from $1-14 per dekatherm. Commenter s stated that mandating reliance on NGCC units will increase the price of natural gas a s both gas supplies and delivery capacity become constrained across the country. Commenters s tated that enhanced reliance on NGCC units as baseload capacity will put upward pressure on both wholesale and retail natural gas prices, which will ultimately be borne by electric and natural gas ratepayers.

Comment 14: Commenters supported the EPA's determination not to base its goal-setting

calculations for reduced utilization of coal-fired EGUs based on retirements directly, but instead on the availability of underutilized NGCC capacity.426

Response 14: The EPA agrees to the extent that we we believe ou r analysis is appropriate. See sections V.A, V.D, VIII.A, VIII.C.1 and VIII.G.2 of the final rule preamble of the CPP and Chapter 3 of the GHG Mitigation Measures TSD for th e CPP Final Rule supporting the final CPP, and the Regulatory Impact Assessment of the fi nal CPP.

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

Commenters referred to the Brattle Group study, whi ch points out, the rate of "voluntary" coal plant retirements is highly dependent on future nat ural gas prices which are impossible to predict, and stated that plant operators and state regulators are unlikely to assign a probability of closing a plant by a certain date until a final det ermination is made.

Commenters supported the EPA's determination not to base its goal-setting calculations for
reduced utilization of coal-fired EGUs based on ret irements directly, but instead on the availability of underutilized NGCC capacity.

Comment 15: Commenters expressed concern that NG price increase s will be further amplified by LNG exports.

Response 15: The EPA disagrees to the extent that we believe our analysis appropriately considers natural gas supplies, infrastructure and competing demands, including net exports. The IPM model includes a natural gas supply module that includes demand and supply of natural gas nationwide. In response to additional analysis and many comments, we have modified the proposal and RIA. States may consider local circums tances as they develop their plans, including system reliability, fuel diversity, the “useful lif e” of generation assets, other regulatory requirements, competing demands for natural gas, an d infrastructure. See sections V.A, V.D, VIII.A, VIII.C.1 and VIII.G.2 of the final rule pre amble of the CPP and Chapter 3 of the GHG Mitigation Measures TSD for the CPP Final Rule supp orting the final CPP, and the Regulatory Impact Assessment of the final CPP.

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

Commenters stated they found it difficult to identi fy EPA's modeling assumptions on the magnitude of exports of liquefied natural gas (LNG) from 2020 to 2029 and noted that the combination of increased LNG exports and increased consumption by the power industry could boost natural gas price by more than EPA is anticip ating. Commenters stated that the growth in international trade in natural gas facilitated by c onstruction of LNG terminals in the U.S. and other major exporting countries could expose the po wer industry to significant price shocks or supply disruptions. Commenters stated the EPA has f ailed to consider the impacts of LNG exports and increased non-electric utility demand o n natural gas supply.

Commenters stated the manufacturing sector serves a s an example of the unintended loss that
would occur as the economic benefits of increased m anufacturing in the U.S. economy would decrease due to LNG exports. Commenters stated thei r analysis disproves the notion that the shale-driven natural gas supply curve is flat and i nstead shows that it is upward sloping. Commenters stated the result is that natural gas pr ices will rise under an extremely conservative427

demand outlook, such as the one projected in the AE O 2013 ER and, under a more reasonable demand forecast, gas prices will almost double from $3.3/MMBtu today to $6.3/MMBtu by 2030. Commenters stated that layering in additional demand from LNG exports in the Likely and High Export scenarios would raise prices to $8.8/MM Btu and $10.3/MMBtu in 2030, respectively, assuming no price-induced demand feed back. Commenters stated that, at these higher scenario prices, growth in the three main se ctors driving the natural gas economy going
would be stunted:

Manufacturing: A significant, gas-intensive sub-se ctor exists that will be challenged in passing through high natural gas costs in the competitive, global market. This is illustrated in our ammonia case study. Manufacturers will look to esta blish new plants and relocate existing operations in more favorable gas markets around the world. The historical precedence of companies exiting US manufacturing is well document ed and can happen again if LNG exports rise too high. Electric Generation: For the electri c sector, generation providers will migrate to other generation technologies, such as wind and nuc lear, but only at higher relative costs. This will raise prices for the full spectrum of electric ity consumers. Our results show that electricity prices in 2030 will increase 60-170% in the Likely Export scenario and will increase 70-180% in the High Export scenario. The wide variation is due to differences in regional electricity markets. Natural Gas Vehicles: As shown in earlier in Figur e 21, NGV HDVs are economical at delivered natural gas prices below $14/MMBtu at cur rent diesel prices of $4.2 per gallon (See http://www.eia.gov/petroleum/gasdiesel/). While thi s is well above our Henry Hub natural gas price forecast in 2030, the costs of pipeline trans portation and compression and liquefaction services will raise the delivered price. CRA estima tes that these costs could be $3-4/MMBtu, which would put NGV economics at the margin under t he High Export scenario.

Commenters stated the LNG exporters are the most im mune to higher natural gas prices, as Asian LNG import prices are tied tightly to an oil index, which currently trades around $20/MMBtu. Subtracting the costs of liquefaction, s hipping, and regasification (netback costs) of $6/MMBtu, commenters stated that exports to Asia ar e attractive with domestic natural gas prices up to $14/MMBtu. Commenters stated this netb ack price is well above our 2030 Henry Hub forecast price across all scenarios and, as a r esult, would induce LNG exports.

Comment 16: Commenters expressed concern that the switch of gen erating capacity from coal to natural gas driven by this rule would impair US manufacturing.

Response 16: The EPA disagrees to the extent that we believe our analysis appropriately considers natural gas supplies, infrastructure and competing demands. The IPM model includes a natural gas supply module that includes demand and supply of natural gas nationwide. In response to additional analysis and many comments, we have modified the proposal and RIA. States may consider local circumstances as they dev elop their plans, including system reliability, fuel diversity, the “useful life” of generation ass ets, other regulatory requirements, competing demands for natural gas, and infrastructure. See se ctions V.A, V.D, VIII.A, VIII.C.1 and VIII.G.2 of the final rule preamble of the CPP and Chapter 3 of the GHG Mitigation Measures TSD for the CPP Final Rule supporting the final CPP , and the Regulatory Impact Assessment of
the final CPP.428

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

Commenters stated that introducing additional regul atory price signals to the market will likely increase both pricing and price volatility and reco mmended that EPA include a full range of natural gas pricing and price volatility in the eco nomic impact assessment of this rule. Commenters stated that the impact of higher natural gas pricing goes well beyond the cost of electricity as many manufacturing industries use ga s as a fuel or raw material and recommended that EPA include these secondary cost impacts to ma nufacturing, as well as the heating cost impact for commercial and residential natural gas u sers, in the economic impact assessment for the proposed rule. Commenters stated that most ener gy intensive manufacturing is located in states with low energy cost structures which will b e most at risk for rate increases and recommended that EPA allow states the flexibility t o mitigate the impact on energy intense industries, including flexible incentives for energ y efficiency or cost offsets for increased energy prices.

Commenters stated that the significant switch of ge nerating capacity from coal to natural gas driven by this rule, coupled with the accelerating manufacturing use of natural gas and the expected future significant export of natural gas f or geopolitical considerations, has the potential to fundamentally alter the natural gas supply suppl y/demand equation, increase natural gas pricing volatility, and impair the US manufacturing renaissance from its full potential as a jobcreating engine of economic growth. Commenters stat ed that current natural gas export growth in Australia provides a cautionary scenario in this re gard. Commenters stated that, in Australia, significant growth in natural gas production has be en accompanied by a tripling of wholesale natural gas prices in the domestic market due to th e explosive growth in Australia's natural gas export market. Commenters stated this is occurring even with the recent repeal of Australia's carbon tax and without the concurrent pressures of an electricity generating base that is rapidly shifting to natural gas fuels, as is contemplated b y the proposed 111(d) rule. Commenters stated these pressures in the US would have a significant detrimental affect not only on the broad US manufacturing base but specifically on the producti on of secondary (recycled) aluminum given the role natural gas as a key input into the second ary aluminum recycling process.

Commenters stated the proposed Clean Power Plan foc uses on electricity, but the increased use of natural gas by power industry to comply also wil l put upward pressure on natural gas costs, an important energy source for South Carolina manufact urers

Commenters stated the EPA failed to assess the econ omic effects on other economic sectors from higher natural gas prices or potential gaps in the incremental natural gas supply. Commenters noted that many sectors of the economy rely on natu ral gas and have increased natural gas consumption since pre-recession levels, including t he power, industrial, and transportation sectors. Commenters stated that natural gas exports will begin to coincide with the accelerated retirement of coal generators. Commenters noted tha t (1) four liquefied natural gas export projects approved so far by DOE have the capacity t o export 7.1 bcfd of natural gas by 2018, amounting to more than 10 percent of the current da ily supply of 70 bcfd; (2) the Sabine Pass liquefaction terminal will begin operations at the end of 2015 and has locked customers into 20- year contracts; and (3) U.S. exports of natural gas to Mexico are expected to rise by 3.5 bcfd by the end of this year according to DOE-nearly double the current rate. Commenters stated the EPA's analysis does not even touch upon, let alone analyze, any of these market developments429

and how the proposed rule will affect the economic sectors and residential customers that depend upon natural gas.

Commenters stated that recent history provides more than ample experience on the scope and depth of the consequences of over-relying on natura l gas. Commenters stated that, between 1997 and 2009, the natural gas market experienced five s ignificant price spikes which contributed to the loss of nearly 4 million jobs in manufacturing and turned a $19 billion U.S. chemical trade surplus into a deficit from 2001-2007. Commenters s tated this occurred even when natural gas demand fell-but prices increased by 160 percent. Co mmenters stated all of this coincided with an increase in natural gas power plant builds and a 27 percent increase in natural gas consumption in the power sector-more than three times the overa ll growth in natural gas demand by all
sectors. Commenters concluded that there is little question of the direct correlation between manufacturing job losses and higher and more volati le natural gas prices during this period. Commenters presented a figure, which illustrates a decline in employment in the manufacturing sector from 1195 to 2005 (a reduction of over 3,000 jobs) (Figure: U.S. Manufacturing Employment 1195-2005; Data Source: U.S. Bureau of L abor Statistics).

Commenters stated Nick Akins, CEO of American Elect ric Power accurately summed it up in testimony to the Senate Energy Committee: "It has b ecome clear that we are having to make a choice in the winter between committing natural gas resources to generating electricity or to heating homes. Right now, we cannot do both. Given the number of additional base load generating units that will be retired in the next 1 4 months, we face a real possibility that we will
have to make that choice more often in the future."

Comment 17: Commenters expressed concern that a new heavy empha sis on natural gas could

increase the cost of fertilizer for farmers and ran chers and that development of new transmission lines, natural gas pipelines and electrical generat ion facilities could restrict use of their land for agricultural purposes.

Response 17: The EPA disagrees to the extent that we we believe our analysis appropriately considers natural gas supplies, infrastructure and competing demands. The IPM model includes a natural gas supply module that includes demand and supply of natural gas nationwide. In response to additional analysis and many comments, we have modified the proposal and RIA. States may consider local circumstances as they dev elop their plans, including system reliability, fuel diversity, the “useful life” of generation ass ets, other regulatory requirements, competing demands for natural gas, and infrastructure. Regard ing the price of natural gas on the impact of fertilizer, EPA believes that demand impact of the 111(d) final rule will be relatively small, as we believe the price impact on natural gas of the r ule will be small. See sections V.A, V.D, VIII.A, VIII.C.1 and VIII.G.2 of the final rule pre amble of the CPP and Chapter 3 of the GHG Mitigation Measures TSD for the CPP Final Rule supp orting the final CPP, and the Regulatory Impact Assessment of the final CPP.Regarding the pr ice of natural gas on the impact of fertilizer, EPA believes that demand impact of the 111(d) final rule will be relatively small, considering the flexibility afforded to states - including trading and additional time before the start of the interim performance period – to develop plans that consider reliability and local circumstances such as430

gas infrastructure and competing demands for natura l gas. The 111(d) final rule does not require states to construct transmission or natural gas inf rastructure on private land. We are providing states with substantial flexibility as to how they structure those plans to achieve the 111(d) requirements. See sections V.A, V.D, VIII.C and VII I.G of the final rule preamble CPP and the Regulatory Impact Analysis of the CPP final rule.

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

Commenters stated farmers and ranchers could be aff ected in another, more direct way by any wide volatility in natural gas prices. Commenters s tated that, while recent trends have lessened the linkage of domestic natural gas and fertilizer prices, natural gas is the principal feedstock in the production of nitrogen fertilizer, which is a v ital input for farmers and ranchers to grow crops. Commenters stated that, while natural gas pr ices are currently low, thanks to technological developments (such as hydraulic fracturing) that ap pear to have opened up large supplies, the future availability of adequate natural gas supplie s comes into question as activists continue to increase pressure on regulatory agencies to oppose fracking. Commenters stated that, if new supply sources be restricted while utility demand i s increased, we could see increases in the price of natural gas that could raise input costs for far mers.

Commenters stated the CPP will undoubtedly increase the average cost of electric generation as well as increase the price for nitrogen fertilizer due to the increased demand for natural gas. Commenters stated that natural gas is the largest c ost in manufacturing commercial fertilizer used to grow crops and that increases in natural ga s prices will have a corresponding impact on the price of commercial fertilizer.

Commenters stated the rule will create the need for new transmission lines, natural gas pipelines and electrical generation facilities which will be constructed on farm and ranch land. Commenters stated that, as such, farmers and ranche rs will either lose property and/or the ability to fully utilize portions of their property.

Comment 18: Commenters expressed concern that the EPA has not a ccounted for impacts at efficient, low-emitting generators of combined heat and power.

Response 18: The EPA disagrees with the commenters’ assertion t hat the rule will cause these

CHP units to shut down. The rule does not affect su ch units and will not have the price impacts alleged. See the Regulatory Impact Analysis of the final CPP.

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

Commenters stated Verso's gas turbines at two faci lities in Maine generate power for the electrical grid when it is most needed. Commenters stated that, with limited natural gas supplies in the region, their costs can skyrocket in winter, surpassing revenues. Commenters stated that natural gas costs in Maine, particularly peak price s, can be expected to escalate further as a result of the Carbon Pollution 111(d) Rule. Commenters sta ted the gas turbines could become too costly to run or maintain, forcing Verso to buy mor e electrical power and making the company431

less competitive. Commenters stated this would rob the northeastern grid of reliable, efficient, low-emitting generators of combined heat and power, just the sort of CHP units EPA is touting as solutions to carbon pollution.

Comment 19: Commenters expressed concern that requiring increas es in NGCC generation will increase demand for gas and may increase the freque ncy of spikes in gas prices in areas with constrained supplies.

Response 19: The EPA disagrees to the extent that we believe ou r analysis appropriately considers natural gas supplies, infrastructure and competing demands. The IPM model includes a natural gas supply module that includes demand and supply of natural gas nationwide. In response to additional analysis and many comments, we have modified the proposal and RIA. States may consider local circumstances as they dev elop their plans, including system reliability, fuel diversity, the “useful life” of generation ass ets, other regulatory requirements, competing demands for natural gas, and infrastructure. See se ctions V.A, V.D, VIII.A, VIII.C.1 and VIII.G.2 of the final rule preamble of the CPP and Chapter 3 of the GHG Mitigation Measures TSD for the CPP Final Rule supporting the final CPP , and the Regulatory Impact Assessment of

the final CPP.

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

Commenters stated that TVA is exposed to higher gas prices when demand exceeds expectations, which raises electricity prices, such as was the ca se during the Polar Vortex experienced in the winter of 2013-14 when spot prices spiked to histor ic levels. Commenters recommended the EPA include consideration of secondary uses and loc alized price impacts in its analysis of natural gas fuel supply. Commenters noted an EIA re port that indicates natural gas fuel prices have a history of volatile pricing for local distri bution company customers in Tennessee and
stated that this is an area where EPA should devote additional consideration in its analysis.

Comment 20: Commenters recommended the EPA provide a "safety va lve", granting relief from the State's CO2 targets if natural gas prices incre ase by more than 10% above the price projections used by the EPA to prepare the Rule.

Response 20: The EPA thanks the commenters. The EPA disagrees wi th the commenters, particularly with the claim that the rule is the pr imary cause of gas price changes, when there are many factors that are entirely outside the rule. We believe the impacts from the rule on natural gas prices will be modest. See the Regulatory Impac t Analysis of the final CPP.

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

Commenters stated the natural consequence of the Pr oposed Rule is that much of the infrastructure for coal-fired generation will cease to exist as the country switches to natural gas for its base load energy needs. Commenters stated t hat, if the supply of natural gas is interrupted432

or the cost of gas rises beyond predications, the c onsequences may be profound. Commenters concluded that some form of safety value is necessa ry to allow for the continuation of coal-fired capacity to be used in such instances.

Comment 21: Commenters stated the EPA should account accuratel y for the efficacy and cost of switching from coal to natural gas, which will like ly lead to curbing the Plan's reliance on natural gas dramatically.

Response 21: The EPA disagrees to the extent that we believe the rule will not result in large increases in consumption of natural gas. In respons e to additional analysis and many comments, we have modified the proposal and RIA. See section V.A of the final rule preamble of the CPP, Chapter 3 of the GHG Mitigation Measures TSD for th e CPP Final Rule supporting the final CPP, and the Regulatory Impact Assessment of the fi nal CPP. In response to additional analysis and many comments, we have modified the proposal an d RIA.

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

Commenters stated the climate benefit of switching to natural gas is doubtful, and the cost is extraordinary because we must soon phase out natura l gas, a factor that EPA fails to consider. Commenters stated the EPA should sharply reduce the Clean Power Plan's reliance on natural gas. Commenters stated there is little if any room for natural gas in a proposal that replaces fossil-fuel generation incrementally by using the e mission-reduction strategies that come at
lowest cost to consumers.

Comment 22: Commenters provided the following comments and aske d the EPA to clarify several points which relate to specific sections an d pages of the Technical Support Document (TSD)--GHG Abatement Measures, Chapter 3.

Response 22: The EPA thanks the commenters for these comments. The TSD has been revised for the final rule. See the GHG Mitigation Measure s TSD in the docket for this rule.

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

• On page 3-5 under the heading Historical Context th e CO2 emission rate of U.S. coal power plants is stated to be 2,200 lb/MWhr and that of NGCCs is 907 lb/MWhr. Footnote 42 says this information comes fr om the 2012 eGrid data file provided in the docket.

• On page 3-10, footnote 53 says the $15/ton CO2 pric e signal is based on CO2 emission rates of 2,354 lb/MWhr for coal and 926 lb /MWhr for NGCC and also
cites the 2012 eGrid data file. EPRI recommends EPA clarify or correct this discrepancy in the two sets of numbers cited as com ing from the same data file.433 • The final sentence on page 3-10 cites an expected i ncrease in natural gas production of 20% between 2012 and 2020 as a reason the United States can accommodate an increase in the average NGCC capacit y factor to 70%. EPRI suggests that it is important to evaluate what is e xpected to be consumed by the LNG export facilities which have recently been appr oved. For example, EPRI estimates 3.6 trillion cubic feet (TCF) per year ha ve already been approved and another 3.6 TCF is under review by DOE.22 EPRI reco mmends EPA clarify its assumptions for the potential magnitude of LNG expo rts to the potential price of natural gas.

• On page 3-11: Adding in the existing sources that w ere not yet online in 2012 (under construction) increases total NGCC generatio n calculated in the goal setting to 1,444TWh. This would represent a 50% inc rease over what was produced in 2012, which was a record year; however, in the Building Blocks memo TSD, EPA predicts NGCC power production in 203 0 will be 1,743TWh, which is 178% of the 2012 value. That implies a sig nificant increase in natural gas consumption versus today. For 2020 EPA predicts NGCC power production will be 1,369TWh, which shows a mismatch between wh at is in this reference
document and what is in the cost-benefit calculatio n memo. Page 3-12: For comparison, NGCC generation growth of 450TWh (calcu lated in goal setting) would result in increased gas consumption of roughl y 3.5 TCF for the electricity
sector. There is a miscalculation here based on wha t is stated in Footnote 69 where the heat rate of an NGCC is assumed to be 10, 000 Btu/kWhr. This is too high. To get 3.5 TCF from 450TWh of electricity one has to assume a heat rate of 7,964 Btu/kWhr. However, EIA estimates the electric power sector consumed 9.1 TCF of natural gas in 2012.23 Consuming an addition al 3.5 TCF of natural gas would mean an increase of 38.5%, but that does not seem to match with the statement on page 3-11 that NGCC generation would i ncrease by 50%. Although the amount of power produced by simple cycles might be large enough to account for this discrepancy, the modeling results in the c ost-benefits memo show only a very small amount of power being generated by simpl e cycles.

• The discussion on page 3-14 regarding the availabil ity of NGCCs is confusing and seems to suggest that the availability of advan ced NGCCs is higher than that of lower firing temperature NGCCs.

• Page 3-20: In the discussion of the assumptions tha t went into EPA's IPM predictions they say they assigned a CO2 charge to units that produced CO2 at a rate greater than 1,100 lb/MWhr. Additional rationa le for this charge and at this particular level would be useful.

• Table 3-6: The base case has an NGCC capacity facto r of 52% which is significantly higher than the value in 2012. It is uncertain whether this is due to the assumed impact of planned coal unit retirements and NGCCs taking up the
slack or another reason.434 • Page 3-26: At the top of the page it is stated: Thi s is because only 29 state goals are premised on the existing NGCC fleet achieving a n average capacity factor of 70 percent. Consequently, a 70 % utilization rate t arget for the existing NGCC fleet requires an average national capacity factor of 63 percent. This second sentence is confusing and should be clarified.

Comment 23: Commenters asked for clarification regarding the E PA's underlying assumptions and approach to performing cost analyses.

Response 23: The EPA thanks the commenters for these comments. The TSD has been revised for the final rule. See the GHG Mitigation Measure s TSD in the docket for this rule.

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

Commenters asked for clarification of the following issues:

• While Table 3-5 of the GHG TSD details "net capacit y", why do the utilization rates not equate with unreserved capacity on a long -term basis?

• What line packing considerations did the EPA take i nto account?

• Why did the EPA not analyze the integration of stor age capacity? How might this further impact cost and reliability factors?

• Why did the EPA not analyze how Dodd-frank has and will impact capacity elasticity?

• Why did the EPA not analyze with system peak-day us age rates.

• Why didn't the EPA consider how extreme events and seasonal changes in demand for natural gas influence gas prices and ava ilability?

• Why did the EPA not consider the impact of expanded natural gas exports on natural gas prices?

• The EPA projects a 10% increase in natural gas pric es, then says EIA averages year-to-year changes at Henry Hub from 1981-2012 as 18.5%. See GHG TSD 3- 26. The EPA projection less than historic changes. Why isn't the 10% in addition
to the 18.5%?

• The EPA provides estimated increases in natural gas prices in national average delivered; why didn't the EPA provide state & regio nal estimates?435

3.2.7 Co-firing

In a notice of data availability (NODA) issued Octo ber 28, 2014, the EPA requested comment on the concept that building block 2 could be expanded to include natural gas co-firing at existing coal-fired boilers as a means of reducing CO2 from the power sector.

This section addresses comments on the potential in clusion of co-firing natural gas and natural gas conversions at existing coal-fired EGUs as part of building block 2.

Comment 1: Commenters expressed both support for and arguments against the concept that building block 2 could be expanded to include natur al gas co-firing at existing coal-fired boilers.
Some of these comments also involved other means fo r increasing the use of natural gas to displace coal.

Response 1: Based on a review of the comments the agency decid ed not to develop the concept of including gas co-firing at coal-fired EGUs as pa rt of building block 2. Our rationale is
discussed in further detail in sections V.A and V.B of the preamble for this final rule.

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

Commenters stated the EPA should not expand the definition of the NGCC fleet to include cofiring or new NGCC units in states' baselines.

Commenters observed that gas co-firing, as a unit-s pecific control measure, more properly belongs within building block 1 as a strategy that can be accomplished by modifications at an existing fossil steam unit.

Commenters concluded that co-firing should remain a tool available to states to help them achieve emission reduction goals, but should not be part of BSER. Also, commenters said, simultaneous inclusion of co-firing with re-dispatc h could lead to double counting of potential
emission reductions.

Commenters stated that expanding the definition of the NGCC fleet to include co-firing or new NGCC units in a state's baseline will only make sta te baselines even tighter and the ultimate
standard even harder to achieve.

Commenters stated that coal-fired CHPs are unique a nd sale of power to the grid may be necessary to recover costs to operate and maintain the units. For this reason, the commenters
believe coal-fired CHP facilities must be excluded from the re-dispatch evaluation under BB2.

Commenters referred to the NODA and objected to any use of natural gas co-firing as a supplement to the re-dispatch assumption. Commenter s said that the feasibility and potential cost of co-firing natural gas with existing coal and oth er fossil fuel-fired power plants is highly dependent upon the particular characteristics of an individual power plant. Commenters added that the same variance in feasibility and cost is a lso true for the relative proximity and availability of natural gas to existing power plant s that do not currently utilize natural gas. As436

such, commenters said that the EPA would not be abl e to apply a simple methodology to every state for what percentage of existing coal, oil, an d other fossil-fuel generation could be met in the future with the co-firing of natural gas. Instead, commenters said, the EPA would need to analyze each fossil-fuel fired power plant individu ally to determine the feasibility and economic cost of implementing natural gas co-firing at each facility. Commenters stated that conducting a suitable analysis for a single power plant would ta ke weeks to months of in depth analysis from a broad array of market experts and engineers, and co nducting such an analysis for hundreds of power plants would take years and tremendous manpow er. Commenters concluded that the proposed alternative is impracticable within EPA's given timeline.

Commenters supported in part the approach that woul d treat the increased use of natural gas "comprehensively" rather than considering separatel y the potential to re-dispatch. Commenters said increasing natural gas utilization including c o-firing of natural gas with coal would reduce the emission rate of an affected EGU and be particu larly valuable in states without significant potential to shift utilization towards underutilize d NGCCs. To the extent that more implementation strategies can enhance states' flexi bility in reaching their targets, commenters favored inclusion of co-firing as a potential compl iance tool. Commenters pointed to the new data and analysis in the NODA that shows that co-fi ring meets the BSER cost criterion.

Commenters supported clarifying the compliance opti on of co-firing coal plants with natural gas as discussed in the NODA, Section III. B. 1. "Strin gency of Building Block 2." The commenters noted that this option is currently a consideration of many coal-fired units in Wyoming (a state
with little NGCC resources as described in the NODA ). According to the commenters, the EPA suggested restricting the co-firing option to state s with NGCC generation of 12% to 55% of existing steam generation, but commenters did not s upport such narrow criteria to be met in order to use the co-firing option. Commenters sugge sted that the EPA avoid specific mandates of technology to achieve the goals, but allow states " potential BSER options" in the final rule from which they can implement confidently in a state pla n, or from which a state may base an alternative approach to reducing CO 2 emissions.

Commenters supported allowing "Other Gas" units to count toward the target implied by BB2, welcoming the flexibility, but stressed that Other Gas units should not be added into the cohort of units expected to achieve a target capacity fact or. Particularly in New York, commenters said, Other Gas units are typically used for specific sys tem reliability purposes.

Commenters suggested a goal setting strategy that r epresents the BSER should include redispatch to new NGCC; consideration of the abilit y to co-fire or interchangeably burn natural gas at existing steam generating units; and redispa tch of remaining coal and oil generation to existing NGCC, up to a 75% capacity factor, based o n average annual capacity. The commenters suggested (1) optimizing the emissions r eduction potential of this building block while limiting the potential for unintended outcome s; (2) capitalizing on the increase in new NGCC capacity nationwide that will occur through ma rket forces irrespective of the proposed rule; (3) respecting the thermodynamic limitations of NGCC units and (4) highlighting the opportunity of make greater use of natural gas in e xisting steam generating units. The commenters stated these suggestions should be imple mented together to preserve the overall stringency of this building block. The commenters s tated the combination of the
recommendations results in a demonstrated level of achievable emission reductions,437

accountability, and flexibility consistent with sta tes' requests and Congress's intent in section 111(d) of the CAA.

Commenters said that the costs of conversion and co -firing are within an acceptable range, noting that the EPA may select any system that sati sfies the other requirements of BSER as long as the system's costs are not "exorbitant." Comment ers said that the number of existing and planned conversion projects already taken, absent a ny regulatory carbon pollution mandate, is strong evidence that the costs are reasonable. In a ddition, commenters said, the EPA's own data demonstrate that conversion to natural gas generate s substantial net benefits: the capital costs of conversion (including new pipeline) are $5 per MWh and the increased fuel cost is $30 per MWh, but the health benefits alone of conversion ar e between $60 and $140 per MWh.
Commenters said that the EPA observed that the cost per ton of CO 2 avoided is "relatively expensive," but it is not "exorbitant," especially when the full range of benefits associated with
conversion are taken into account. Commenters refer red to modeling by ICF using IPM and stated that, if the EPA adopts the changes NRDC rec ommends, natural gas use will fall over the 10-year period.

Commenters believed that the adoption of a minimum value for Block 2 that accounts for cofiring natural gas in steam EGUs would be a fair me ans to make Block 2 emission reductions stronger and fairer. If the EPA does not adopt this revision to Block 2, commenters agreed that the EPA could revise BSER to include a 20 percent ( %) co-firing rate, which could, in turn, be utilized to calculate more stringent Block 1 or Blo ck 2 values for states. Commenters stated that
Block 2 should be revised such that a 12% shift fro m coal-fired generation to natural gas-fired generation (i.e., re-dispatch, co-firing natural ga s in steam EGUs, and new NGCC) would serve
as the minimum floor for each state vis-a-vis Block 2. Barring the EPA's adoption of such an approach, commenters said that natural gas co-firin g should be part of BSER that undergirds each state's ultimate emission goals. Commenters sa id that the EPA could reasonably incorporate a 20% natural gas co-firing rate for facilities tha t are so equipped as an element of the BSER (e.g., part of the assumptions underlying Block 1 o r Block 2), which could achieve a 8-10%
reduction in CO2 emissions from coal-fired affected EGUs. Like the Building Block approach as a whole, commenters said that the establishment of a particular target level for any particular CO2 mitigation strategy does not require the achiev ement of that particular level by each state. Rather, commenters stated, all of the Building Bloc ks together synthesize the assumptions that lead to each state's goal. While not all steam EGUs will necessarily co-fire natural gas, commenters concluded that co-firing should be incor porated into and provide the basis for the state goals in the final Clean Power Plan.

Commenters stated that EPA proposes to make buildin g block two more stringent by assuming that EGUs can implement some amount of co-firing or rely on construction of new NGCC capacity to reduce emissions from coal-fired EGUs. Commenters stated that this approach is problematic for at least three reasons. Commenters stated that designating co-firing or new NGCC construction as BSER would effectively redefin e the source by re-designating coal-fired EGUs as natural-gas fired EGUs. Commenters stated t hat EPA cannot simply redefine an entire source category in an attempt to reduce emissions f rom that category. Commenters stated that second, EPA cannot designate new units as a compone nt of the best system of emission reduction for existing units and to do so would imp ermissibly blur the clear statutory distinction between new and existing units. Commenters stated t hat third, as EPA itself recognizes, the costs438

of building new NGCC or converting existing EGUs to allow them to co-fire is prohibitively expensive. Commenters stated that EPA estimates the cost of reducing emissions through cofiring to be as high as $150 per metric ton of CO2. Commenters stated that the cost of reducing emissions through redispatch to new NGCC units, mea nwhile, would be as high as $81 per metric ton, and therefore, it would be unreasonable to designate these exorbitantly costly alternatives as the "best system of emission reduct ion (considering the cost of such reduction) that has been adequately demonstrated for designate d facilities.

Commenter s stated that in its Notice of Data Availability, EPA requested comment on whether it should consider the potential to co-fire with natur al gas. Commenters stated that reliance on natural gas to reduce emissions should be looked at as a short-term solution, yet, to achieve the maximum amount of emissions from the proposed rule, EPA should set targets that reflect the opportunities presented by all three coal-to-gas op tions (increased use of existing NGCC plants, re-dispatch from coal to new NGCC plants, and co-fi ring). Commenters stated that the power sector is already deploying these methods, making c lear that they are both adequately
demonstrated and reasonable in cost. Commenters sta ted that these methods will also achieve carbon pollution reductions along with reductions i n other harmful pollutants that threaten wildlife, such as sulfur dioxide, NOx, and mercury.

3.2.8 New NGCC

This section discusses issues related to shifting g eneration from existing units to newly constructed NGCC plants as part of Building Block 2

.

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

Comment 5: Commenters opposed the two new proposed approaches for calculating building block 2 of imposing a minimum level of natural gas dispatch and calculating Building Block 2 on a regional basis.

Response 5: The EPA has not adopted the minimum floor approach for the final rule and believes the approach to developing state goals is not arbitrary (See Preamble Section V).

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

Commenters said that it is inconsistent with the CA A for the EPA to set standards for existing 111(d) units based on operation of new 111(b) units and that any minimum requirements for natural gas capacity would be arbitrary and reduce state flexibility for fuel diversity and cost effectiveness. Commenters added that calculating Bu ilding Block 2 on a regional basis is an arbitrary way for the EPA to increase the stringenc y of some states' goals and downplay disparities in state targets. Commenters said that electric utility companies design, operate, and dispatch their systems across state and regional bo undaries, and these systems should be afforded439

the flexibility to comply as a system. Commenters c oncluded that the calculation of Building Block 2 should support this approach, not further c omplicate it.

Comment 2: Commenters allege that EPA fails to understand RTO- Operated Capacity Markets and Claim these markets Pose Significant Barriers t o New Generation Resource Development and Thus to Implementation of the Proposed Rule.

Response 2: The EPA believes it understands and has properly t reated the role of these capacity markets, and disagrees that they are a barrier to c ompliance with this rule. EPA cites these markets as examples of one component of how EGUs ca n comply with this rule in these areas. First, when this rule addresses existing EGUs; with respect to NGCC utilization, it encourages greater use of existing resources, not new NGCC cap acity that is a principle concern of several commenters. Also, EPA recognizes that participants in these markets have raised issues for these markets before the FERC, but notes that these marke ts have been a component of revenue for the development of new NGCC and other new capacity to r eplace retiring coal capacity in regions
like PJM. This rule concerns the CO 2 emissions from existing sources, and is not direct ly related to the development of new capacity, as new NGCC cap acity is not part of BSER for this rule. The EPA modeling for this rule also does not projec t significant new NGCC capacity will be required for compliance with this rule. See Chapte r 3 of the GHG Mitigation Measures TSD for the CPP Final Rule supporting the final CPP, and th e Regulatory Impact Assessment of the final
CPP.

Commenters stated, although the building blocks in the Proposed Rule incorporate an increase in dispatch from natural-gas fired units, but do not e xplicitly include the construction of new natural-gas units, under the portfolio approach, co mpliance with the proposed guidelines will likely require a partial turnover of the existing f leet and the construction of new natural-gas fired generation resources. Commenters said, such resourc es will be needed both to replace retiring coal plants and meet the flexible ramping needs req uired to support an increase in intermittent renewable resources. Commenters said, this section discusses how the RTO-operated mandatory capacity markets will greatly impede such new natur al gas generation and are also likely to pose barriers to new renewable resources, as described i n the next subsection.

Commenters stated, the difficulties imposed by the mandatory capacity markets for new resource development were identified in an APPA-commissioned paper released in May 2014 entitled, Markets Matter: Expect a Bumpy Ride on the Road to Reduced CO2 Emissions, by Cliff Hamal of Navigant Economics ("Navigant Paper"). Commenter s said, the Navigant paper prepared for APPA found that the mandatory capacity markets "are already floundering over existing challenges and will be severely stressed by the add ed complexity of maintaining reliability while shifting to a lower CO2 emission portfolio."

Commenters stated that the Proposed Rule relies in part on the RTO capacity markets to serve the policies that the Proposed Rule seeks to implem ent. Commenters said EPA misunderstands, however, how those markets function. Commenters sai d EPA asserts that in states where RTOs manage markets, the RTOs "administer auctions for f orward capacity" in which generators "all440

compete to provide potential resources for meeting the projected demand for electricity services." Commenters said only two of the five RTO s administer such auctions.

Commenters stated that RTO capacity markets are ext remely controversial and subject to many pending legal disputes. Commenters said many FERC s takeholders have argued for years that RTO capacity markets have failed to serve their int ended basic function, i.e., to procure capacity needed for reliability in an economically efficient way, and thus should be substantially modified, or eliminated - not expanded in scope or introduced to new regions. Commenters said a major open FERC docket is currently considering t he core design and purpose of RTO capacity
markets. Commenters said individual RTOs are likewi se continuously making alterations that seek to correct identified flaws in existing capaci ty markets. Commenters said that consequently, it is not reasoned decision-making for EPA simply t o assume that RTO capacity markets can take on the new function of advancing the Proposed Rule's objectives.

Commenters said that EPA needs to withdraw the Prop osed Rule, fully engage with FERC regarding these issues, and revise its Proposed Rul e to reflect the actual market conditions under which any Section 111(d) regulations would be imple mented. B. RTO-Operated Mandatory Capacity Markets Have Not Been Effective in Leading to the Construction of New, More
Efficient Resources at a Reasonable Cost to Consume rs.

Commenters stated, there are numerous flaws in the mandatory capacity markets that have made them ineffective and costly constructs that will li kely impede the development or retention of more efficient and lower CO2 emitting resources, as follows:

• Different resources have different costs, which are not reflected in the capacity market prices. A 50-year old coal plant is paid the same amount per MW and for the same duration as a brand new highly efficient c ombined-cycle natural gas plant.

• The vast majority of the revenue collected through capacity markets has been paid to older, existing units, although many older plant s have paid off much of their fixed costs and are therefore earning windfall prof its. For example, only 9 percent of the $72 billion in revenue committed through the PJM capacity markets is for new resources, demand response, or energy efficienc y.

• Financing of newer units at a reasonable capital co st requires a long-term steady stream of revenue, such as that provided by a long- term contract and not the capacity market.

• The capacity markets do not distinguish between tec hnology types or specific locations on the grid. As a result, critical needs are not addressed, including adequate flexible ramping capability to match the v ariability of renewable resources, reliability gaps created by retiring coa l plants, and the coordination of natural gas infrastructure and delivery with the si gnificant expansion of natural gas generation. The RTOs often create systems of si de payments to ensure reliability, such as direct payments through what a re known as reliability-mustrun agreements to coal plants to remain in place to ensure reliability.441 • Capacity markets use zonal price differentials on t he theory that higher prices will act as a "signal" for the development of new genera tion or transmission. But such higher prices are not effective signals because own ers of existing generation have no financial interest in building new resources and lowering prices for their existing units. In fact, they have an incentive to hinder new entrants, and have an established track record of using RTO regulatory pr ocesses and litigation to do so.

• Investors seek steady and predictable revenue flows , not fluctuating prices and many other factors influence the decision to build, including land and transmission availability, local acceptance, and en vironmental rules.

Commenters stated, the ineffectiveness of the capac ity markets as a tool in resource development was confirmed by a recent study by Christensen Asso ciates commissioned by the Electric Markets Research Foundation. Commenters said, the s tudy's authors concluded that RTO markets "do not and cannot address long-term capaci ty needs." Commenters said, the study also found that "[b]ilateral forward contracting remains key under any market design for locking in revenues and facilitating financing of new resource s. Commenters said, contrary to this key necessity, however, RTO markets include some design elements that impede long-term investments and long-term bilateral contracts."

C. Recent Mandatory Capacity Market Developments Cr eate Direct Impediments to New
Resources.

Commenters stated, not only are mandatory capacity markets generally ineffective in new resource development, but the markets can actually serve as barriers to new capacity development. Commenters said, these markets all hav e some type of MOPR or "buyer-side mitigation" (BSM) that imposes a floor price on off ers to sell from new resources, making it more difficult for these new plants to clear the au ctions.

Commenters stated, when mandatory capacity markets were created, the states, public power, and cooperative utilities negotiated specific and e xpress exemptions from these MOPRs in PJM and ISO-NE for resources built by load serving util ities to self-supply their own loads. Commenters said, while FERC initially approved thes e provisions as just and reasonable, in 2011, the Commission effectively stripped these sel f-supply provisions out from the relevant PJM and ISO-NE market rules. Commenters said, FERC did so based on arguments made by the generators and supported by these RTOs that the pro visions allowed load-serving utilities to exercise "buyer-side market power." Commenters beli eved these arguments are unsubstantiated and the MOPR in these RTOs is an unnecessary and in efficient barrier to entry. Commenters said, these RTO proposals and their acceptance by F ERC overturned previously negotiated agreements and provide a dramatic example of the ab sence of a commitment by RTOs to respect
all stakeholder interests.

Commenters stated, the impetus for these rule chang es was actions taken by several states
located within RTOs that had become frustrated with the lack of new, more efficient generation in their states given the billions of dollars spent by their utility customers on capacity payments. Commenters said, these states had sought to take co ntrol of their energy resource future and protect their residents from high electricity price s. Commenters said, New Jersey, Maryland, and442

Connecticut all established competitive bidding pro cesses for the procurement of capacity in their states using long-term bilateral contracts. C ommenters said, fearful of the lower prices that would result from the entry of new generation resul ting from these state efforts, owners of existing power plants sought to block this new gene ration by obtaining approval from FERC for a significant tightening of the MOPRs in PJM and IS O-NE. Commenters said, as part of the new MOPR provisions, FERC eliminated the aforementioned carefully negotiated self-supply and state resource exemptions. Commenters said, in addi tion, FERC also determined in 2012 a new, more efficient natural-gas plant under long-term co ntract in the NYISO was subject to mitigation because the plant had an unfair advantage by signin g a contract that reduced its risks and was procured through a "discriminatory" process that wa s only open to new generation.

Commenters stated, imposition of a MOPR and BSM mak es it more likely that new resources will fail to clear the capacity auctions and that t he LSEs would pay twice for new capacity (once for the plant and a second time through the market) . Commenters said, this risk makes financing for such new plants more difficult to obtain, which raises the cost of capital. Commenters said, not only do these rules adversely affect the abilit y of state utility commissions to ensure reliable service in their states, but they also raise barrie rs to resource development by public power utilities, because a MOPR greatly increases the fin ancial risk these entities face in constructing or procuring new resources. Commenters said, these rules are therefore impediments to the development of new, cleaner resources, potentially including renewable energy.

Commenters stated, in separate cases, federal distr ict courts in Maryland and New Jersey also
invalidated these state contracts because FERC has jurisdiction over wholesale power rates and states cannot take actions that impact wholesale po wer markets. Commenters said, these decisions were appealed to the U.S. Courts of Appea ls for the Third and Fourth Circuits, and both Circuits upheld the district court decisions.

Commenters stated, not only do the mandatory capaci ty markets impede implementation of the Proposed Rule by erecting barriers to new resource development, but further jurisdictional complications exist where the utilities were restru ctured at the retail level and therefore no longer own the generation. Commenters said, such "retail a ccess states" tend to be located in RTOs with mandatory capacity markets. Commenters said, these difficulties are summed up in the Navigant Paper:

"Merchant generators are for-profit companies that sell their energy at market prices and are neither under traditional utility ownership nor sub ject to state price regulation. They do not have any obligation to serve customers (load) and face m inimal price regulation at the federal level.
Even without consideration of CO2 emission reductio n objectives, the combination of RTO-run energy markets and domination of merchant generator s has led to significant difficulties in providing longer-term investment incentives to main tain proper levels of generating capacity.

Even in markets with fully-regulated, vertically-in tegrated utilities, the challenges of integrating CO2 reduction policies will be significant, but tho se utilities have the means to balance all of the options and develop a comprehensive strategy to mee t these environmental goals. In markets that
have restructured at the wholesale and retail level , and eliminated cost-of-service rates for electricity supply, resource decisions will be driv en by competing firms in response to short term price signals (and expectations of future short-ter m price signals)."443

Commenters stated, FERC Commissioner Tony Clark apt ly described this difficulty during an April 2014 technical conference: "The region of the country that continues to vex me more than any other is in those restructured regions, the Nor theast part of the country, the politics and the levels of government and the stages of restructurin g or not restructuring and how they match up offers a very unique set of challenges because you just don't have some of those command and control type levers that you have in some other reg ions of the country."

Commenters stated, ironically, those entities that remain vertically-integrated (either through asset ownership or through contracts) and maintain an obligation to serve retail customers regardless of whether their states have implemented retail restructuring - namely public power and cooperative utilities - have had their ability to procure new resources to supply their customers impeded by mandatory capacity market rule s.

However, commenters stated, the Proposed Rule does not directly address this concern. Commenters said, instead it notes that "states comm itted to Integrated Resource Planning (IRP) would be able to establish their CO2 reduction plan s within that framework, while states with a more deregulated power sector system could develop CO2 reduction plans within that specific framework." Commenters said, the Proposed Rule late r states that "in the U.S. electricity system the demand for electricity services is met, on both a short-term and longer-term basis and in both regulated and deregulated contexts, through integra ted consideration of a wide variety of possible options, coordinated by some combination o f utilities, regulators, system operators, and market mechanisms." Commenters said, these vague an d highly generalized statements do not specify how LSEs and a state within an RTO market, that have not been able to successfully contract for new, lower-emission resources, can imp lement these guidelines without significant reforms to the mandatory capacity markets.

Comment 3: Commenters stated that considering new NGCCs, or an y new sources, as part of a BSER or compliance process for existing sources is clearly contrary to Section 111.

Response 3: EPA thanks the commenters. EPA has determined that new NGCC is not BSER and is not allowing shifting generation to new NGCC units to be used as a measure for adjusting

CO2 emission rates for affected EGUs in rate-based state plans. See Preamble Section V for

BSER issues and Section VIII for State Plans.

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

Commenters stated that the proposed BSER for existi ng stationary combustion turbines is also inconsistent with proposed BSER and proposed limit for new stationary combustion turbines. Commenters said the proposed BSER for the new stati onary combustion turbines source category is NGCC technology (where the proposed fed eral standard is 1,000 pound of carbon dioxide per gross MWH for larger turbines).

Commenters stated that considering new NGCCs, or an y new sources, as part of a BSER or compliance process for existing sources is clearly contrary to Section 111. Commenters said that by definition, a new source cannot be an existing s ource, or vice versa. Commenters said that444

because existing sources, when modified or reconstr ucted, become new sources, those sources would no longer be existing sources subject to Sect ion 111(d), state plans, or state standards of performance.

Commenters stated the preamble (see NPRM, 79 Fed. R eg. at 34923) misses a vital point because by focusing solely on the "mass emission re ductions from affected EGUs" it ignores the emissions that will be created by the new NGCCs, wh ich should bear on a determination whether the state has achieved the required level of emissi on performance. Commenters added that this approach is consistent with the EPA's treatment and concerns related to sources gaming the system by making modifications to escape coming und er the emission targets. Commenters noted that a potential exception is the implementat ion of Smart System Dispatch because it is preferable to have the price that the EPA determine s apply to both existing and new EGUs based
on their relative carbon emissions. Once the carbon price is set, commenters said, an alternative is to apply that price to existing EGUs only. Comme nters said that while this alternative would not be as economically efficient as a non-discrimin atory application of the carbon price, it would not have the significant detrimental emissions impa cts discussed above. Commenters said with a pre-determined uniform price, the new NGCCs will no t artificially reduce the carbon price necessary to achieve the target reductions at exist ing EGUs. Commenters stated that new NGCCs would still shift emissions from existing EGUs to n ew EGUs, but as long as the carbon price is maintained, the overall reductions due to coal to g as re-dispatch should be maintained. Commenters noted that in the NODA, the EPA requeste d comment on whether it should designate a minimum level of re-dispatch that can o ccur in each state because states with little existing NGCC capacity could still build new NGCC c apacity to reduce the use of coal-fired facilities. Under such a mechanism, commenters note d, the new units would necessarily need to be treated as affected units, and their emissions s hould be included in calculating compliance with the EPA's goals. Commenters asked the EPA to c larify that this approach applies in all

states.

3.2.9 Regional approach

This section discusses issues related to use of a r egional approach to building block 2 to account for interstate generation shifting.

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

Comment 1: Some commenters supported using a regional approach to building block 2 to account for interstate re-dispatch opportunities.

Response 1: The EPA decided to not include the state level red ispatch approach in the final CPP, as detailed in Section V.A of the final rule p reamble of the CPP.

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

Commenters said that the EPA's proposed methodology to calculate re-dispatched generation assumes that each state must have the existing NGCC capacity to increase output in the amount445

needed to reduce emissions from existing coal units in the same state. Commenters said that this metric ignores the reality of interstate power flow s (which the EPA elsewhere recognizes) and misses an opportunity for NGCC generation in one st ate to displace coal generation in a neighboring state. Commenters said that calculating re-dispatch on a regional basis would increase the amount of re-dispatched generation by 104 TWh (or 24%).

Commenters said that section 111(d) rules permit th e Agency to recommend the contours of an allowance system that could be adopted by multiple states. According to commenters, many states have asked for such guidance.

Commenters stated EPA should recognize that for som e states, a regional budgeting approach will make more sense than using RECs for compliance . Therefore, the commenters believed
states should be allowed to enter into multi-state agreements that allow for emissions budgeting so long as the emission reductions are verifiable a nd not being claimed by another entity or

state.

Commenters supported a regional approach because it would more accurately calculate the availability of underutilized NGCC capacity nationw ide and more fairly assign emission reduction obligations across the states. Commenters stated that existing power plants are components of a complex and interconnected electric ity grid that stretches across state lines. Commenters agreed that the EPA's final guidelines w ill embody BSER if the state goals reflect
the full extent of emission reductions available to coal-fired units, whether the NGCC excess capacity is in the same state or a neighboring one. Commenters provided several examples of this interconnectedness, including ISO-NE, New England's regional transmission organization, which includes 300 generating plants and 8,000 miles of t ransmission lines. Within each ISO system, commenters noted that plant dispatch and electricit y flows are determined not by individual state regulators but by ISO-NE rules and bidding activiti es, and these factors should determine the actual amount of existing NGCC capacity that is ava ilable for re-dispatch under Block 2.

Commenters presented a calculation of the coal disp atch limitation that occurs if the available existing NGCC capacity in nine states that are serv ed by the Midwest Independent System Operator ("MISO") are considered as a group. Accord ing to commenters, a regional allocation of re-dispatch under Block 2 would produce little chan ge in the overall limitation on coal generation, but would provide for a more even alloc ation of emission reduction obligations between "low impact" states, such as North Dakota a nd Indiana, and "high impact" states, such as South Dakota, Michigan and Minnesota. Commenters stated that this approach would also facilitate regional cooperation by limiting the dif ference between rule's impact on states that are "winners" and those that face a more challenging re gulatory burden.

Commenters noted that applying the same concept to five of the states served by the Western Electric Coordinating Council (WECC) results in an additional 11 million MWh of reduced coal generation. Commenters added that it also redistrib utes the allocation of compliance obligations between Montana and Wyoming, on the one hand, which share none of the Building Block 2 burden under the EPA's plan, and Nevada, on the oth er hand, which would otherwise be expected to eliminate all of its existing coal-fire d generation.446

Commenters said that the preceding examples illustr ate a more simplified calculation process (i.e., assume that all of the units in the states a re part of MISO or WECC, which is almost, but not completely correct.) Commenters recognized that it may be more appropriate to organize and evaluate generating capacity on a sub-regional basi s. Commenters recommended that the EPA evaluate the available underutilized capacity on th e basis of how the electric generation and transmission system actually works, rather than on the basis of state jurisdiction. Once a dispatch
limitation is determined for each coal-fired unit i n a given system, commenters said that each
unit's assumed available limitation can then be inc orporated in the calculation of the emission targets for the state in which that unit is located

.
Commenters similarly noted that a regional methodol ogy is a way of making the targets for building block 2 more equitable across states; it w ould increase targets for states with little existing NGCC capacity (such as West Virginia and K entucky) and ameliorate targets for states with large excess capacity (such as Texas and Flori da). Commenters added that a regional approach would also more consistently align with on going grid operations and electricity dispatch decisions. Commenters concluded that regio nalization of the gas re-dispatch targets
would be more consistent with how the EPA calculate s the renewable energy building block targets. Commenters noted that the stronger renewab le energy targets proposed in the comment
and summarized elsewhere in this document were deve loped on a bottom-up approach from the state level, but they can be easily regionalized in a similar manner for consistency.

Commenters favored the regional scenario because Ne w Hampshire grid operators have engaged in considerable re-dispatch involving shifting gene ration among various fossil fuel-fired units
within and outside the state. Commenters concluded that the impact of meeting New Hampshire's need should be evaluated on a regional level.

Commenters acknowledged while that regional plans w ill be complex and time-consuming to develop, they will be needed to provide the lowest cost solutions. Commenters appreciated the EPA's recognition of the disparate impacts between states that have invested in NGCC and those that have not. Because most generation is operated in order to meet regional needs, commenters said that it makes sense to apply building block 2 on a regional basis as well.

Commenters recommended that the EPA calculate the e mission reduction potential for redispatch on a regional, rather than state-by-stat e, basis. Commenters stated that, while the EPA's proposal does not mandate that states achieve emission reductions through any particular building blocks, or for that matter, via any specif ic measures, the fact that targets of some states include a large re-dispatch component increases the likelihood that those states will need to rely on measures within that building block to achieve t heir targets; likewise, states whose targets do not include a re-dispatch component, or for which t his component is small, are less likely to rely on measures in this building block. Commenters stat ed that the EPA's assumption in calculating potential emission reductions from re-dispatch of c oal to NGCC also does not comport with the reality of the bulk electricity system, because coa l in one state could be re-dispatched by NGCC
in another.447

Comment 2: In comments on the Tribal & Territorial supplement al proposal, commenters supported the use of a regional approach applying t o Tribal lands and described the benefits.

Response 2: The EPA decided to not include the state level red ispatch approach in the final CPP, as detailed in Section V.A of the final rule p reamble of the CPP.

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

Commenters said that not only would a regional (rat her than state-by-state) approach to Block 2 correspond with how the electric sector actually op erates, it would ensure significantly greater emission reductions, since coal-heavy states with l ittle or no NGCC capacity would be expected to import cleaner generation from neighboring state s that do have excess capacity. According to commenters, nowhere is this "fix" more appropriate than on tribal nation lands, which function as "islands" of generation under the EPA's proposal . Commenters noted that, of the three nations affected by the supplemental proposal, the Navajo N ation and Ute Tribe have a combined 4.5 GW of privately owned coal-fired capacity but no NG CC capacity, while the Fort Mojave Tribe has over 700 MW of NGCC-fired capacity but no coal units. Commenters said that the EPA's approach calculates no emission reductions under Bl ock 2 for any of these three nations. Far from "islands," commenters stated, the plants that are hosted on these lands export the vast majority of their electricity to ratepayers in othe r jurisdictions and could easily be expected to reduce their dispatch in accord with the available NGCC capacity in nearby states.

Commenters calculated the impact on the emission ra tes of the privately-owned EGUs located on Navajo and Ute lands if the underutilized NGCC capa city that is available in the region is used as a proxy for anticipated coal unit retirements, a s EPA has done elsewhere. As proposed by the EPA, generation from coal units located in Arizona would drop from 24 million MWh/yr to zero, while under the regional redispatch approach, 9.4 m illion MWh would remain, even as coal-fired generation on Navajo lands is reduced by 16 million MWh. Since APS is a majority owner of Four Corners, commenters recommended approach, whil e achieving greater reductions than the EPA's proposal, would also balance the reductions t hat APS will need to make between assets in
states and on tribal nation lands.

Commenters said that the appropriate emission rate for tribal nation lands, applying the EPA's Blocks 1 and 2 but employing factually documented a ssumptions about the available HRI improvements at the affected units and more realist ic assumptions about the availability of existing NGCC capacity to offset curtailments of co al-fired EGUs, is 1,292 lbs CO 2 /MWh for units located on Navajo lands and 1,336 lbs CO 2 /MWh for the unit located on Ute lands.
Commenters said that this rate should be further ad justed to reflect the EPA's Building Blocks 3 and 4, as described elsewhere. According to comment ers, 1,292 lbs CO 2 /MWh may seem to be a large difference from the EPA's proposed emission r ate of 1,993 lbs CO 2 /MWh for the Navajo Nation, however, if one Navajo Generating Station u nit closes by 2019, a possibility the EPA has discussed, and if the lost generation is replaced b y renewable energy or energy efficiency while the remaining coal-fired units on Navajo land achie ve the calculated HRI improvements, the Navajo Nation's emission rate will be 1,500 lbs CO 2 /MWh. Commenters said that the Nation would be able to meet its target with modest additi onal emission reductions through coal curtailment or RE development.448

Commenters added that a regional approach is especi ally useful in the context of Indian country where a single tribal jurisdiction may not encompas s both coal and NGCC generation, and therefore coal to gas re-dispatch within such a jur isdiction would not be possible unless a regional approach were adopted. Commenters stated t hat a regional approach would enable tribal areas to take advantage of the flexibility to switc h to cleaner generation resources and reap the benefits of doing so.

Comment 3: Commenters said that the EPA did not fully conside r the logical retirement of coal units when they determined goals on a state-by-stat e basis.

Response 3: The EPA disagrees. In response to additional analys is and many comments, we have modified the proposal and RIA. Goals are set on a state basis, but reflect the wider interconnected nature of the power system. The 111 (d) final rule requires that states develop plans that establish emission standards for affecte d EGUs. We are providing states with substantial flexibility as to how they structure th ose plans to achieve the 111(d) requirements. The flexibility includes, for example, the choice o f approaches, trading, time to develop plans, additional time before the start of the interim per formance period, and the ability to shift emission rate achievement between performance perio ds. Neither the Building Blocks nor the IPM runs are prescriptive - states may consider loc al circumstances as they develop their plans. See sections V.D, VIII.A, VIII.C and VIII.G of the final rule preamble of the CPP and Chapter 3 of the GHG Mitigation Measures TSD for the CPP Fina l Rule supporting the final CPP.

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

Commenters said that setting goals on a state-by-st ate basis leads to cases where a newer, cleaner, more efficient coal-fired unit is retired as a result of the regulation while an older, dirtier, less efficient unit continues to operate o n the opposite side of a state line simply due to the target for the first state being lower than the target for the second. For instance, commenters said, in the IPM run illustrating the regional comp liance scenario for Option 1 under the CPP, Plum Point (a 670 MWh coal-fired unit in northeast AR that was built with state-of-the-art emissions control equipment and entered service in 2010) retires in 2020 while much older, less efficient units continue to operate in nearly every neighboring state. Commenters stated that coal-fired generating units are expensive, long-liv ed assets, and the effects of the retirement of one of these facilities, especially before the end of its useful life, not only will electricity users lose the benefits of its use, but ratepayers and sh areholders of IOUs, members of cooperatives and customers of public power districts will contin ue to pay for the asset as well as any new generating units built to replace its output.

Commenters noted that the service territories of th e Entergy operating companies (utilities) have a higher percentage of existing NGCC capacity (rela tive to load) than most other regions. Under the Proposed Rule, commenters said that Entergy's u tility states (Arkansas, Louisiana, Mississippi, and Texas) are required to reduce emis sions significantly even though its utility fossil average emissions/MWh already is below the s tandard for new NGCCs. According to commenters, this approach also ignores the fact tha t Entergy is in an interstate power pool balancing authority, MISO, whose MISO load represen ts approximately 24% of MISO TWh, but449

they include approximately 45% of the NGCC redispat ch potential within MISO. Commenters said that allocating this potential more broadly ac ross a larger region would reduce the collective compliance obligation of the Entergy states without weakening the overall standard.

Comment 4: Commenters stated that a critical problem with the CPP arises from the fact that responsibility for meeting and enforcing targets ap pears to be left only with the states.

Response 4: The EPA disagrees. States are required to submit p lans to the EPA, but the rule applies to sources. The EPA believes states have th e authority to achieve the requirements - see section V.A. of the preamble of the final rule for discussion of the BSER.

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

Commenters stated that the proposed 111(d) regulati ons require individual states to meet and enforce their required emission rates, while region al organizations, RTOs, ISOs or groups of states are not expressly provided this authority. C ommenters believed that this apparent conflict in state obligations and enforcement versus an allo wance for regional approaches is at the heart of one of the major problems with the Clean Air Pla n - the electric utility industry throughout the United States, with few exceptions, operates on a r egional or multi-state basis. Commenters indicated that this is true in both traditionally r egulated areas of the country with large multi-stat e companies like the Southeast (e.g., Southern Compan y, Duke Energy) and Northwest (Bonneville Power Administration and PacifiCorp), a nd in RTO centralized markets that cover much of the rest of the country. [Commenters noted that exceptions include California, New York and Texas ISOs which operate within single sta tes.] Commenters provided a figure showing the extent of power flows among states, not ing that Maryland imports a high proportion of its power needs (almost 50%), Wyoming exports al most twice as much power as it uses within the state, and all other states are between these e xtremes.

Commenters indicated that this means that state and federal regulators, and both verticallyintegrated utilities and RTOs/ISOs with responsibil ity for operating their systems, will likely need to reconcile EPA's state-by-state requirements approach with the multi-state planning, dispatch and operations that characterizes much of the electric power industry, all while maintaining reliability of the electric systems and striving to meet environmental requirements at
a reasonable cost. Commenters stated that whether a ll of these operational changes can be made while the critical requirements of reliability and affordability are satisfied, within the 2020 deadline in the CPP for meeting initial targets, is extremely problematic if not impossible. Commenters noted that while the EPA gives a 2 year delay in filing a state plan if a state is participating in a multi-state plan, it does not cu rrently allow for a delay in meeting the initial 2020 emissions targets. Commenters added that the N ODA requests comments on a potential phase-in of building block 2, which presumably woul d give more time for regional approaches to
be considered.

Commenters stated that the multi-state nature of gr id operations also holds the potential to be disrupted by a state-by-state compliance approach i n unintended and detrimental ways. Commenters suggested the following issues:450 • A state that looks solely to itself to ensure compl iance, and institutes restrictions for generating power within the state (and increasi ng its emissions) to export outside the state, would result in no one being abl e to look within that state with confidence for possible power purchases - even if p urchases might be needed for system reliability.

• And what if utilities or independent power producer s within a state not subject to state jurisdiction act on their own in ways that in crease costs or emissions, or reduce reliability, in other parts of the interconn ected network? Has the EPA provided states the authority to override existing governance of these different
entities?

• And what incentives are there in the future for tha t state to consider expanding
transmission interconnections with other states? If this state is not interested in exporting power, then why would other states be int erested in moving power into
that state?

• This state-by-state implementation/compliance plan could ultimately result in the
loss of both economies of scale and economies of sc ope currently derived from multi-state operations of electric networks. Planni ng and operating reserves would have to be increased to reflect less dependence on neighboring systems.

Commenters stated that to some degree, building blo ck 2 will be easier to implement in the traditionally vertically-integrated markets (the ar eas not covered by RTOs or ISOs) because in these markets utilities remain regulated as to gene ration output by the state public service commissions, and state regulated utilities are the ones who make dispatch decisions within the states. According to the commenters, even though st ate regulators in regulated states may not have the authority to directly dictate dispatch and /or may not feel comfortable doing so, they likely could provide direction on how many hours pl ants could operate in a given period similar to what is done with respect to other pollutants. C ommenters indicated that instead of dispatching the lowest cost mix of generation at an y point in time (within reliability and security constraints), utilities could dispatch based on pla nt emissions to meet the EPA environmental requirements - known as environmental dispatch. Com menters said that this form of dispatch would result in higher costs because plants would n eed to operate out of economic merit order, but it is one of the few options. Commenters added that another option could be for the state to set a mass-based limit and require its utilities to meet that requirement through the plants it operates - perhaps by closing coal plants or limiti ng the hours per year coal plants can operate. Commenters stated that there are significant equity issues in these determinations if there are plants with multiple owners within the state: How d oes a state decide which plants must close or limit operations to meet the state requirements? Co mmenters indicated that once the decisions are made, utilities would then use economic dispatc h the best they could with generation remaining available to the system in any period.

Commenters stated that in either of these cases - w here a utility itself alters dispatch or the state determines allowable periods of operation - ineffic iencies will result in cases where the vertically-integrated utility operates in multiple states, as the utility must operate plants according to individual state requirements when low er cost options for dispatch to reduce451

emissions might be available in another state. Comm enters added that to this extent, traditional vertically-integrated utilities operating in multip le states have some of the same problems and concerns with a state-by-state approach as do multi -state RTOs and ISOs, but because utilities in the vertically-integrated states still control disp atch under supervision of state regulators, they do have a clearer path to implementation of the CPP th an do the RTOs and ISOs.

Comment 5: Commenters argued that a regional system is the on ly way to completely eliminate potentially serious inconsistencies in the operatio ns of power plants in different states.

Response 5: The EPA decided to not include this state level red ispatch to determine goals in the final CPP, as detailed in Section V.A of the final rule preamble of the CPP.

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

Commenters stated that the ideal approach would be a regional, market-based system that is harmonized across all states sharing a regional pow er market. Commenters added that coordination across states is most easily achieved if states convert to a mass-based standard and implement a flexible, market-based approach to comp liance. Under an emissions trading program, commenters said, emissions reductions coul d be traded freely across states. Alternatively, commenters said, if states chose to achieve compliance via the introduction of a carbon tax or fee, a uniform regional emissions tax or fee would result in cost-effective dispatch.

Commenters discussed rate-based and mass-based stan dards in a regional context in which the dispatch of electricity production across a multi-s tate region is centrally coordinated.

Commenters noted that in any electricity system, pl ants are dispatched (or operated) in the approximate order of their variable operating costs with low cost plants operating almost all the time, while high cost plants operate only during th e high demand conditions in which their capacity is needed. Commenters said that the introd uction of an emissions regulation alters a fossil-fueled power plant's variable operating cost s and can thereby affect the merit-order of dispatch. Commenters said that recent analysis by B ushnell et al. (James B. Bushnell, Stephen P. Holland, Jonathan E. Hughes, and Christopher R. Kni ttel. 2014. "Strategic Policy Choice in State-Level Regulation: The EPA's Clean Power Plan" , EI at Haas WP 255 and MIT CEEPR WP-2014-09) demonstrate the implications of alterna tive policy designs on system dispatch and associated power sector outcome and summarized some of their findings.) Commenters noted that although the analysis is calibrated using data from a specific region and year (the western interconnect in 2007), the main results apply with generality.

Commenters stated that the following analysis assum es that all states use a market-based approach to meet their compliance obligation. Under a mass-based system, commenters said this means that producers within the state must purchase allowances to offset their emissions while under a rate-based system, it means that plants wit h emissions rates below the standard can sell compliance credits to the plants with emissions rat es that exceed the standard.

Commenters discussed how the simulated power system dispatch is affected under a regionally
coordinated rate-based or mass-based standard. Unde r the mass-based regime, commenters said,452

"regionally harmonized" means that the regional tar get is simply the sum of the individual states' emissions targets, with an alternative interpretati on that emissions trading is allowed across all states in the region. In either case, commenters co ntinued, the analysis assumes that permits are allocated via an auction, grandfathering, or some c ombination of these two approaches and that auctioning and grandfathering have identical impact s on marginal production incentives. Under the rate-based regime, commenters said that a "harm onized" regional target is defined by summing the mass-based targets across states (to de fine the numerator of the target) and dividing by the sum of baseline generation across all states . Then, in each case, commenters said, the dispatch model is used to identify the permit price that clears the market and therefore brings the region into compliance.

Commenters described Figure 1 (titled: "Changes in the merit order of electricity generating units with no regulation, a region rate-based regim e, and a regional mass-based regime") to illustrate how these policies affect plants' operat ing costs. Commenters said that the figure serves to illustrate two general results. First, commenter s said, variable operating costs (as perceived by the firms) are higher under the mass-based standard as compared to the rate-based standard, and it follows that electricity prices will be lower un der the rate-based approach. Commenters said
that one should not infer from this that social cos ts are higher under the mass-based standard. According to commenters, the private variable costs indicated in the graph are comprised of variable input costs (e.g., fuel) and compliance co sts, whereas social variable costs are comprised of variable input costs and the external damages fr om emissions.

Commenters said that lower electricity prices under the rate-based standard reflect the fact that a rate-based standard confers an implicit subsidy to plants with emissions rates below the standard; hence, to the extent that demand for electricity is price-responsive, there will be a higher level of electricity consumption under the rate-based approa ch compared to the mass-based approach. If consumer prices under the rate-based standard fail to reflect the full social cost of electricity production, commenters said that the level of elect ricity production, and the overall costs of achieving any mandated level of reductions, would b e higher under the rate-based standard. This means, commenters stated, that while producer varia ble costs are lower under a rate-based standard, a mass-based approach will provide a more cost-effective approach for achieving
emissions reductions.

Commenters said that the second general result to h ighlight is that, whereas the introduction of an emissions regulation changes the merit order sig nificantly relative to the unregulated baseline, under the mass-based and rate-based regional scheme the merit-order of plants is approximately the same. Under both approaches, commenters said, s ome coal plants are replaced with low-cost gas plants at the bottom of the merit order. Thus, commenters stated, the main difference between the regionally coordinated mass-based targe t and regionally coordinated rate-based target lies in the level (versus dispatch order) of production.

Commenters also considered a scenario where the str ingency of the standard varies across states in a regional power system. Commenters continued to assume that the form of the standard does not vary and all states convert to a mass-based sta ndard. Whereas the mass-based scenario in Figure 1 is based on the assumption that a single m ass-based standard applies to all plants in the western U.S., commenters said that in the present s cenario individual states have their own targets and there is no possibility of trading comp liance obligations across state boundaries. In453

this case, commenters said that it is important to keep in mind that electricity will nevertheless be traded among states within a regional power system.

Commenters described Figure 2 (titled: "Changes in the merit order of electricity generating units with a regional mass-based regime and individ ual state-level mass-based regimes") to illustrate how variation in stringency across state s affects the merit-order in this case. Commenters said that Figure 2 illustrates how a lac k of coordination or linkage between states with different mass-based standards significantly a lters the order of dispatch. For example, commenters said, technically identical coal plants that sit side-by-side in the reference merit order (the black line) are impacted very differentl y under the uncoordinated policy if they are located in states with very different emissions sta ndards. Plants in states with relatively aggressive standards see operating costs increase r elative to the reference case, commenters said, whereas coal plants in states with much less string ent standards move to the front of the dispatch
order.

Commenters said that any re-ordering of the dispatc h order that is due to inter-state differences in the stringency of emissions standards, versus re al differences in the emissions intensity of production, will undermine the efficiency of power- system operations. Commenters stated that this underscores the importance of allowing for tra des in emissions across states in the same electricity market.

Commenters also considered a scenario in which some states in a region adopt rate-based
standards while other states elect to convert to a mass-based standard, i.e., a "hybrid" regime. Commenters said that Figure 3 (titled: "Changes in the merit order of electricity generating units"), which illustrates one such hypothetical ou tcome, where the three WEST Coast states adopt a shared mass-based system, while all inland western states adopt a shared rate-based
target.

Commenters noted that the average effect of the pol icy on plant-level variable operating costs (as perceived by firms) is lower under the hybrid scena rio as compared to the scenario that features a regional emissions cap, and this is true in both th e mass-based and rate-based states. Intuitively, commenters said, this is because some compliance is achieved in the capped states by increasing imports of electricity from the rate-based states. Under a hybrid scenario, commenters said we should expect to see a re-allocation of production towards the rate-based states because the ratebased regulation subsidizes gas production. Comment ers stated that this hybrid design effectively makes imports of gas from the rate-based states to the mass-based states even more attractive than they would otherwise be. Under such conditions , commenters noted, increasing imports from rate-based states becomes a low-cost option fo r complying with the mass-based standard imposed by the coastal region.

Also, according to commenters, the states may face strong incentives to choose different compliance approaches (i.e., rate- versus mass-base d). Setting aside concerns about the administrative and process costs of coordinating co mpliance across states, commenters said that regional coordination is not the most likely outcom e given incompatibilities in economic incentives. Notably, commenters said, it can be in a state's interest to choose the opposite regulatory mechanism as their neighbors, and this i s true regardless of whether carbon allowances are traded between the states. According to commenters, Figure 3 illustrates this454

point quite clearly. Commenters noted that, conditi onal on the coastal region adopting a massbased standard, the inland states will want to adop t a rate-based standard in order to enhance their opportunity to increase exports to the mass-b ased states. Commenters added that the coastal states will benefit from increasing imports from th e inland states because this reduces the cost of complying with the mass-based standard. In other wo rds, commenters said, by choosing to implement the policy in a way that differs from the coastal states in the region, inland states can take advantage of new opportunities to import or ex port power that could lower their own individual compliance costs.

Comment 6: Several commenters said that the "regional" approac h to natural gas is inconsistent with energy markets and exceeds the EPA's authority

.
Response 6: EPA disagrees. The final rule is consistent with r egional economic dispatch as practiced by RTOs and other system operators. The final rule is consistent with existing forms of environmental regulations that are currently ful ly incorporated into system planning and dispatch, from long term planning to short term dis patch decisions. The final rule builds on the proposal and includes provisions to support trading mechanisms, both in terms of the BSER and in terms of planning and implementation. See the d iscussion of BSER in Preamble Section V and the implementation of the rule in Section VIII on state plans.

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

Commenters said that the EPA's proposal to redispa tch to NGCCs, whether on a state-by-state basis or on a regional basis, impermissibly intrude s upon the exclusive jurisdiction of FERC under the FPA. Commenters agreed that the EPA does not have the legal authority to control dispatch of electricity to the grid. Commenters sta ted that the proposed regional approach is an arbitrary, artificial way to increase the stringenc y of some states' goals and smooth out differences in state targets by normalizing states' generation mixes. Commenters said that this result is at odds with the proposed rule's stated g oal of accommodating the differences in state generation mixes.

Commenters said that a regional approach poses sign ificant complexity with respect to how regions would be determined as well as the allocati on of shares to states within each region. Commenters added that a regional approach would add another subjective element to the goal computation. Commenters stated that the EPA has not provided any details on how regions
would be determined or how shares would be allocate d among the states within a region. If a regional approach is used to determine NGCC capacit y availability, commenters said, a regional approach must also be used to determine how much co al-based generation is available to be displaced. Finally, commenters noted that the elect ric system is planned and built as an organized and coordinated structure, largely independent of s tate boundaries.

Commenters added that their analysis showed that a pplying BB2 on a regional basis would reduce the amount of coal generation remaining afte r redispatch in the West region from 109455

million MWh to 21 million MWh. Commenters believed that such a drastic reduction by 2020 or even 2030 would be completely inconsistent with sec tion 111(d) and the EPA's goal of maintaining the reliability and affordability of th e electric system.

Commenters stated that the proposal to redispatch N GCCs across a region is unreasonable,
because it fails to consider limitations on the sta tes' abilities to mandate redispatch to natural gas

. Commenters said that it is not reasonable to consid er regional scenarios when establishing goals for state plans. Commenters believed that changing economic dispatch to environmental dispatch of specific EGUs, which is integral to the EPA's un ique attempt to move outside the fence to effect CO2 reductions, is an extreme and unwise mov e away from the existing dispatch scenario. Commenters stated that such a massive change to the grid reliability/economic dispatch model is difficult to envision on an individual state basis, and even more difficult to envision on a regional level. Commenters agreed that this proposal would b e difficult to accomplish without robust analysis of the supporting infrastructure that woul d make such dispatch feasible, and a regional approach to dispatch is not warranted under this pr oposal.

Commenters explained that System Operators generall y dispatch electricity regionally on a leastcost basis, so states whose transmission facilities are under the operational control of an RTO or ISO cannot unilaterally impose redispatch to natura l gas. Commenters said that the only manner
in which an individual state could ensure that its coal-fired EGUs are not dispatched is to bid generation from coal into the RTO or ISO at a price high enough to ensure that it would be dispatched after natural gas. However, commenters s aid, there is no way for a state to know the prices at which other states, who also would be mot ivated to bid generation from coal into the market at a high price to discourage its dispatch, are bidding in their coal-fired units.
Commenters concluded that individual states would h ave no way to ensure that their coal generation is bid into the system at a price that r esults in the level of dispatch needed to comply with the state goal.

Commenters said that the only way in which states c ould ensure that all coal-fired generation is fairly and predictably dispatched across an RTO or ISO is by entering into voluntary, multi-state
contracts. Commenters said that these contracts mus t include all states in the RTO or ISO region to ensure that all coal-fired generation is bid int o the market at the same price, but this would be difficult, if not impossible, for states located in multiple RTO or ISO regions. Commenters described an example of such states that would have to enter into multiple state plans, which the commenters thought was unrealistic.

Commenters said that the EPA's approach ignores the ownership of NGCC units, and it assumes that the utilities that own fossil steam generation will be able to purchase energy from NGCC merchant generators. Applying Building Block 2 on a regional basis would exacerbate this problem commenters added. Commenters concluded that a regional approach would presume that a state reliant on another state by the EPA's calculations could actually procure energy from generators within that other state as one possible compliance option. In bilateral wholesale markets, such as those used in Arizona and other su rrounding states, commenters said that this may not be possible even if the necessary infrastru cture were in place.

Commenters said that resource selections are determ ined, in part, on a utility's customer load. According to commenters, new resources are added on ly if there is sufficient load to justify the456

need for additional resources or in response to a s tate's energy policies. Commenters stated that the proposed regional approach reduces states' flex ibility to accomplish emission reductions and could force customers to pay for additional resourc es simply to accomplish a shift to natural gas resources. Commenters added that a regional approac h may also serve to discourage increased utilization of renewable energy and end-use energy efficiency programs. Commenters’ experience in developing and operating renewable en ergy over the last decade demonstrates that significant emission reductions can be achieved wit hout dictating quotas for certain types of generating resources. Maintaining this flexibility in resource planning is critical for states and utilities as they implement the final rule commente rs concluded.

According to commenters, calculating Building Block 2 values on a regional basis would be complex, and the EPA has not provided any details o n how regions would be determined or how shares would be allocated among the states within a region. In the BSER formulation, commenters said, the EPA treats natural gas and coa l generation as two sides of the same coin; therefore, if a regional approach was used to deter mine NGCC capacity availability, a regional approach should also be used to determine how much coal-based generation is available to be displaced.

Commenters opposed using a regional approach to the application of Building Block 2. Commenters stated that there are already serious fl aws in the EPA's application of Building Block 2 on a state basis, and using a regional basi s would simply exacerbate some of those issues. According to commenters, a prime example is the failure of the EPA' goal calculation to recognize the impact on gas pipeline and electric t ransmission system infrastructure needs that would result within a state if coal generation were to be shifted to existing NGCC. Commenters said that applying Building Block 2 on a regional b asis in the EPA's goal calculation model would compound this failure by not considering whet her the necessary electric transmission and gas pipeline infrastructure exists to support such interstate energy transfers within whatever region the EPA chose to use.

Commenters stated that the existing infrastructure for natural gas delivery and electrical transmission may be overstressed by the radical shi ft called for in Building Block 2 and that reliability and resource adequacy are primary conce rns. According to commenters, the North American Electric Reliability Corporation (NERC) re cently completed an evaluation of the impact of the CPP on reliability and resource adequ acy. With respect to expanded use of natural gas, commenters said that the NERC concludes that " [p]ipeline constraints and growing gas and electric interdependency challenges impede the elec tric industry's ability to obtain needed natural gas services," in its November 2014 report titled P otential Reliability Impacts of EPA 's Proposed Clean Power Plan. According to commenters, the NERC identifies several areas of concern regarding continued reliability of the elec trical system, including: 1) the shift toward more natural gas consumption in the power sector wi ll result in a power industry that is increasingly vulnerable to natural gas supply and t ransportation risks; 2) more natural gas generation will likely create the need for addition al pipelines, which will require sufficient lead time in order to plan, negotiate contracts, permit, procure, and build new pipeline and associated natural gas processing facilities; 3) additional tr ansmission line capacity will be needed that require sufficient lead times for planning and cons truction; and 4) impacts on grid reliability will occur requiring additional time to plan and build t ransmission infrastructure to maintain acceptable margins of reliability assurance.457

Commenters added that the Western Electricity Coord inating Council (WECC), which covers a region that includes Nevada, has undertaken a study of the CPP on regional electrical system reliability and resource adequacy. That study has n ot been finalized; but commenters said that the WECC identified areas of concern in an August 2 014 project planning document titled, EPA Clean Power Plan: An Overview of WECC's Phased Appr oach that include some of the same issues identified in the NERC report. Based on the studies by the organizations charged with identifying and remedying reliability concerns, com menters concluded that the current transmission and natural gas infrastructure may not be able to accommodate an abrupt transition to a regionalized NGCC re-dispatch approach. Commen ters stated that the regionalized structure for Building Block 2 goal-setting does not address the potential compromise of electrical reliability standards and that Building Block 2 goa l-setting needs to be based on each state's individual circumstances after sufficient analysis of reliability and resource adequacy has been completed.

Commenters added that the EPA's alternative approac h to Building Block 2 calculations amounts to a mandate to burn a minimum amount of natural ga s, and the EPA has not made a determination that justifies the imposition of a ma ndate for natural gas use as a component of BSER. Commenters said that although the mandate wou ld ostensibly be used only to determine the target for Building Block 2, for practical purp oses, the actual implementation of state goals would have to mirror the targets in the other Build ing Blocks to a very large degree. Commenters said that any predefined amount of natural gas usag e would be arbitrary and would lock states into a specific technology and fuel - potentially t o the detriment of cleaner fuels - which would further reduce state flexibility and go against pri nciples of fuel neutrality and cost effectiveness.

Comment 7: Commenters generally opposed using a regional appro ach to building block 2.

Response 7: EPA disagrees. The final rule is consistent with r egional economic dispatch as practiced by RTOs and other system operators. The final rule is consistent with existing forms of environmental regulations that are currently ful ly incorporated into system planning and dispatch, from long term planning to short term dis patch decisions. The final rule builds on the proposal and includes provisions to support trading mechanisms, both in terms of the BSER and in terms of planning and implementation. See the d iscussion of BSER in Preamble Section V and the implementation of the rule in Section VIII on state plans.

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

Commenters stated that the EPA should not redefine BB2 by calculating it on a regional basis (or modify the way it calculates state goals by imposin g a minimum level of re-dispatch). Commenters believed that to do so ignores the fact that every state and region has unique generation portfolios that reflect specific energy demand requirements and resource availability.

Commenters similarly did not support the regional a pproach (or a minimum level of re-dispatch), preferring the proposed approach under which a stat e's baseline and goals for building blocks 1 and 2 are based on that state's existing generation , since the proposed rules are to regulate CO2 emissions from existing power plants, not new ones. Commenters stated that it does not seem458

reasonable or fair to set a state's goal for buildi ng block 2 premised on shifting generation to
NGCC units that do not exist in the state based on the amount of NGCC generation in another state, nor to base a state's goals on a theoretical potential to increase NGCC generation in other states over which the commenters’ state (Iowa) and Iowa's utilities have no input or control. Commenters observed that under the EPA's proposed r ules, application of all the building blocks has different impacts on different states depending on their particular circumstances and opportunities to reduce CO2 emissions, and asserted that it does not seem reasonable to change only building block 2 just because application of t hat building block has varying impacts on states without taking a more holistic look at how a ll the building blocks have varying impacts on

states.

Commenters referred to the NODA and stated that, si nce the ERCOT region is an island located entirely within Texas' borders with very little int erconnection with other states and regions, regional availability of NGCC has little relevance and provides little benefit to Texas. Commenters, in response to revisions to the glide p ath described in the NODA, stated the EPA should withdraw Block 2 in its entirety rather than revise the block. Commenters noted the proposed rule's potential impacts on Texas, Mississ ippi and Louisiana and the difficulty for these states to achieve compliance by 2020. Commenters st ated that, given the importance of coal to these states, any relaxation of requirements is app reciated; however, what EPA has proposed in the NODA will ultimately do nothing to alleviate th e harms that the Rule Proposal and BSER
Block 2 will inflict on these states. Commenters re ferred to the NODA and stated that, EPA's proposed revisions to Block 2 stringency are largel y illegal, provide little relief to coalgenerating units, and may actually increase stringe ncy on coal electricity generators. Commenters stated that, since the EPA has not provi ded specific proposals or explanations regarding the use of natural gas "more comprehensiv ely or holistically," they are unable to
comment further.

Commenters stated the EPA must consider state- and source-specific factors in establishing the Building Block Two targets. Commenters objected to the regional approach suggested in the NODA to the extent it would assume NGCC capacity ca n be made available in a state where such capacity currently does not exist.

Commenters stated the other Block 2 alternative app roaches offered in EPA's NODA should not be applied in the final guidelines because these ne ed to be better justified, details clarified, and outcomes analyzed and issued for public comment. Co mmenters stated that requiring a minimum level of natural gas dispatch may not be technicall y supportable as the BSER. Commenters said that the regional approach may not qualify as BSER and/or has not been adequately demonstrated. Commenters added that the regional ap proach may not qualify as the BSER, and it also poses significant complexity with respect to h ow regions would be determined as well as the allocation of shares to states within each region. Commenters stated that such a determination is not supportable, since individual states have limit ed existing NGCC capacity and there are constraints on building new capacity.

Commenters stated that there are important local li mitations and constraints on distribution and generation that must be accounted for in determinin g dispatch. As an example, commenters noted that some plants must be run to maintain load ; transmission bottlenecks can prevent perfectly efficient distribution, and it cannot be assumed that electricity generated from459

alternative sources can be transmitted to all consu mers. Commenters stated, in States such as Texas where electricity transmission is managed by multiple ISOs, it may be impossible to move electricity across ISOs from one part of the State to another; the availability of wind and solar generation will depend on local conditions that var y from State to State (and within States) and
over time. Commenters stated that the fact that the States are best situated to make these types of local policy and technical determinations is reinfo rced by the numerous errors EPA made in connection with the four Building Blocks in the pro posed rule.

Comment 8: In comments on the Tribal & Territorial supplementa l proposal, commenters stated the Navajo Nation is opposed to either regional app lication of Building Block 2 goals or setting a minimum level of gas usage for all jurisdictions, a s these would require excessive cost and impose severe economic hardship on the Navajo Natio n.

Response 8: The EPA decided to not include this provision in th e final CPP, as detailed in Section V.A of the final rule preamble of the CPP.

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

Commenters stated the Navajo Nation agrees with EP A that because there are no natural gas combined cycle plants on the Navajo Nation, there i s no need to apply Building Block 2. Similarly, commenters noted that the Navajo Nation economy is highly dependent on the use of Navajo coal, a tribal trust asset.

Commenters said that under the Proposed Rule, all s tates and jurisdictions have the option of participating in a regional section 111(d) program if they believe that it is in their best interest; therefore, the EPA does not need to require a regio nal application of any of the building blocks. Commenters added that the proposed rule allows juri sdictions to establish their own regional trading programs which can help to even out differe nces between states.

Commenters stated that in the proposed supplemental rule EPA correctly concluded that building block 2 is not applicable on the Navajo Nation beca use there are no natural gas complying cycle units on the Navajo Nation for redispatch to occur, however, EPA has discussed additional approaches to building block 2 in the October 30th, 2014 notice of data availability and one such approach includes the adoption of the minimum level of generation shift concept. The commenters stated that this concept presents numero us achievability standards if applied to the Navajo Nation, however EPA should not expand the ty pe of natural gas facilities in its determination of the best system of emission reduct ion to include coal firing with natural gas. Commenters opposed the inclusion of coal firing nat ural gas at existing coal fire plants as part of building block 2 because of the technical obstacles and cost considerations that coal firing would present at the Four Corners Power Plant. The commen ters stated that the Four Corners units are currently equipped with the ability to combust a sm all amount of natural gas for start-up operations and early flame stabilization, however t he amount of heat input from natural gas
combustion is limited to a small fraction of the to tal heat input to the units. Commenters stated that an enormous capital investment to modify the b oilers and increase the natural gas supply infrastructure which would also take numerous years to complete, would be necessary to achieve460

a material reduction in carbon emissions from coal firing natural gas and such actions simply cannot be rationalized or cost justified.

Comment 9: Through RGGI, commenters asserted that participati ng states implement coordinated CO2 emission budget trading programs th at, in aggregate, establish an overall limit

on allowable CO2 emissions from affected EGUs in th e participating states.

Response 9: The EPA decided to not include this provision in t he final CPP, as detailed in Section V.A of the final rule preamble of the CPP.

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

The commenters stated that RGGI already provide a f ramework for participant states to collectively work together to reduce CO 2 emissions, and it has generated revenues from the sale
of CO 2 allowances that are used to fund EE and RE program s. For example, the commenters noted that from 2009-2012, the 9 RGGI states have i nvested auction proceeds of more than $700 million in programs that lower costs for energy con sumers and reduce CO 2 emissions. (Regional
Investments of RGGI CO 2 Allowance Proceeds, 2012 (2014), available at http ://www. rggi.org/docs/Documents/20 12 .Investment-Report.pd f).

Commenters asserted that while the EPA cites RGGI a s an example of a model program, the RGGI states voluntarily adopted a multi-state progr am that taxes emissions of CO 2 , but Congress has not provided the authority to the EPA to tax CO 2 emissions, nor can the EPA force states to
tax CO 2 emissions. Commenters stated that the EPA should n ot use the RGGI approach as an example program since the RGGI approach relies on v oluntary carbon taxes that cannot be legally forced upon a state.

Commenters cited recent FERC testimony before Congr ess stating that:

"...it is probably too early to know with specificity exactly what those impacts will be and the primary driver for is that we simply don't know what the potential State implementation plans, compliance plans might look l ike, and we also don't have a sense for what a Federal implementation plan or a Federal compliance plan would look like."

Commenters stated that, although the EPA has said t hat they will offer flexibility to states, potential plans seem to rely in some part on a comb ination of cap and trade, like a regional gas house initiative like they have in the northeast, s ome sort of reliance on energy efficiency and demand response resources, a shuttering of coal pla nts and, at the same time, pivoting towards heavier reliance on natural gas, perhaps some sort of renewable portfolio standard in the state.
Commenters stated this looks like what one of the r egions, New England, has already been going through.

To implement a regional approach, commenters stated FERC recognized the need to ensure that as it moves forward, that some of the concerns seen in New England with the pipeline constraints and the rapid conversion to gas and the very tight reliability system and sometimes very high cost for electricity aren't exported to other regio ns of the country, and overcoming that could be a461

challenge. Commenters concluded that the national e xperts charged with reliability, FERC, recognized the RGGI program has experienced growing pains as it was implemented.
Commenters did not believe it should be touted as a model program for the entire country when FERC has described reliability and cost concerns.

Comment 10: Commenters noted that the proposal to use a regiona l approach, combined with the rule's promotion of nuclear as an emissions-red ucing resource and the concern placed on preserving existing capacity, opens up the possibil ity that states would turn to regional emissions programs that permit use of nuclear as an offset to fossil fuel generation.

Response 10: The EPA decided to not include this provision in th e final CPP, as detailed in Section V.A of the final rule preamble of the CPP.

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

Commenters stated that such programs would both lim it the extent of CO 2 emission reductions by providing an alternative regulatory compliance m echanism for fossil fuel plants, and they would limit the growth potential of renewables by f looding the market with emissions credits. Commenters stated that replacement of state renewab le portfolio standards with so-called "clean" energy standards that include nuclear would have a similar effect.

Commenters described previous efforts to create reg ional emissions-reduction programs, but
none of them reached fruition. Commenters noted tha t the long-established opposition to renewable energy and emissions regulations in the S outheast and the unique level of commitment among states in the region to developing new nuclear, could provide conditions for regional implementation plans that utilize nuclear as a primary compliance mechanism for achieving state goals. In so doing, commenters said , states may be able to achieve the goals, not by reducing CO 2 emissions significantly, but by "diluting" their e missions rate with additional nuclear capacity. According to commenters, this pos sibility is as much an artifact of the originally proposed BSER formula as it is a flaw of including nuclear - and renewable capacity and efficiency could produce the same effect - but the EPA's failure to do an accurate calculation of the costs and environmental impacts of nuclear c ould create a biased yardstick by which to evaluate state implementation plans.

Commenters recognized that regional approaches may be advantageous, especially considering that all but five states participate in RTOs with i nterconnected electricity grids. Even though establishing a regional emissions program would rel ieve states of none of their obligations to meet the CPP's mandated emissions goals, commenters said that the adoption of regional compacts that utilize emissions offsets and non-BSE R resources could encourage the preservation of fossil fuel generation sources and uneconomical low-/zero-carbon resources.
Such an outcome could both limit emissions reductio ns that would otherwise be possible and lead states to put off investments in new infrastru cture and innovation, commenters added, leaving them unprepared to make deeper reductions i n emissions after 2030. Commenters462

encouraged the EPA to set forth guidelines for how states may structure regional greenhouse gas programs to reflect best practices and to optimize emissions reductions and cost-effectiveness. Commenters stressed that programs that adopt emissi ons offsets should be strictly limited, and those that include nuclear as an offset option shou ld be disqualified.

Commenters said that the draft rule notes that rate -based approaches could result in nuclear power receiving disproportionate support over renew ables, but does not set a guideline or standard to regulate the extent of reliance on nucl ear in states' implementation plans. Without such guidance, commenters were concerned existing r eactors would receive benefits that are intended to support deployment of sustainable techn ology, drive innovation, and produce cost efficiencies and that could distort renewable energ y credit (REC) markets. Commenters said that the draft rule's incorporation of 6% of states' exi sting nuclear capacity in the computation of state goals would encourage states to include nuclear as an offset in such programs. According to commenters, that would require states to set higher offset limits, in order to credit resources that are effective at reducing emissions or converting o r removing greenhouse gases from the atmosphere. Doing so, commenters said, would effect ively increase the amount of carbon emissions by enabling fossil fuel generation source s to buy their way to compliance rather than by reducing emissions. In states such as Illinois a nd South Carolina, in which nuclear approaches 50% of the states' electricity generation, commente rs noted that just 6% of nuclear would account for nearly all of the 3.3% of CO 2 emissions from fossil fuel generation sources - wi thout, however, removing a single pound of CO 2 from the atmosphere. Even in states with lower proportions of nuclear capacity, commenters added, the effect would be the same, just to a lesser degree. Commenters stated that the EPA may not be a ble to directly regulate regional emissions compacts under the CPP, but it can define the way i n which measures states include in their CAA section 111(d) implementation plans are credited to ward compliance. In the final rule, commenters concluded, the EPA should establish guid elines defining what aspects of regional emissions programs will count toward compliance.

Comment 11: Commenters noted a recent FERC Order recently uphel d by the U.S. Court of Appeals for the DC Circuit which updated and enhanc ed requirements for utilities to participate in regional transmission planning.

Response 11: EPA agrees that regional planning under FERC Order 1000 can facilitate implementation of this rule.

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

Commenters said that the U.S. Court of Appeals for the DC Circuit recently unanimously upheld FERC Order 1000, which updated and enhanced require ments for utilities to participate in regional transmission planning in addition to cost allocation reforms and other matters, which could have implications for the achievability of Bl ocks 2, 3 and 4 as well as costs for states with utilities subject to FERC jurisdiction. South Carol ina Public Service Authority v. F.E.R.C., Cause No. 12-1232, decided August 15, 2014 (D.C. Ct . App. 2014). Commenters said that it is unclear whether the EPA assessed the impacts of FER C Order 1000 and other FERC orders in its evaluation of building blocks 2, 3 and 4, particula rly with respect to cost impacts to utilities and463

consumers. Commenters added that since FERC jurisdi ction is limited in Texas, not all Texas utilities are subject to FERC Order 1000, which sho uld be considered by the EPA in evaluating the potential emission reductions attributable to b uilding Blocks 2, 3, and 4.

Comment 12: Commenters did not believe that defining regional r enewables targets will address the problem with cross-state crediting, as states m ay choose to fund renewable energy projects outside of regions with which they have an agreemen t for their SIP.

Response 12: The EPA decided to not include this provision in th e final CPP, as detailed in Section V.A of the final rule preamble of the CPP.

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

Commenters said that having pre-defined regions wou ld reduce flexibility and limit the costeffective options available to states. In order to address the issues raised by stakeholders with crediting in-state generation purchased by other st ates, commenters said that the EPA should
allow states with renewable resources to net their renewable generation sold out-of-state against their targets. Commenters said that this approach w ill allow compliance while also avoiding double-counting.

Comment 13: Commenters believe that the alternative regional ap proach would be more reasonable and better represent BSER if additional adjustments can be included in the final emission guidelines.

Response 13: The EPA thanks the commenters. In response to addi tional analysis and many comments, we have modified the proposal and RIA. Th e Building Blocks are not prescriptive but the EPA believes that the 111(d) final rule establi shes reasonable CO2 emission performance rates. The rule requires that states develop plans that establish emission standards for affected EGUs. We are providing states with substantial flex ibility as to how they structure those plans to achieve the 111(d) requirements. The flexibility in cludes, for example, the choice of approaches, trading, time to develop plans, additional time bef ore the start of the interim performance period, and the ability to shift emission rate achievement between performance periods. See sections V.A, V.D, VIII.A, VIII.C and VIII.G of the final ru le preamble of the CPP and Chapter 3 of the GHG Mitigation Measures TSD for the CPP Final Rule supporting the final CPP

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

Commenters suggested that, for reasons of burden-sh aring, the EPA should adopt a minimum performance level requirement for coal-fired EGUs c ommiserate with a 20% reduction in emissions intensity for coal. Commenters stated tha t this value is about 1.75 lb/kWh and recommended this in place of the proposed reassignm ent of NGCC capacity to states currently
without NGCC.464

Comment 14: Commenters stated the proposed rule places Florida in a southeast region with Kentucky, North Carolina, South Carolina, Tennessee , Mississippi, Alabama, and Georgia.

Response 14: The EPA decided to not include this provision in th e final CPP, as detailed in Section V.A of the final rule preamble of the CPP.

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

Commenters stated Florida's import transmission ca pability is limited to approximately 3,800 MW, or 6.6% of total capacity. Commenters concluded that Florida's geographical location and corresponding energy import limitations should mini mize reliance on regional dispatch hypotheticals and confine Florida's redispatch incr eases (for Final Goal computation) to those within the state going from 61-70%.

Comment 15: Some commenters stated that additional information is needed from the EPA on how a regional approach to BB2 would work.

Response 15: The EPA decided to not include this provision in th e final CPP, as detailed in Section V.A of the final rule preamble of the CPP.

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

Although this approach might better resemble the wa y that power markets work than the EPA's current proposal, commenters said that they cannot reasonably evaluate this proposal unless the EPA provides additional details about the approach, such as how the EPA would develop the regions, how it would model power transfers and tra nsmission capacity among states, how the approach would impact individual state goals, how r egional NGCC resources would be allocated in the context of individual state compliance deter minations, how it will address the fact that different ownership structures and contractual arra ngements for NGCC facilities will affect each unit's ability to reduce the need for other generat ion elsewhere, and other questions. Commenters stated that the EPA must provide the required techn ical and economic analyses before proceeding with a regional approach. Commenters add ed that in addition to providing more information, the EPA must solicit additional commen t on this proposal before deciding to adopt
it in the final rule. Commenters added that if the EPA pursues this approach, then it must withdraw the Proposed Rule and issue a new proposed rule that details how the regional approach works and the specific requirements that w ould be applicable based on application of the regional approach and other building blocks.

Commenters added that because the EPA lacks the aut hority to require redispatch, it is precluded from setting standards in any final rule utilizing this approach.465

Commenters stated that a critical problem with the CPP is that responsibility for meeting and enforcing targets appears to be left only with the states, even though regional approaches are encouraged. Commenters indicated that the EPA sugge sts that regional implementation is viable, referencing specifically the northeastern RGGI or C alifornia's cap and trade program (which has been made available to regional and Canadian partic ipants), both of which are voluntary programs that the states have adopted, but says not hing about whether or what changes to these existing programs would be necessary to meet the pr oposed requirements. Commenters identified two issues with the California program: (1) they assign carbon emissions from imports to the state to the first seller in the state, whic h would not work in a regional plan, and (2) the program has multi-sector coverage as opposed to the EPA plan which covers electric generating units only. Commenters also noted that RGGI uses a mass-based emissions target that is regionally based and does not require individual st ates to meet state emission targets as long as they have bought sufficient credits from someone el se in the region. Commenters asserted that the EPA should provide further guidance in its fina l rule on how existing regional frameworks need to be modified and how or if new regional fram eworks can be established.

3.2.10 Setting a floor

This section discusses issues related to setting a floor for the shift of generation to NCCU units as part of Building Block 2.

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

Comment 1: Commenters expressed support for setting a floor fo r NGCC redispatch

Response 1: See section V.D of the final rule preamble of the C PP for the EPA’s response to

this comment.

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

Some commenters supported the alternative approach the EPA proposed, in which a minimum level of generation shift from coal to gas would be adopted for each state. Commenters stated that it is important to take advantage of the poten tial reductions in point-of-combustion emissions that can be achieved through new NGCC and co-firing and stated that the minimum shift approach ensures a coal-to-gas shift will occ ur in all states with coal-generation, not just those with underutilized existing NGCC capacity. Co mmenters urged EPA to consider ramp rates up to and including a continuation of a 5% pe r year shift rate, the 1-year historic average. Commenters supported setting the minimum floor at t he 12% suggested by EPA in the NODA.

Commenters recommended that the EPA adopt as a comp onent of BSER, a minimum level of generation shift from higher-emitting to lower-emit ting fossil sources that can be met by any of
these methods. Commenters stated this minimum level should be based on what is cost-effective
and reasonable based on historic trends and electri c and natural gas sector modeling.
Commenters stated the EPA should assume that at lea st 2% of a state's coal use shifts to natural466

gas per year from 2020 to 2029 (at least 20% over a 10-year period) through a combination of
these three means.

Commenters stated that, if the amount of under-util ized existing NGCC capacity in a state (or other pathways of coal to gas transition) would all ow for a greater redispatch between coal and gas, that higher level should be used to set the st ate's target. Regarding whether the EPA should allow new NGCC plants to be a source of compliance credits even if those plants were not considered in setting the targets, commenters state d that the EPA must maintain symmetry between the target setting and compliance.

Commenters asserted that states (and likely sources ) will have significant flexibility in choosing which combination of measures to employ to meet the ir applicable targets and indicated they will urge states to rely as much as possible on efficien cy and renewables to achieve compliance, in order to avoid or limit expanded reliance on natura l gas. Commenters found that the building block and flexible compliance concepts proposed in the CPP are generally constructive and suggested the EPA continue to ensure the intended f lexibility is carried through in the final rule.

Comment 4: Commenters stated that they do not believe that the EPA should establish a minimum value as a floor for the amount of generati on shift that can be achieved via Building

Block 2.

Response 4: In the final rule, the EPA does not use the floor a pproach to Building Block 2. See Preamble Section V.D for Building Block 2 and Secti ons VI and VII for determination of performance rates and state goals.

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

Some commenters did not support the setting of a mi nimum level as the EPA proposed. Commenters stated the suggested BB2 alternatives in the NODA are unlawful, unsupported, and
unworkable. Commenters believed EPA's alternatives are equally, if not more, unjustified than the originally proposed BB2. This commenters object ed to the EPA considering new NGCCs which are not affected sources subject to this rule as part of determining the stringency of BB2.
The commenters also stated that the EPA cannot accu rately assess the potential of co-firing natural gas in existing coal-fired EGUs due to unit -specific characteristics, natural gas availability, pipeline infrastructure, fuel prices and overall electricity demand, nor can it accurately project the development of new NGCCs. Th e commenters stated that any mandated shift in generation, from coal-fired units to natur al gas-fired units, is thus arbitrary.

Commenters indicated that in section III.B.1 of the NODA, the EPA identified a potential approach regarding additional use of natural gas un der building block 2, especially in states with little or no existing NGCC capacity. The commenters further said that in the same section of the NODA, the EPA also highlighted an alternative appro ach from the June 2014 proposal, in which regional availability of NGCC generation would be c onsidered, rather than just in-state availability of NGCC generation, when setting build ing block 2 targets.467

Commenters indicated that it did not support either of the alternative approaches. Under the EPA's proposed approach, a state's baseline and goa ls for building blocks 1 and 2 are based on that state's existing generation, which makes sense since the proposed rules are to regulate CO2 emissions from existing power plants, not new ones, the commenters said. Given this, it does not seem reasonable or fair to set a state's goal for b uilding block 2 premised on shifting generation
to NGCC units that do not exist in the state based on the amount of NGCC generation in another state, in the commenters’ opinion. The commenters b elieved it also does not seem reasonable or fair to base a state's goals on a theoretical poten tial to increase NGCC generation in other states over which Iowa and Iowa's utilities have no input or control.

In addition, commenters stated that under the EPA's proposed rules, application of all the building blocks has different impacts on different states, depending on their particular circumstances and opportunities to reduce CO2 emiss ions. The commenters concluded it does not seem reasonable to change only building block 2 just because application of that building block has varying impacts on states without taking a more holistic look at how all the building blocks have varying impacts on states.

Commenters stated the EPA should not modify the way it calculates state goals by imposing a minimum level of redispatch or redefine BB2 by calc ulating it on a regional basis because that would ignore the fact that every state and region h as unique generation portfolios that reflect specific energy demand requirements and resource av ailability. Commenters believed, as proposed in the NODA, EPA's new approach mandates b urning a minimum amount of natural gas with no determination justifying the imposition of natural gas use as a component of BSER. Moreover, the commenters stated that although the m andate would ostensibly be used only to determine the target for BB2, for all practical pur poses, the actual implementation of state goals would have to mirror the targets in the other build ing blocks to a large degree. The commenters believed any predefined amount of natural gas usage would be arbitrary and would lock states into a specific technology and fuel - potentially t o the detriment of cleaner fuels - further reducing state flexibility and against principles o f fuel neutrality and cost-effectiveness.

Commenters recommended the BSER determination shoul d not include a minimum natural gas utilization assumption because the approach would ( 1) be arbitrary and infringe on state energy planning and regulation authority and (2) disregard the remaining useful life of the coal
units located in those states.

Commenters did not support setting a minimum floor for NCGG and stated that a floor would
strand assets in states where there are reliable co al-fired generation units with useful lives beyond the BB2 phase-in period of 2020-2029. The co mmenters were concerned that a minimum
level of NGCC utilization would create market disto rtions, preventing a utility from providing the least-cost resources to its consumers, especial ly during times of natural gas price volatility, and would increase prices. The commenters stated th at a floor would require a significant build out of electricity generation and transmission, as well as the natural gas infrastructure necessary to serve those generators, and it is not clear that the assets would be in place by 2020 or even 2030 in some cases. Commenters stated creating a fl oor would be arbitrary and ignores the existing circumstances of states with little to no NGCC and the many technical and economic reasons they may have for not having any plans to u tilize NGCC technology.468

Commenters said BB2 punishes states that burn more natural gas for electricity generation and rewards states that burn less, and that EPA is seek ing to fix this by forcing redispatch to NGCC
units that do not exist. The commenters believed th e only reasonable solution to BB2 is to remove it (along with the other three building bloc ks) and start again with a rule that complies
with the CAA.

Commenters stated EPA should not modify the way it calculates state goals by imposing a minimum level of redispatch or redefine BB2 by calc ulating it on a regional basis because every state and region has unique generation portfolios t hat reflect specific energy demand requirements and resource availability.

Commenters recognized that requiring a minimum coul d help ensure overall U.S. grid reliability, but stated that given the potential costs associate d with building such gas infrastructure, a minimum level of gas adoption would not be helpful. The commenters said the proposed rule's unique application to the hydropower dependent Paci fic Northwest may require the development of additional natural gas-fired generation to compe nsate for the limited thermal capacity that presently exists in the region (this would be the only operationally effective alternative to trying to try on building blocks three and four to maintain grid reliability). The commenters said requiring the development of a very large reserve m argin may not be effective in application on a state-by-state basis, given the regional nature of the Pacific Northwest grid. According to the commenters, this new requirement would mandate yet another costly requirement that may not be necessary if the proposed baseline and emission- rates proposed for Pacific Northwest states were modified to accommodate the region's dependenc e on hydropower generation. The
commenters said that review and decisions related t o generation resource planning infrastructure are best led by existing authorities in concert wit h utilities.

Commenters supported the inclusion of new NGCC in B B2, but asserted that the proposed 12% floor for redispatch in states with low or no exist ing NGCC capacity would have limited impact. The commenters declared that its analysis indicates that the proposed 12% floor would only apply to nine states and add a small amount of addi tional NGCC generation - about 30,000 GWh nationwide. The commenters suggested that, in lieu of a floor, EPA consider deriving new state NGCC capacity targets using the national compound a verage growth rate for natural gas projected by the U.S. EIA's Annual Energy Outlook, and also consider the production capacity and construction plans for new natural gas pipeline s, as well as the potential to re-power existing
coal EGUs..

Commenters noted that Wyoming has little NGCC gener ating capacity and stated that it is not clear why this disparity should be an administrativ e priority. Commenters suggested these decisions should be made in response to the myriad economic and practical considerations that have long been standard in the industry. Rather tha n adopting an arbitrary minimum for gas consumption, the commenters stated it makes more se nse to develop a complete understanding of
those difficulties and address them. Commenters ref erred to their letter to the EPA dated December 16, 2013 and stated that, while the premat ure closure of coal fired EGUs will likely result in the construction of new NGCC capacity to meet existing demand, it is not clear whether this new NGCC capacity would or should be construct ed in Wyoming. Commenters noted that the only natural gas conversion presently scheduled in Wyoming, the Naughton 3 unit in 2018, will simply fire the existing boiler with gas rathe r than coal, which is not a replacement of the469

existing unit with an NGCC unit, and it is not a us e of gas that is in any way the efficiency equivalent of a new NGCC unit. Commenters added tha t the most recent construction by PacifiCorp of new NGCC capacity has been closer to load in Utah, a reflection of the fact that existing transmission is not the dominant economic determinant.

Commenters stated they have similar doubts about co -firing, as it may increase ratepayer costs without materially altering the scale of the task c onfronting the state. The commenters believed the entire section 111(d) program will cause a cont raction of Wyoming's economy, due to the impact on its coal industry, the premature retireme nt of a major portion of its coal fleet, and to the resulting increase in electricity rates, which will directly affect the state's economic base of industrial users, who accounted for 58.98% of Wyomi ng electricity sales in 2012.

According to commenters, such a mandate restricts t he ability for states to identify flexible compliance mechanisms by dictating certain resource utilization outcomes. Commenters
concluded that such determinations do not fall with in the scope of the EPA's authority under the Clean Air Act, with commenters adding that such det erminations are the purview of state utility regulators. Commenters said that the EPA should con sider system-wide modeling for all building blocks together to inform how generation will move among states and what generation and emissions are offset in each state, including state s without existing NGCC units, by the building block 2 requirements.

Commenters added that this area of the NODA reflect s a misunderstanding of the manner in which deregulated energy markets operate, and that EPA could only recognize new NGCC in their feasibility projections via a carbon tax thro ugh IPM, which the commenters fundamentally disagreed with. The commenters stated that the conc ept of a minimum "floor" level for generation shifting, and Building Block 2 in its en tirety, must be abandoned.

Commenters recommended that EPA not include new NGC C into section 111(d) target setting or compliance. The commenters supported EPA allowing t he segment of new NGCC generation that outperforms the section 111(b) NSPS to 'count' towards satisfying section 111(d) compliance targets. The commenters said EPA should leave it to the discretion of the state whether they wish to opt-in new NGCC in target sett ing for EPA's proposed 70% capacity factor target for existing NGCC. The commenters added that EPA should eliminate the BB2 target component for Minnesota, giving deference to the Mi nnesota established Integrated Resource Planning process, which is already giving considera tion to fuel diversity, cost and environmental profile, including CO2 environmental externalities. The commenters also supported EPA's clarified intention to allow RE and customer energy efficiency to receive treatment in the denominator of emission rate compliance determinati ons.

Commenters stated that RTOs may be required to acce lerate development of NGCC facilities to meet the re-dispatch requirements of BB2 without as surances that the 70% utilization rate under
BB2 can be met.

Commenters recommended that EPA allow NGCC units un der planning and construction that are not subject to EPA's 111(b) requirements to emit CO 2 annual emissions reflecting unimpeded operation across their full operating range. The co mmenters added that this sort of unimpeded planning and operation would be allowed if the unit was subject to 111(b) NSPS requirements470

and it is notable that the difference between under deployment new NGCC heat rate performance and 111(b) NSPS affected unit heat rate performance is not significant enough to warrant impeding the operation of these under construction NGCC units. The commenters stated that EPA should simply acknowledge that those resources already in approved state integrated resource plans or under permitting and/or physical construction pre-date the timing of CPP applicability, represent a small population of gene rating units and represent good CO2 emitting performance regardless of CO2 NSPS not being applic able. The commenters said that EPA should, in turn, allow the units to operate unimped ed by CPP requirements currently under proposal.

Commenters recommended that the EPA eliminate its B lock 2 requirements of imposing greater Block 2 targeted natural gas dispatch on less impac ted states (e.g., assigning a minimum portion of state generation to NGCC) completely for states that utilize an integrated resource planning (IRP) process, allowing power market conditions to continue to establish optimal least-cost conditions for dispatching natural gas resources. F or states without an IRP process, commenters said that the EPA should eliminate the portion of p rospective existing NGCC capacity factor dispatch that supports preserving electric system r eliability, operating intermittent renewable energy resources, or for service periods during whi ch NGCC serves peak customer demand, system reserve requirements and system spinning res erve requirements. In the case of Minnesota, commenters anticipated that the residual component for existing NGCC re-dispatch for displacement of existing coal generation will be ne ar zero at least until new NGCC generation is deployed that is able to replace the services of ex isting NGCC, considering that today's IRP deployments and wholesale markets show optimized pe rformance at existing NGCC utilization
levels.

Commenters said that the aspects of the NODA for wh ich comment were sought may add further complication to understanding the proposed rule and do not offer additional insight as to how EPA might ease the interim goals or glide path. Th e commenters said that it appears any easing of the interim goals will be offset with stricter g oals from another building block or cause more stringent goals to be added to another state. The commenters does not agree that EPA should require states to build more NGCC units in recalcul ating state goals or offset the growth opportunities that may be afforded in BBs 3 and 4.

Commenters were concerned that inclusion of a minim um level of natural gas co-firing and new NGCC deployment as components of the BSER would rai se the cost of the Proposed Rule considerably and potentially expose the rule to inc reased legal risk. Commenters were also concerned with additional risks that might compromi se electric reliability or complicate compliance with local, regional, or state regulatio ns. Commenters said that, according to the EPA, the cost of reducing emissions through re-disp atch to new NGCC units could cost as much as $81 per metric ton, which is significantly more expensive than the EPA's estimates for the other Building Blocks.

Commenters said that if shifts in generation due to re-dispatch or co-firing for states with low Block 2 requirements do not trigger corresponding r eductions in emissions targets for states with little or no NGCC generating capacity, then EPA wil l essentially be punishing low-NGCC states as a means to merely appease high-NGCC capacity sta tes, which is not only inequitable, but is simply not allowed by the CAA. The commenters state d that although some states are treated471

inequitably under the Rule Proposal, EPA should not increase the stringency of guidelines in low-NGCC states to eliminate "significant dispariti es" between states. The commenters stated that the Rule Proposal puts states in competition f or an arbitrarily limited amount of allowable CO2 emissions, with the agency illegally placed as an arbiter of fairness and equity, a situation which is neither codified nor contemplated in any r egulatory scheme envisioned under the CAA.

Commenters objected to use of natural gas co-firing and re-dispatch to new NGCCs as a supplement to the re-dispatch assumption. Commenter s stated the EPA should not adopt the suggestions advanced in the NODA to expand the defi nition of the NGCC fleet to include cofiring or new NGCC units in states' baselines (79 F R 64549-50).

Comment 2: Commenters agreed with NODA approach for minimum f loor of 12% on a regional basis.

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

this comment.

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

Commenters stated the block 2 & 3 goals are inequit able and require more of states that have already heavily invested in NGCC and RE, such as Te xas, while requiring relatively less from those states that have not, such as Kentucky. The c ommenters believed that due to the interconnected nature of electricity markets, EPA s hould reapportion the emissions reduction obligation, increasing the stringency of the goal f or states like Kentucky while reducing the stringency of the goal for states like Texas, which has significant under-utilized NGCC capacity. The commenters agreed with the approach in the NODA , establishing a minimum floor value for each state to achieve through Block 2 - regardless of a state's existing NGCC capacity - and reducing the burden by an equivalent amount for tho se states with higher amounts of NGCC capacity. The commenters believed that the minimum value of 12% suggested by EPA in the NODA appears reasonable and should be established o n a regional basis. The commenters stated that by basing the minimum floor on a regional basi s, states that have invested heavily in NGCC capacity can export power to states that have no or little NGCC capacity, an approach reflecting the interconnected nature of the electric grid.

Comment 3: Commenters expressed opposition to setting a floor for the Navajo Nation.

Response 3: See section V.D of the final rule preamble of the C PP for the EPA’s response to

this comment.

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

In comments on the Tribes and Territories supplemen tal proposal, commenters stated that the Navajo Nation opposes requiring a target or minimum level of transition to natural gas from coal even for jurisdictions with little or no NGCC capac ity because trying to apply a minimum472

transition to natural gas in an effort to achieve m ore of a "one size fits all" approach to BB2 ignores the costs and availability of fuels in a gi ven state and the necessary infrastructure to deliver it. For example, the commenters asserted Na vajo Nation coal is local to the mine and, at roughly $5/ton, costs only about $0.28/MMBtu. The c ommenters believed the suggested "one size fits all" approach ignores the recent investme nts that have been made in coal generation and would push more coal generation (and the associated investments) toward an uneconomic state
with stranded assets. The commenters added that the "one size fits all" approach ignores recent investments made in coal generation and would push more coal generation and associated investments, toward an uneconomic state with strand ed assets.

Comment 4: Commenters stated that the EPA should not adopt the "minimum level of generation shift" concept.

Response 4: See section V.D of the final rule preamble of the C PP for the EPA’s response to

this comment.

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

Commenters stated that because the Tribes and Terri tories Supplemental Proposal incorporates concepts introduced in the CPP, including its NODA, it is important to address the concept of "generation shift" within these comments in the con text of the EPA's acknowledgment that there are no NGCCs on the Navajo Nation. The commenters o pposed the use of a minimum level of NGCC generation, whether that is in the form of exi sting or new NGCC units as part of BB2. The commenters also opposed inclusion of co-firing natural gas as part of BB2 because of the
technical obstacles and cost considerations that co -firing would present for the FCPP. The
commenters stated these units can combust a small a mount of natural gas for startup operations and early flame stabilization, but the amount of he at input from natural gas combustion is limited to a small fraction of the total heat input to the units. The commenters asserted that achieving a
material reduction in carbon emissions from co-firi ng would require an enormous capital investment to modify the boilers and increase the n atural gas supply infrastructure. The commenters believed this effort not cost justified, especially considering the extremely small load demand in the Navajo Nation. The commenters st ated that the EPA should not expand the types of natural gas facilities in its determinatio n of BSER to include co-firing natural gas.

Comment 5: Commenters expressed opposition to setting a floor based on national averages, suggest establishing a floor on a state-by-state ba sis.

Response 5: See section V.D of the final rule preamble of the C PP for the EPA’s response to

this comment.

The following are summaries of the specific public comments under this comment:473

Commenters asserted that requiring states to meet a floor might create more equitable goals between those states that have little existing NGCC capacity and those with excess, but could result in even less flexibility for states. The com menters believed BB2 targets must consider each
state's individual circumstances and not be based o n a national average. If the EPA is determined to establish BB2 targets based on the national aver age, the commenters stated the EPA should hold the total level of gas use the same, thereby i ncreasing the BB2 requirement for states with little or no NGCC capacity and simultaneously reduc ing the requirement for states with excess capacity. The commenters believed this approach wou ld reduce the disparities between those states that have already invested significantly in NGCC and those that have not, giving credit to states for early action and resulting in more equit able treatment.

Commenters stated that EPA should limit the amount of anticipated NGCC redispatch under BB2 for New York (and similarly-situated states) du e to constraints that limit the ability of these states to implement BB2. The commenters suggested t he EPA establish a floor based on a percent of total in-state generation after the appl ication of BB2: for example, a collective floor of 12% coal and oil/gas steam units based on total gen eration, and then not apply the NGCC redispatch component of BB2 beyond that level.

The commenters stated the EPA could limit this prov ision to those states demonstrating that system constraints or reliability requirements prev ent them from achieving the level of redispatch initially anticipated by BB2. The commenters believ ed this approach would achieve the greatest level of dispatch realistically supported by existi ng fossil sources while allowing states the flexibility to meet reliability and gas/electric sy stem constraints, and maintain some amount of ongoing fuel diversity. Consistent with the NODA, a ccording the commenters, the reduction in redispatch from this adjustment could be made up by requiring a minimum level of dispatch from all states: for example, a state producing 15% of its generation from coal or oil/gas would have to redispatch one-third of that amount, reduci ng the amount generated by oil/gas or coal units to 12% of its total generation. Alternatively , the commenters suggested the EPA could limit the application of BB2 to New York in recognition o f the geographic and system topology constraints of NY's electricity system.

Comment 6: Commenters stated infrastructure concerns and quest ioned the definition of "region".

Response 6: See section V.D of the final rule preamble of the C PP for the EPA’s response to

this comment.

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

Commenters believed adopting a floor will increase pressure to add new generation in states that currently have no NGCCs and that if the EPA does ad opt a floor that it not be initiated until necessary infrastructure to interconnect and delive r new generation resources is in place. If the EPA decides to consider regional availability in th e establishment of BB2 targets, the commenters believed the definition of "region" shou ld be based on the boundaries of organized474

markets since this best matches how generation is d ispatched and how enabling transmission infrastructure is planned.

Comment 7: Commenters stated the starting point for the EPA's revised analysis of the CO2 effects of redispatch in 2020 should be no lower th an the historical maximum capacity factor for

NGCC.

Response 7: See section V.D of the final rule preamble of the CPP for the EPA’s response to

this comment.

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

Commenters stated that if the EPA finalizes target rates based on the phase in of BB2 redispatch over a number of years, as discussed in the NODA, t he Agency will need to determine the amount of NGCC capacity achievable by 2020. Comment ers recommended that the EPA select a maximum utilization/capacity factor that is no lowe r than the level that each state or region has achieved historically. Commenters specifically reco mmended that the EPA use the average of the highest monthly utilization/capacity factors ac hieved during the winter and summer seasons during the years 2011 through 2013 in calculating t he portion of the CO 2 emissions reductions targets achievable through BB2 redispatch. Commente rs stated this would reflect the times of greatest NGCC production during the multi-year peri od for which the EPA has real information, and would also take into account the differing avai lability of pipeline capacity during the winter
and summer seasons.

Comment 8: Commenters stated questions regarding goal recalcul ation.

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

this comment.

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

Commenters asked if the EPA will recalculate the ma ss goal for each state and communicate the result before the state plan deadline, if an NGCC f loor is established in the final rule. Commenters also asked if the number goal will be le ss than that included in the original proposal
if the RE/EE fossil offset is established in the fi nal rule.

Comment 9: Set natural gas ramp rate at 5% per year.

Response 9: See section V.D of the final rule preamble of the CPP for the EPA’s response to

this comment.

The following are summaries of the specific public comments under this comment:475

Commenters urged the EPA to consider natural gas ge neration increases (i.e., ramp rate) of 5% per year, the historical average over the last 10 y ears, when considering gas and electricity prices
in the evaluation of the total costs of the BSER ta rgets. Additionally, commenters stated that the ramp rate should reflect the needs for additional i nfrastructure to support increased gas use through the three respective pathways, which may be different for the different pathways.
Commenters added that it had assessed a more conser vative 2% per year ramp rate, and the modeling results indicated that a coal-to-gas shift at this level was highly cost effective, but the commenters did not have time to complete additional modeling at higher ramp rates. Nonetheless, commenters urged the EPA to consider h igher shift rates, up to and including a continuation of 5%, the 10-year historic rate.

Comment 10: Commenters suggested adoption of a minimum 2% annua l conversion rate for

Tribal Nations and U.S. Territories.

Response 10: See section V.D of the final rule preamble of the C PP for the EPA’s response to

this comment.

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

Regarding the Tribal and Territories Supplementary Rule, commenters urged that the EPA, in setting the targets for power plants in Indian Coun try and U.S. territories, apply the 2% annual conversion. This approach or some other approach th at incorporates the opportunity for switching to lower-emitting fuels and achieves equi valent or greater reductions is particularly important, according to the commenters, given that BB2 would not otherwise apply to these facilities given the lack of existing NGCC plants i n these jurisdictions. The commenters asserted lack of existing facilities within the jurisdiction does not reflect a reduced opportunity to switch to lower-emitting fuel sources.

Comment 11: Commenters expressed support and opposition to redi spatch approaches in the

NODA.

Response 11: See section V.D of the final rule preamble of the CPP for the EPA’s response to

this comment.

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

Commenters stated that there is significant opportu nity to reduce emissions from affected sources by shifting to natural gas generation in al l three ways noted by the EPA - shifting generation to existing NGCC units with additional c apacity, shifting generation to new NGCC units or by co-firing, and by repowering existing c oal-fired EGUs with natural gas. The commenters stated that incorporating the potential to improve emission performance from all three of these methods into the BSER is in keeping with the EPA's overall approach and would better reflect the actual system that states have u sed to achieve emission reductions.476

Commenters opposed the redispatch approaches in the NODA. Commenters opposed the redispatch approaches as well as the proposed alter native approach and co-firing as a consideration in lieu of, or addition to shifting f rom coal to natural gas. The commenters believed the approaches could make the goals less a chievable. The commenters asserted new resources are developed based on demand, cost and c urrent conditions, thus it is not possible for EPA to develop realistic assumptions regarding deve lopment of natural gas resources through 2030. Even if it were possible, the commenters stat ed it would be infeasible to apply on a uniform basis across states. The commenters appreci ated EPA attempting to create greater equity between states in terms of goals but believed intro ducing inherently arbitrary assumptions will create different inequities between states.

Commenters stated the BB2 alternative approaches in the NODA should not be applied in the final guidelines because these need to be better ju stified, details clarified, and outcomes analyzed and issued for public comment. In particular, the c ommenters believed requiring a minimum level of natural gas dispatch may not be technicall y supportable as the BSER.

Comment 12: Commenters noted negative impacts of co-firing.

Response 12: See section V.D of the final rule preamble of the C PP for the EPA’s response to

this comment.

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

Commenters stated that co-firing natural gas with c oal, as discussed in the NODA, would require significant investment, leading to higher cost of e lectricity. The commenters stated that contrary to the assumption used in the EPA's analysis that c oal-fired units run at full load and could benefit from co-firing, most units do not run at fu ll load. The commenters also stated that moving coal-fired or co-fired units away from baseload ope rations into more of an intermediate or load following mode will decrease any gains in power pla nt efficiency envisioned in Building Block 1. The commenters stated that ramping co-fired unit s up and down, in effect running them as peaking units, would most likely increase criteria pollutant emissions as well as CO 2 emissions.

Comment 13: Projected emission rates for gas-fired EGUs should be based on combined cycle

turbines.

Response 13: See section V.D of the final rule preamble of the C PP for the EPA’s response to

this comment.

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

Commenters supported the Agency's decision not to i nclude simple cycle units in calculating goals, as these are typically much smaller, operate for short periods to meet peak demand, and are unlikely to have much impact on industry-wide e mission rates from gas-fired EGUs. The commenters stated their own analysis found that onl y 18 of 583 gas-fired EGUs had heat rates477

that exceeded 250 MMBtu/hr and a 5-year average gro ss generation greater than 240,000 MWhr, which are the criteria EPA used to identify gas -fired units included in its proposal.

Comment 14: Any generation shifts in states with little or no N GCC capacity should be used to reduce the amount of re-dispatch required from stat es with higher amounts of NGCC capacity

Response 14: See section V.D of the final rule preamble of the C PP for the EPA’s response to

this comment.

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

Commenters stated that if the EPA expands BB2 to in clude some minimum level of generation shift from higher-emitting to lower emitting source s for all states containing some fossil steam generation, then it should take the path in which t he minimum generation shifts in states with little or no NGCC capacity should be used to reduce the amount of re-dispatch required from states with higher amounts of NGCC capacity. The co mmenters stated that the EPA's existing proposal already raises substantial concerns about infrastructure adequacy, reliability and stranded investments; therefore the commenters woul d not be in favor of an expansion of the total amount of re-dispatch required.

Comment 3: Commenters were concerned about the interplay betw een BB2 and the CPP's objective of encouraging re-dispatch from higher-em itting generating units to lower emitting generating units.

Response 3: The EPA has revised the approach to implementing BB 2 for the final rule and believes these changes respond to this comment. See Section V.D of the preamble, Chapter 3 of the GHG Mitigations Measures TSD, and the Goal Sett ing TSD for further details.

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

Under the CPP 111(d) proposal, commenters said, the amount of re-dispatch expected of states is limited by the makeup of the existing generating fl eet. Commenters said that although it would be feasible to construct new NGCC plants for commis sioning on or near the start of the compliance period, building block two only consider s re-dispatch to NGCC plants already in operation. Commenters noted that early acting state s that have already made substantial progress in phasing out oil and coal generation are faced wi th the potential economic burden of redispatching existing NGCC fleet investments, while states that have yet to make these investments may utilize the unconstrained dispatch to newly constructed NGCC units that are economic to build without any regulation. To addres s this inequity, where the re-dispatch is limited only by the lack of in-state NGCC capacity, commenters said that a minimum floor of redispatch should be attributed to the states to reco gnize likely cross state transfers of NGCC generated electricity to even out the compliance bu rden and more accurately and equitably set the goals as among regions and states.478

3.2.11 Glide Path

This section discusses issues related to the time l ine for implementation of the CPP and whether a more gradual glide path is needed for building bl ock 2.

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

Comment 1: Some commenters were concerned about the ability o f states to meet the proposed glide path time line, while other commenters said t hat additional time is not needed.

Response 1: The EPA thanks the commenters. The 111(d) final rul e requires that states develop plans that establish emission standards for affecte d EGUs. The rule provides states with substantial flexibility as to how they structure th ose plans to achieve the 111(d) requirements. The flexibility includes, for example, the choice o f approaches, trading, time to develop plans, additional time before the start of the interim per formance period (postponed from 2020 until 2022), and the ability to shift emission rate achie vement between performance periods. The Building Blocks are not prescriptive, and states ma y consider local circumstances as they develop their plans, including other regulatory req uirements and the “useful life” of assets. See sections V.D, VIII.A, VIII.C and VIII.G of the fina l rule preamble of the CPP and Chapter 3 of the GHG Mitigation Measures TSD for the CPP Final R ule supporting the final CPP.

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

Concerned That States May Not Be Able to Meet the P roposed Timeline to Comply with the
Interim Goals

Commenters expressed concerns regarding the ability of states to be able to meet the proposed timeline to comply with the interim emissions goals . Several of these comments are provided in the following paragraphs.

Commenters asserted that the proposal tries to do t oo much too fast. Commenters believed that state limits are too stringent and they offer a wid e and differing level of compliance for many different states. Additionally, the commenters comp lained that, as others have pointed out, the limits are front loaded, so you really have to actu ally achieve most of what is required by 2020,
not 2030.

Commenters asserted that additional time is needed to comply with the proposed rule and to allow utilities more flexibility in the near-term t o meet the initial targets, and to lower cost and other impacts on electric utility consumers. Accord ing to the commenters, while there may be a perceived glide path between 2020 and 2030, they ar e concerned that the proposed rule does not address the sharp drop in emissions that must be ac hieved prior to 2020. Commenters reported that, in Arkansas, a 37% decrease in CO2 emissions prior to 2020 must be achieved in order to479

maintain the average CO2 emission rate of 968 lb/MW h from 2020 through 2029 (estimate assumes that the current emission rate of 1,634 lb/ MWh does not change until 2020). Commenters reported that Arkansas's interim goal fo r 2020 through 2029 is 968 lb/MWh, and the final goal in 2030 is 910 lb/MWh. Commenters re ported that, in order to meet the interim goals and 2030 targets, the large majority of emiss ions reductions must be made prior to 2020. Commenters stated that, because utility forecasting and generation planning are long-term prospects, they will effectively have to comply wit h Building Blocks 1 and 2 prior to 2020, in order to achieve the interim goals.

Commenters argued that forcing the re-dispatch of N GCC to significantly higher capacity factors within two to three years will severely strain the natural gas supply and delivery system, resulting in significant price volatility and highe r electricity costs to the consumer. According to the commenters, during the recent polar vortex, nat ural gas demand exceeded delivery capacity demonstrating a current need. Commenters opined tha t permitting and construction of additional infrastructure would take more than two or three ye ars to complete. According to the commenters, NERC states in its November 2014 initia l reliability review that it take[s] three to five years to plan, permit, sign contract capacity, finance, and build additional pipeline capacity and that the Proposed Rule timelines would provide little time to add required pipeline or related resource capacity by 2020.

Commenters asserted that, without significant chang es to the proposal, state plans that comply with it would be all too likely to put reliability at risk by stranding essential assets, increase power prices dramatically, and cause a stampede of new base-load natural-gas fired generation. Commenters opined that this wave of new base-load g as generation would lock-in levels of new fossil fuel emissions in the US power sector that w ould make getting on the IPCC pathways to a world with no more than two degree centigrade warmi ng much more difficult, if not impossible.

Commenters argued that the proposed interim goal el iminates compliance flexibility and that the EPA requires 11 states meet more than 75 percent of their final target by 2020, granting states at most 2 years or as little as 6 months to achieve co mpliance. Commenters opined that states will have no choice but to make dramatic changes in gene ration resource dispatch to achieve near or full compliance with the interim goals by 2020. Mor eover, according to commenters, the constricted timeline will prevent states from cushi oning economic impacts from retirements.

According to commenters, the EPA has overestimated the ability of states to achieve re-dispatch, and the EPA has proposed interim emissions goals th at are so stringent that many states will be required to achieve most of their CO2 emissions red uctions by 2020. According to commenters, given the EPA's proposed timetable for the approval of state plans, this would leave states at most with approximately 2 years to implement the ne cessary CO2 reduction measures; a task that they asserted will be extremely difficult or imposs ible to achieve without severe economic disruption. Commenters explained that, to determine the interim goal for each state, the EPA
assumed that all emission rate reductions from Buil ding Block 1 and Building Block 2 could be achieved at the start of the ten year interim goal compliance period. As a consequence of this assumption, commenters stated that, for many states , almost all of the emission rate reductions that the proposed rule ultimately requires must be achieved in the first year of the ten-year interim goal compliance period.480

Commenters further reported that, states with emiss ion levels that are above their interim goals in the first part of the compliance period will not be able to achieve reductions sufficient to offset those emissions later in the compliance period. Acc ording to commenters, this is evident from the calculations presented in the EPA's technical s upport documents, which project that many states will make dramatic changes in generation res ource dispatch to achieve near or full compliance with the interim goals in 2020. Commente rs reported that resulting emission rate reduction trajectory resembles a cliff, whereby emi ssions decrease sharply early in the compliance period and then remain largely unchanged through 2030.

Commenters argued that states are left with little or no flexibility to determine a different compliance path to avoid the compliance cliff under EPA's proposed schedule for implementing the Proposed Rule. Commenters stated that the EPA i ntends to finalize the proposed rule in 2015, which means that the earliest state implement ation plans would be approved by EPA is 2017. At most, commenters asserted, this schedule l eaves 2 years for electric generating companies to achieve aggressive emission reductions and for states to make sweeping changes to their existing electric generation, transmission, a nd distribution systems. Given the stringency of the interim goals, commenters reported that the pro posed implementation schedule will force states to adhere to the EPA's anticipated re-dispat ch and coal and oil/gas-unit closures to achieve compliance with the goals.

Commenters asserted that the interim goals are larg ely unachievable in their current state for many jurisdictions. Commenters stated that, this is in no small part because it requires most of
the emissions reductions to occur in 2020 via the n atural gas re-dispatch in Building Block 2.

Commenters asserted that, whether the electric syst em as a whole can operate with most states' NGCC fleets averaging 70 percent by the early part of the compliance period (as implied by the goal computation) is uncertain. According to the co mmenters, while many states would be able to rapidly increase the utilization of existing NGC C facilities, others may require additional time because of infrastructure constraints, characterist ics of existing in-state generation facilities, or
because of their load centers' locations in the ele ctric or gas transmission system. Commenters stated that procuring adequate natural gas supplies to sustain a high level of utilization year round could mean, in the case of some states, build ing new pipelines or increasing the capacity of existing ones. For others, the commenters stated that getting the electricity to consumers currently served by steam units without expanding t ransmission may be a challenge. Thus, although the commenters agreed with EPA's conclusio n that, over time, existing fleets will have the technical capability of reaching a 70 percent c apacity factor, and agreed with EPA's finding that states could comply with the emission guidelin es without increasing NGCC utilization to 70 percent, they also agreed with stakeholders who are recommending to EPA that changes be made to the rate at which Building Block 2 is deployed a s part of the goal-setting process.

Commenters opined that the timeline between final s tate plan approval (which, for many states, may not occur until mid-2018 or later) and 2020 is far too short for states to implement significant action to encourage implementation of e arly emission-reducing measures that would counteract the EPA's stringent interim goal require ments. Commenters reported that full redispatch by 2020 would be unachievable and bad publ ic policy. Commenters stated that the EPA claims that its intent in proposing to require comp liance with an interim goal is to "provide states with a reasonable glide path to compliance with the ir final goals by 2030." However, according481

to commenters, EPA fails to explain why interim goa ls are necessary to achieve the Proposed Guidelines' ultimate goal. Commenters stated that, although they do not believe EPA's suggested approaches will significantly alleviate the negativ e consequences of EPA's proposed interim goals, they urged that, if EPA does not abandon int erim goals, the EPA adopt both of these changes in the final guidelines.

Commenters stated that, as proposed, significant ca rbon reductions - 80% of final compliance requirement -- will be needed by 2020 in order to m eet the 2020/2029 interim goals. Commenters argued that front loading of reductions by 2020 is particularly problematic because of the short time frame between approval of state p lans (2017 at earliest, 2019 for regional plans) and 2020 (start of interim goal averaging period), as well as failing to give utilities and states adequate time to implement prudent compliance strat egies that ensure reliability. In particular the commenters expressed concerned that the drastic act ion required to meet the 2020 interim targets will lead to a major upheaval in the industry and t he potential for blackouts.

Commenters stated that, while the idea of a "glide path" to the final requirements of the year 2030 appears appealing, it would not work. In addit ion to the glide path requiring a sharp decrease in emissions in the year 2020 or over-comp liance in the latter years of the period, the commenters believed that the glide path proposed by the EPA would prematurely and unnecessarily cause an increase in costs borne by t heir (Minnkota's) member-owners by shifting generation away from coal-fired plants to more expe nsive lower emitting carbon dioxide sources prematurely.

Commenters asserted that "overnight." large scale r e-dispatch raises a number of daunting problems in the real world, which they believed wer e inadequately addressed in EPA's analyses. Commenters opined that, in states with a large numb er of existing combined cycle units and existing coal plants, such a sudden major re-dispat ch has the potential to create resource adequacy challenges by stranding assets needed for reliability, increasing consumer costs, and, in all likelihood, leading to unnecessarily large amou nts of new natural gas power plant investment and the long term lock-in of their CO2 emissions. C ommenters argued that the sudden retirement of most or all coal plants in a state where they ma ke up one-third of the supply stack clearly will threaten resource adequacy (unless the state enjoys a 33 percent or greater reserve margin) and risk a major resource adequacy crisis in states wit h much smaller reserve margins. According to the commenters, such a crisis would almost certainl y be met by deployment of new natural gas plants - whose dispatchable capacity counts toward reserve requirements and whose CO2 emissions simply don't count under the proposed rul e.

Commenters argued that, requiring that all changes in dispatch be achieved before the interim compliance period begins eliminates any flexibility states have to determine how quickly to make these changes or to assess and address the imp lications for the interconnected power system. Commenters also asserted that it also refle cts the fact that the proposed guidelines do not acknowledge or consider how the interconnected powe r system works. For example, commenters stated that the Director of the Arizona DEQ has not ed that, "the proposed goals for Arizona were set based upon an EPA assumption that all of our ex isting coal-fired power generation could be immediately transferred to existing natural gas-fir ed power plants by 2020." Commenters reported that Arizona is required to achieve at lea st 75 percent of its final 2030 goal by 2020. According to commenters, the DEQ reported that Ariz ona's only option to achieve this level of482

reductions by 2020 is through switching from coal t o natural gas. Commenters reported that, even if Arizona has an approved state plan by 2017, this is an unprecedented reductions requirement that must be achieved in, at most, a fe w short years.

Commenters expressed concern that states will have limited flexibility to tailor their implementation plans in ways that (A) make practica l and economic sense for each state's circumstances and (B) ensure on-going system reliab ility. MLIG understands that implementation of the Clean Power Plan could have s ignificant impacts on Minnesota utility resource planning processes. Commenters stated that energy-intensive trade-exposed industries that their members operate in are not only vulnerab le to electricity price increases, but also price volatility. Commenters opined that allowing states more flexibility to establish their own glide paths would allow for more efficient planning and p rovide the ability to take advantage of more cost-effective options that may arise in the 2020-2 029 timeframe. Commenters further expressed serious concerns about reliability issues that coul d be caused by the proposed 2020-2029 interim emission performance period. Commenters reported th at, on November 25, 2014, they had submitted a comment letter to EPA arguing that appl ication of the interim compliance period "will negatively impact reliability and resource ad equacy in the MISO region starting in 2020." States need flexibility to resolve such potential t ensions between meeting Clean Power Plan targets and complying with reliability safeguards. Commenters opined that the Clean Power Plan has a greater chance of success if it can be implem ented in a way that accounts for other critical energy consumer needs such as affordability and rel iability.

Commenters stated that the EPA assumes that the re- dispatching from existing coal-fired EGUs to NGCC EGUs under Block 2 can happen by 2020. Howe ver, according to commenters, the EPA does not consider that legislative changes, and in particular, ERCOT market changes that would be necessary to effect such a re-dispatching change. According to commenters, the shift in generation assumed by the EPA for Texas' NGCC units is the largest of all states, approximately
19% of the total MWh increase assumed for the entir e United States NGCC fleet. In fact, according to commenters, the net increase in genera tion at Texas' NGCC units assumed by the EPA, approximately 83 million MWh, is greater than the total NGCC generation in every other state except for Florida. Yet, commenters reported that the EPA assumes that Texas can effect such a change in less than four years. Commenters r eported that the EPA assumes that the states can force such a shift by imposing a cap-and-trade program such as Regional Greenhouse Gas Initiative (RGGI) or otherwise exercise its permitt ing authority to restrict operation of units. However, commenters asserted that the EPA's arbitra ry assumption is flawed. Commenters stated that neither the TCEQ nor the EPA has the le gal authority to call the permits for the affected units to implement such a change through p ermitting actions. In citing RGGI as an example of how states might cause such a change, co mmenters asserted that the EPA fails to acknowledge the significant amount of time required to implement RGGI. According to the RGGI program design history webpage, commenters rep orted that discussions to create the program began in 2003. RGGI was reported by comment ers to be first established in 2005 and includes two control periods, spanning from 2009 to 2014. According to commenters, from the initial concept to the final phase, the RGGI progra m encompasses more than ten years.

Furthermore, commenters asserted that, while the EP A might argue that they are not requiring the re-dispatching to be implemented by 2020, the E PA has incorporated this assumption into the calculation of the interim goals. Commenters assert ed that the effect of the EPA's assumption is483

that the interim goal for Texas is substantially re duced which forces the state to make significant reductions prior to the start of the 2020 - 2029 in terim period. Commenters reported that approximately 60% of Texas' required reductions on a lb/MWh bases are derived from Block 2 and the majority of reductions for Texas will be re quired to be made by 2020. Commenters stated that, given the legislative, regulatory, and implementation factors, it is not possible for Texas to implement such a drastic shift in energy p olicy in the time period assumed by the EPA.

Commenters asserted 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 Arizona receives clarity on the state t arget and even less time from when Arizona's state plan actually gains approval. According to th e commenters, since Arizona has no natural gas storage and only two major natural gas pipeline s, this radically compressed timeline leaves Arizona virtually no time for proper economic, safe ty, and reliability based preparation.

Commenters noted that, in Arizona, the application of Building Block 2 makes a disproportionate contribution to the overall requir ed CO2 reductions. According to the commenters, this result would essentially require A rizona to choose re-dispatch over other

measures.

Commenters opined that the time frame the proposed regulation would provide from its predicted finalization in June 2015 to implementati on of the "glide path" in 2020 is far too small for the necessary:

1. State outreach to stakeholders;

2. State outreach to other states for exploration of a nd negotiation of any potential multistate or regional plan;

3. Meeting any requisites for proposing legislation th at may exist under state law;

4. Adoption of enabling state legislation;

5. Adoption of state regulations implementing state le gislation;

6. Development of a state (or regional) section 111(d) plan;

7. Obtain Congressional approval of a multistate compa ct, as required by the Compact Clause of the Constitution, for an enforceable mult i-state plan.

8. Approval of fifty or more state section 111(d) plan s by EPA, which is already well behind in approving state SIPs under CAA section 11 0;

9. Commitment of capital by the electric generation in dustry and others that would be regulated by the proposed rule to fund the work tha t will be necessary to achieve its mandates;

10. Commitment of capital for new electric transmission lines and gas pipelines;

11. Acquisition of property rights for construction or other work that may be necessary;484

12. Regulatory approvals and permits from FERC, utility commissions, environmental regulators and others, including any required revie ws under the National Environmental Policy Act, the Endangered Species Ac t, and the National Historic Preservation Act;

13. Completion of construction or other work to enable compliance that can only begin after regulatory approvals are obtained; and

14. Trouble-shooting and adjustment of new equipment, s ystems or devices to assure performance as intended.

According to commenters, the fact that each of thes e steps is necessary to implement a plan to fundamentally restructure the way in which the U.S. meets its energy needs will make accomplishing them more difficult than would otherw ise be the case.

Commenters stated that the original proposed rule c ontains a requirement for a phased reduction (glide path) from 2020 to 2029 that is problematic for a number of reasons. According to commenters, while recognizing that there are signif icant differences between states, and that states should have flexibility to design their own rules to achieve the ultimate CO2 goals by 2029, the proposed "glide-path" practically elimina ted any flexibility that EPA claimed was in the proposed rule. More recently, commenters stated that, in the NODA, the EPA has noted the problems with the strict phase-in targets and has e xpressed an interest in additional ideas regarding the "glide path" to ensure that the overa ll framework of its rules includes sufficient flexibility. Commenters agreed that the originally proposed "glide-path" is a substantial, intractable problem. Commenters did not agree that allowing a credit for early excess CO 2 emission reductions or a phase-in of Building Block 2 corrects the issues.

Commenters opined that, instead of providing a smoo th "glide path" from the current situation toward meeting EPA's final goals for the state, EPA 's interim goals are actually more stringent than its final goals and would require immediate, d isruptive, sharp reductions, 47 percent of West Virginia's final goal, before the 2020 to 2029 "glide path" even begins. Commenters opined that the interim goals effectively remove all flexi bility and limit the opportunity section 111(d) provides to take advantage of the remaining asset v alue of coal-fired generation. According to commenters, this problem is not limited to states f or which Building Block 2 results in large amounts of CO2 reduction. Commenters reported that their state's (West Virginia) coal-fired EGUs with remaining useful life have already instal led controls and undertaken work practices to meet the ARP, CAIR, CSAPR, and MATS. Commenters reported that compliance has come at a high capital cost, which can only be recovered if the units are allowed to operate at reasonable levels. According to commenters, in order for West Virginia to achieve the interim goal as EPA has outlined in the proposal, existing coal-fired E GUs would be have to achieve a six percent reduction in CO2 emissions due to heat rate improve ments; an 89 percent increase (an additional 1,154,643 MWh) in non-hydro RE generation from 2012 levels; and an 885 percent increase (from 0.18 percent to 1.77 percent cumulative annua l savings) in avoided generation due to EE measures over 2012 levels by 2020 which they report ed is not possible.

Commenters asserted that the EPA's presumption that Building Block 2 can be implemented by 2020 is unrealistic. Commenters stated that, if EPA chooses to retain the interim goals and485

allows states to phase in Building Block 2, the tim e needed to shift from higher-emitting to lower-emitting generating units must definitely be provided for in the final rule. Building any combustion turbine NGCC capacity for new natural ga s generation needed to comply with the rule, according to the commenters, will require at least five to seven years. The commenters stated that it is impossible for this capacity to b e operational by 2020, given that it is very unlikely the state will have an approvable plan pri or to 2019. Finally, the commenters reported that EGU outages for equipment installations have t o be coordinated by the independent system operators (ISOs). Commenters argued that this plann ing and approval process, along with any necessary permitting, cannot occur by 2020.

Commenters reported that, between 2012 and 2016, Ge orgia is retiring over 3000 MW of coalfired capacity. In January 2016, commenters reporte d that there will be 9400 MW of capacity remaining in its coal-fired fleet. According to com menters, selective catalytic reduction (SCR) controls and flue gas desulfurization (FGD) control s will be installed on 95% of the remaining coal-fired generation capacity. Commenters reported that installation dates of these controls will range from 2001 to 2014. Assuming a 40-year book li fe for this equipment, commenters reported that the book life retirement dates will range from 2041 to 2054. Commenters asserted that these control systems should be viable assets for at leas t 21 years past 2020, the year that the EPA has assumed re-dispatch to NGCC to be completed.

Commenters asserted that the EPA's proposed target schedule for Georgia is asking too much, too soon. Commenters reported that the Georgia's re -dispatch from coal unit to NGCC makes u
30 % of the overall reduction in their emission rat e reduction from 2012-2030 and is targeted by EPA for implementation by 2020. Commenters opined t hat re-dispatch away from coal-fired generation will result in a significant quantity of stranded viable assets. For example, accordig to EPA's modeling, commenters stated that Plant Schere r Units 1 and 2 will be retired by 2020 after recently installing nearly $500 million in air poll ution control equipment. Commenters reported that these units are partially owned (30%) by Georg ia municipal utilities and (60%) Georgia's EMCs. The premature retirement of these units, acco rding to commenters, will leave small municipal utilities, and the Georgia citizens serve d by these utilities, with financial obligations for the installation of the air pollution control e quipment extending for the next forty years without any benefit of electricity generation.

Commenters stated that, although EPA has determined that, on an average basis, many states have significant excess capacity at existing natura l gas plants, this may not necessarily mean all of this capacity is available to displace coal-fire d electricity on a year-round basis. Commenters expressed that some states may have strong seasonal variations in demand for natural gas electricity, for example to accommodate high air co nditioning demand during the summer in the Southwest. Commenters further expressed that other states may not have the natural gas pipeline capacity to allow power plants to run at 70 percent capacity in months when demand is high for gas as a heating fuel. Commenters stated that these concerns are surmountable with new or upgraded infrastructure, but this will take time to deploy and that Building Block 2 should be shaped in a way that accounts for this time.

Commenters stated that the existing transmission ne twork in Arizona 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 pe riphery of the State. Commenters486

complained that significant modifications and addit ions to the transmission network would be required to account for shutdown of the coal-fired EGUs and still provide reliable electricity.

Commenters reported that, at the earliest the Kentu cky SIP would be approved by EPA in June of 2017. According to the commenters, for an interi m reduction compliance date of January 1, 2020, OMU would need to take immediate action to fi nd an acceptable site for construction of natural gas generation. Commenters stated, at a min imum, that process would take 6-12 months. Commenters further stated that permitting a new nat ural gas EGU would take a minimum of 18 months after engineering is completed to the level necessary to support the air permit application, and Large Generator Interconnect Agree ments (LGIA) and associated required studies pursuant the LGE/KU Open Access Transmissio n Tariff would take a minimum of 12
months after the definitive site is identified and engineering was completed. Commenters reported that the LGIA process is further complicat ed because to the extent LGE/KU has additional LGIA requests in queue, OMU and any othe r applicant must wait until their project reaches the number one queue position before the OA TT prescribed time clock begins. Commenters also reported that construction of requi red interconnection infrastructure will take at least 24 months with complications likely due to ri ght-of-way acquisition for transmission facilities and natural gas pipelines. According to the commenters, with a minimum construction period of 24 months depending upon start date, the retirement of an ESGS unit in 2020 would expose OMU ratepayers to market prices for a minimu m of two years before a replacement natural gas fired generating facility comes online. Commenters suggested that EPA should at a minimum permit a compliance timeline based upon the assessment made by the Kentucky Division of Air Quality working with the affected E GUs that recognizes both the reality of the time required to complete the steps necessary to re place existing generation with lower emitting natural gas generation and to reflect the useful li fe of existing EGUs.

Commenters stated that the EPA glide path for Build ing Block 2 inherently assumes that redispatch can be achieved seamlessly by 2020; it ent irely fails to account for the fact that NGCC is used as reactive power to back up the intermitte nt renewables, such as wind. According to the commenters, if those current units are re-dispatche d as base load, new natural gas-fired units would have to be constructed for the purpose of pro viding reliability for the renewable energy already on the ground. The commenters asserted that the inability to re-dispatch means that Building Block 2 "where EPA assumes over 30% of red uctions can be made" is not available to MRES, nor is it even remotely possible in many stat es. Instead, the commenters suggested that the EPA acknowledge that the states alone are in th e best position to determine when and how reductions can be made under this building block du ring the interim glide path period.

Finally, the commenters stated that, in the upper M idwest, where the MRES load is centered, there are already constraints in natural gas capaci ty. Commenters reported that the Northern Natural Gas, one of the leading suppliers of natura l gas in the upper Midwest, faced constraints and limited capacity during the "polar vortex" of 2 014 and that it may require new natural gas infrastructure just to provide additional supply to existing NGCC plants that EPA anticipates running at a higher capacity factor, not to mention what will be required for the construction of new facilities. Commenters further reported that ne w natural gas lines would also face the need of ample time frames to be permitted and constructe d. Commenters stated that public notice, permitting, and construction will take years, not m onths. Commenters further stated that there will also be added delays if the lines are opposed, if there are environmental impact issues, or if487

there are eminent domain complications. Commenters asserted that, before the publication of this proposed rule, the MISO region already had 3.7 GW o f announced coal retirements and 5.0 GW of new gas plants announced in the region. Accordin g to the commenters, in order to interconnect the MISO-forecasted NGCCs and simple c ycle turbines, the lateral natural gas pipeline construction will cost between $870 millio n to $1.08 billion. Commenters stated that this is for the construction of lateral lines only and not including any mainline costs. Commenters opined that the rules before us would lead to even more natural gas-fired generation than the predicted 830 MW; again, adding to the complexity a nd the time for planning, permitting and constructing sufficient natural gas construction in the upper Midwest alone. Commenters stated that, as the MISO natural gas infrastructure analys is concluded, there must be consideration for the lead-time required for pipeline construction to meet the need of power generators by 2015/2016 and the potential for construction delays due to the anticipated increase in power generation interconnection request. Lastly, the com menters asserted that the decision-makers must recognize the competing needs for pipeline con struction as industrials and other reshoring industries ramp-up. Commenters opined that this wil l affect the availability of skilled labor and materials and will most likely increase costs for t hose that postpone decision-making. Commenters asserted that the electric power industr y must determine its own level of redundancy and reliability requirements and the mea ns to recover costs associated with the value of reliability under its economic models. Simply pu t, according to the commenters, the anticipated substantial increase in natural gas rel iance and additional natural gas capacity needed makes the glide path milestones difficult, at best, to reach in the allotted time.

In summary, commenters argued that the glide path w ould require Minnesota to achieve 84 percent of its total mandated reductions by January 1, 2020 (moving from a 2012 historical emission rate of 1,470 lb. CO2/MWh to 965 lb. CO2/M Wh), a huge feat in such a short time. Likewise, Iowa would need to achieve 61 perc ent of its total mandated reductions by 2020, North Dakota 67 percent, South Dakota 67 percent an d Wyoming 53 percent. This, according to the commenters, would require substantial changes i n the entire electric industry in the matter of less than four years, which the commenters stated i s not achievable given the limitations of natural gas capacity, renewable energy intermittenc y, the need for more transmission, and the lack of planning and permitting time for new renewa bles, new pipelines or transmission, for natural gas ramp-ups at existing plants (if feasibl e), or for new natural gas plants.

States Can Comply With Interim and Final Standards

A few commenters believed that the interim and fina l standards compliance timeline can be met.

Commenters stated that Missouri can achieve all its needed reductions through alreadyannounced coal plant closures and through complianc e with state policies already in place.

Commenters asserted that states have many alternati ves to comply with the interim and final standards if re-dispatch would result in temporary reliability issues. Commenters noted that it should be emphasized that the building blocks are u sed to calculate what a state could do to cut emissions, not what it must do. Therefore, accordin g to the commenters, if local reliability genuinely prevents re-dispatch of coal to gas, as s ome claim, there are other options. Commenters stated that other options are being depl oyed by Western states and utilities, and are already leading to significant emission reductions. According to the commenters, states could:488 • deploy more renewable energy and energy efficiency measures in the years preceding 2020 and during the performance period;

• upgrade the local grid with advanced transmission t echnologies to expand capacity and maintain reliability; and

• implement demand-side management at the regional le vel.

According to the commenters, if a state is unable t o meet the state's annual targets in the early years due to operational constraints, it could stil l meet the interim and final standards by exceeding annual state targets in the latter years of the performance period. Finally, the commenters stated that it is important to keep in m ind that EPA did not set its standards based on
the maximum achievable reduction from each block. T he commenters expressed that this provides states with flexibility to use the blocks in amounts different than EPA assumed in setting the state targets.

Comment 2: Some commenters supported a phase-in period for re -dispatch while others said that the proposed NODA approach would not work or w ould result in excess GHG emissions.

Response 2: The EPA thanks the commenters. The 111(d) final rul e requires that states develop plans that establish emission standards for affecte d EGUs. The rule provides states with substantial flexibility as to how they structure th ose plans to achieve the 111(d) requirements. The flexibility includes, for example, the choice o f approaches, trading, time to develop plans, additional time before the start of the interim per formance period (postponed from 2020 until 2022), and the ability to shift emission rate achie vement between performance periods. The Building Blocks are not prescriptive, and states ma y consider local circumstances as they develop their plans, including other regulatory req uirements and the “useful life” of assets. See sections V.D, VIII.A, VIII.C and VIII.G of the fina l rule preamble of the CPP and Chapter 3 of the GHG Mitigation Measures TSD for the CPP Final R ule supporting the final CPP.

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

Support Phase-In of Re-Dispatch

Several commenters supported a phase-in of re-dispa tch under Building Block 2 rather than requiring re-dispatch be fully implemented by 2020. Several of these comments are provided in the following paragraphs.

Commenters requested that states be allowed to use all years up to 2030 rather than the first two to three years to achieve the bulk of its carbon in tensity goals would allow a more reasonable schedule for infrastructure expansion, thereby avoi ding significant cost increases to rate payers.

Commenters requested that EPA mitigate negative eff ects by setting more reasonable goals for
each state that are based on the emission reduction s that are truly achievable for each state. In489

addition, the commenters stated that a gradual phas e-in for re-dispatch would be in line with EPA's approach to the RE and EE components of state goals, both of which assume that states will gradually phase in reductions from these measu res.

Commenters opined that a more measured phase-in sch edule would provide time for infrastructure improvements that would be required to ensure grid reliability. Commenters requested that any improvements to Building Block 2 and the interim period take into account the remaining useful life of affected electric gene rating units.

Commenters stated that a more gradual phase-in of B uilding Block 2 over time would avoid threats to generation source reliability and would allow a more thoughtful transition to increasingly competitive renewables and other clean energy resources, less emergency-inspired new gas plants, and lower CO2 emissions from the po wer sector as a whole at a lower cost.

Commenters urged EPA to phase-in the re-dispatch co mponent of Building Block 2. Commenters stated that a substantially longer runwa y for states to make this coal-to-natural gas transition and include a phased approach to re-disp atch is needed. Commenters stated that it is needed because the interim average target is so clo se to the end 2030 target and it leaves little room for flexibility let alone enough time to site needed upgrades.

Commenters recommended that the EPA adjust the Buil ding Block approach to exclude remaining useful life units from the re-dispatch ca lculation (discussed in another comment summary in this section) and phase in the applicati on of Building Block 2 evenly over the 2020 to 2030 time period, similar to the application of Building Blocks 3 and 4. Commenters stated that additional timing will enable more cost effect ive decision making and reduce the cost and reliability impacts associated with stranded coal i nvestments and simply defaulting to natural gas for compliance.

Commenters recommended that the EPA phase in the ta rget for re-dispatch to NGCC over a longer duration to allow for continued, cost-effect ive operation of existing fossil-fired generation

sources.

Commenters stated that, if the EPA does not phase-i n re-dispatch, there would be the required shutdown of many coal-fired units that "have recent ly been constructed" or "have received significant capital investment (e.g., in the form o f pollution control retrofits)."

Commenters expressed concern with the assumption th at the full re-dispatch of NGCC units according to Building Block 2 is feasible on "day o ne" and agrees with phasing in of these targets over time.

Commenters believed that, while existing NGCC plant s are capable of operating at higher capacity factors, they acknowledged the need for a reasonable phase-in to accommodate
infrastructure and economic realities. Commenters a lso recognized the need to balance this redispatch with the concern for an economic transitio n that includes capital recovery for the existing fleet of coal generation, especially in li ght of the significant recent investments coal plants have made to comply with other recent EPA ru lemakings. Therefore, although the commenters believed that the existing fleet is tech nically capable of achieving this capacity factor today, they also believed that an extended p hase-in period for Building Block 2490

requirements would better allow for necessary infra structure improvements and economic
considerations.

Commenters argued that, if the interim goals remain in the EPA's final guidelines, they supported the phase-in of emissions under Building Block 2.

Commenters requested the "front loaded" problem be addressed by building in phase-in periods for the implementation of the NGCC re-dispatch call ed for under Building Block 2, while providing a mechanism for utilities to get credit f or early action, such as purchase of Rio Nogales
in 2012.

Commenters preferred that the EPA phase-in Building Block 2 to allow for a more gradual glide path instead of the current cliff facing their stat e (Arkansas). Commenters asserted that the electric grid is a complex machine and the implemen tation of Building Block 2 represents a major change in operations and that such a change w ill not be quick or easy.

Similarly, commenters stated that, if EPA chooses t o retain the interim goals and allow states to phase-in Building Block 2 over the 10-year complian ce period, a phase-in schedule should consider additional necessary infrastructure improv ements, due to existing natural gas supply constraints and ensuring a reliable fuel supply. Ac cording to the commenters, the EPA should also consider the time required to integrate any tr ansmission enhancements needed to address impacts to reliability from the proposed rule, as i ndicated by Midcontinent Independent Systems Operator (MISO) and North American Electric Reliabi lity Corporation. Commenters indicated that new transmission may be necessary to support n ew resources in order to comply with the rule and that the transmission planning process and construction could take between 6 and 10

years.

Commenters agreed that many NGCC facilities have th e technical capability to operate at an annual average capacity factor up to 70%. However, according to the commenters, other factors limit the ability of NGCCs to increase their curren t annual average capacity factor. To ensure existing NGCCs can provide up to 70% capacity facto rs, the commenters reported that many states/regions would need to address natural gas de livery and/or transmission constraints. Commenters recognized that strict implementation of the goals is not required for compliance; however, other options (plant retirements and/or ne w construction) will not be available early in the interim period for the very same reasons. There fore, the commenters recommended that EPA provide a glide path that allows for these reductio n opportunities to occur evenly throughout the interim compliance period. Commenters reported that projects to address natural gas delivery and transmission constraints take time to implement , and stated that two prime examples have occurred in New Jersey:

1. BL England Closure/Repowering

According to commenters, BL England entered into a consent order with the New Jersey Department of Environmental Protection ("NJDEP") in 2006, which required BL England either to meet NJ's standards for coal-fired EGUs or repow er the facility to natural gas (NGCC).
Commenters stated that the order was amended in 201 2 to require the facility to either cease operations or repower the facility. Unit 1, a coal- fired EGU, was shutdown in 2013. Unit 2 (coal-491

fired EGU), according to the commenters, was origin ally scheduled to shutdown in 2015 and the owner planned to complete construction of a new NGC C unit in 2016. However, the commenters stated that Units 2 and 3 (oil-fired EGU) remain in operation. Commenters reported that a natural gas pipeline through the Pinelands must be built to deliver natural gas to facility, and that the Pinelands Commission rejected the pipeline project in January 2014.

Subsequently, the commenters reported that the plan t owner submitted a generation deactivation request to PJM for Units 2 and 3; however, the requ est was withdrawn because PJM identified reliability issues. The PJM Reliability study, acco rding to the commenters, stated that the closure of Units 2 and 3 would require significant transmis sion upgrades that may take several years to complete. PJM indicated that brownouts and/or black outs may occur during periods of peak demand. Hence, the commenters reported that the NJD EP extended the retirement requirement
for Unit 2 to mid-2017. Commenters stated that the amended consent order allows for an extension beyond 2017 if the New Jersey Board of Pu blic Utilities ("NJBPU") or PJM determine that additional time is necessary to avoid reliabil ity issues. The commenters further reported that the potential closure/repowering of this facility h as been studied and debated for at least 8 years and is expected to continue for several more years to reach a conclusion.

2. Susquehanna-Roseland Project ("Project")

Commenters stated that, in 2007, PJM approved the P roject for inclusion in its Regional Transmission Expansion Plan ("RTEP") as a necessary baseline project to address reliability issues in the constrained northern New Jersey area. Commenters reported that the Project
consists of a new 500 kV transmission line that wil l run from Susquehanna, PA to Roseland, NJ. PSE&G is responsible for constructing the New Jerse y portion of the Project. Commenters further reported that the Project required approval s for the following: Board of Public Utilities,
Freshwater Wetlands Permits/Flood Hazard Area Permi ts, National Park Service (NPS), Picatinny Arsenal, and required land use agreements . The original in-service date was scheduled for 2012; however, according to the commenters, com mencement of construction was delayed by three years due to the NPS Environmental Impact Stu dy. In total, the commenters reported that the Project will have taken eight years from PJM ap proval to complete.

Commenters opined that these two examples show that ample time is needed to address all potential obstacles relating to re-dispatch and tha t the 2020 cliff that the proposed rule would impose may not be practical. NERC also expressed it s concern regarding the need for more time to address transmission and delivery enhancements t hat are required to achieve the necessary reductions in the CPP. Commenters concluded that, g iven the significant delays states may face in planning for increased use of NGCC units, EPA mu st allow for a gradual phase in of Building
Block 2.

Commenters asserted that, as a preliminary matter, phasing in reductions under Building Block 2, similar to the phase-in of reductions under Buil ding Blocks 3 and 4, could address some of the near-term compliance challenges discussed in these comments for some states. In general, commenters stated that phasing in these reductions is more reasonable than assuming that all changes in dispatch between coal- and gas-based gen eration occurs before 2020. As EPA recognizes in establishing the Building Block 3 and 4 goals, commenters believed that it is appropriate to give states and electric utilities s ufficient time to make system changes or create492

new programs. Commenters opined that a phase-in of Building Block 2 reductions could allow for the necessary expansion of natural gas infrastr ucture to support increased utilization of existing NGCC units and could provide competitive m arkets time to review and adjust market rules, if needed.

Commenters stated that the EPA should revise the Pr oposed Rule so that the phase-in period for Building Block 2 roughly mirrors the EPA's more gra dual approach to implementing Building Blocks 3 and 4. Commenters asserted that a gradual approach would provide more flexibility for
states and utilities to invest in the infrastructur e that will be necessary to increase NGCC utilization to the levels assumed in calculating st ate goals.

Commenters shared the concerns of stakeholders who have requested EPA replace the current interim compliance period goals with a more reasona ble glide path. Commenters supported alternative phase-in glide paths between 2020 and 2 029 based on State specific considerations and suggests EPA should expressly allow a State to present alternative glide path compliance scenarios so long as the State can demonstrate the same or better cumulative emissions are
achieved.

Although commenters favored a mile milestone approa ch for measuring progress during the years preceding the 2030 goal (discussed in another comment summary in this section), if the EPA adopts a ten-year averaging period in the final rule, they would prefer a modified interim period that accounts for a phase-in schedule. Comme nters stated that a phase-in schedule would provide time for infrastructure improvements that w ould support increased existing natural gasfired generation as well as modifications that woul d minimize stranded investments.

Commenters opined that easing the emissions "glide path" in the first few years of the interim compliance period gives states time to focus on lon g-term infrastructure needs. Commenters opined that phasing in compliance would enable stat es to make investments in deeper cuts that may not be achievable as quickly as a shift from co al to gas. Specifically, the commenters opined that states would be able to develop increased rene wable generation capacity, including new transmission lines where necessary, to reduce fossi l fuel consumption. Commenters stated that such development requires a significant amount of p lanning, permitting, and construction time. If states are forced to move too quickly to comply wit h a strict interim target, they are likely to prioritize solutions that are faster than large-sca le renewable generation deployment, such as the construction of new natural gas power plant capacit y. Commenters asserted that, while new natural gas capacity would be preferable to coal, f orcing this type of investment too quickly in order to meet the interim target may deter consider ation of investment in zero-emitting capacity in later years, and thereby reduce the lasting impa ct of the Proposal. Commenters stated that, while they appreciate EPA's willingness to explore softening the emissions glide path for states, they are not suggesting that any change to this eff ect should loosen the 2030 targets or the cumulative effect of the Proposal over the course o f the next decade, because loosening the targets would likewise reduce the incentive to inve st in zero-emitting capacity.

Commenters agreed with the proposal to phase-in Bui lding Block 2 over time to accommodate technical challenges states may face in expanding n atural gas infrastructure. Similar to the way that building blocks 3 and 4 are implemented in the proposal, the commenters suggested that
EPA could define an amount of utilization shift tha t is feasible by 2020, and then define how493

quickly that amount could grow until the full amoun t of utilization (70 percent in 2030) is achieved. This way, according to the commenters, st ates whose proposed emission rate goals assume large improvements through building block 2 will have a similar level of compliance flexibility as that which results from gradual depl oyment of the other building blocks. Commenters stated that they do not believe it is ne cessary to evaluate the rate at which existing coal-fired power plants can be retired as the compl iance period averaging should be able to accommodate any such delays.

Commenters stated that the development of an interi m goal reflecting a trajectory or "glide path" for a gradual phase-in schedule using all Building Blocks would achieve the flexibility EPA originally sought to provide in the proposed rule.

Commenters asserted that, to maintain affordability and reliability, the switch from coal to more natural gas fired generation needs to be phased in at an achievable rate through 2030, rather than by 2020.

Commenters expressed that, aside from the legal, te chnical, and practical concerns with Building Block 2, a phased-in approach would offer additiona l flexibility for states to attempt to address early unit retirement and related potential reliabi lity issues in developing a state plan within, what they believe to be an aggressive implementatio n schedule proposed by EPA.

Commenters expressed that the EPA does not provide any specific information on how it would determine an appropriate phase-in schedule for Buil ding Block 2. Commenters opined that it is
not realistic to assume that the EPA will be able t o establish a phase-in for Building Block 2 to accommodate all of the concerns surrounding the per mitting, technical, engineering, and infrastructure limitations associated with Building Block 2.

Did Not Take Position on Phase-In of Re-Dispatch

Commenters stated that they did not take a position on whether EPA should phase-in Building Block 2, and they reported that their states may ha ve different positions on this issue. However, commenters requested that, if the EPA does choose t o develop a phase-in schedule for Building Block 2, the EPA base any rate of transition from e xisting coal to existing under-utilized NGCC capacity on technical considerations relevant to su ch a transition. Commenters recommended that the EPA carefully consider historic changes in the relative utilization of coal and NGCC plants in response to price considerations, as well as natural gas supply capacity, as an important source of information about the potential for and p ace of shifts in utilization between coal- and gas-fired power plants.

Specifically Supported Phase-In of Building Block 2 Alternatives Raised in the NODA

Commenters supported a phase-in of Building Block 2 under both alternatives raised in the
NODA. Commenters stated that utilities could be in a situation to need the flexibility afforded by each alternative. Commenters reported that, where t here is an existing NGCC that will need additional infrastructure improvements to increase to a 70% capacity factor, utilities and states
will need additional time. Commenters are also in f avor of EPA considering the return on capital investment in existing coal-based assets in order t o avoid stranded investments. Based on commenters’ analyses of EPA's modeling results, the re are numerous stranded assets as a result494

of this proposal. Commenters reported that, some of the units that would be retired are currently installing air pollution controls at a cost of seve ral hundred million dollars to comply with the Mercury and Air Toxics Standards (MATS) rule.

Commenters recognized that a phase-in to provide an opportunity to develop infrastructure necessary to fully realize the effects of Building Block 2 may be necessary and supported a phase-in for Building Block 2, as EPA discusses in the NODA.

Commenters expressed that, if the EPA does not defe r to the states, they supported the adoption of a more gradual glide path that takes into accoun t both natural gas infrastructure needs (e.g., pipelines, booster compressors, and storage) and st randed investment concerns. Commenters opined that such an approach is consistent with the statute, which provides for consideration of energy system impacts and the remaining useful life of the affected source. Commenters further opined that a more gradual glide path would also li kely facilitate deeper long-term reductions. According to the commenters, there is likely an inv erse relationship between forcing states to reduce greenhouse gas emissions almost immediately (i.e., by 2020) and a state's ability to shift generation to renewable sources of energy, since ea rly reductions will depend predominantly on natural gas dispatch. Commenters asserted that, whe re material additional state investments are required, near-term natural gas commitments may "lo ck in" a state's or region's investment strategy thus deferring alternative investment in r enewables, energy-efficiency and energy storage. Commenters requested that states be able t o retain the authority to select the approach
best suited to their needs and to time the reductio ns accordingly.

Commenters supported the allowance for compliance o f measures which occur between the baselines year(s), and the first interim compliance deadline in 2020. Commenters opined that this would encourage states to act early in building ren ewable generation and energy efficiency incentive programs to create a smooth transition in to the compliance period, and will also provide some credit to states already making these investments. Commenters further stated that, while it would not be appropriate to make these ear ly reductions legally enforceable prior to 2020 given the timeline for SIP submission and appr oval, these reductions can be noted as part of a state's plan as a source of emissions reductio n. Commenters agreed with commenters who suggest that the re-dispatch of NGCC units contempl ated under Building Block 2 cannot reasonably be expected to occur on "day one" and su pported the recommendation put forth in the October 28th NODA that Building Block 2 should be p hased in similar to Building Blocks 3 and 4. Commenters expressed that states should be given flexibility to determine the appropriate phasing of this Building Block based on electric an d gas transmission needs in their states and regions.

Commenters urged the EPA to adopt a phase-in schedu le for Building Block 2 based on the fact that some states will require additional infrastruc ture improvements in order to support more use of existing natural gas-fired generation, as discus sed in the NODA. Commenters stated that they would support the NODA-suggested approach of modify ing Building Block 2, and thus the interim goal, to reflect such factors as infrastruc ture limitations and the potential for stranded investments considering state specific factors. Com menters suggested that the most straightforward method of adopting this approach wo uld be to allow each state to propose its interim goal in its section 111(d) plan.495

Commenters believed that both options described in the NODA, credit for early reductions (addressed under another comment in this section) a nd phasing in of Building Block 2, are options that a state should be able to use in estab lishing its glide-path. Phasing-in would be more consistent with Buildings Blocks 3 and 4 where incr eased utilization is phased-in between 2020 and 2029. Commenters further stated that they suppo rted the second phase-in option included in the EPA's NODA; that Building Block 2 be modified t o respond to stakeholder concerns about the pace with which generation in some states may n eed to be shifted from higher-emitting to lower-emitting-units.

Commenters expressed that it is not clear from the NODA how EPA would structure a phase-in schedule for Building Block 2. Commenters stated th at, under the first option, the EPA would account for the needed expansion in natural gas pip eline infrastructure, but the Agency has not provided any details as to how the Agency would det ermine which states need new capacity and how quickly it could be built. Commenters stated th at, at minimum, the EPA should recognize that it takes three to five years to plan, permit, contract for capacity, finance and build additional pipeline capacity. However, commenters believed tha t, in general, it is difficult to see how the Agency could determine a phase-in rate for new pipe line capacity that would make sense for each state or accurately reflect state-specific inf rastructure circumstances.

Commenters urged the EPA to examine early action (a ddressed under another comment in this section) and phasing in to reasonably adjust the in terim goals, while maintaining the environmental integrity of the final targets. Comme nters urged the EPA to work with states, regulatory authorities such as the NERC, and region al reliability organizations (RROs) such as the Western Electricity Coordinating Council (WECC) to adopt a more realistic view of the potential for re-dispatch that considers stranded c osts and the reliability of the grid. Specifically, the commenters requested that EPA develop a more re asonable, phased-in timetable for redispatch that would not threaten the reliability of the regional grid nor impose undue stranded costs on states' electric ratepayers. Commenters op ined that such a development should result in more realistic interim goals, which would not imply such sharp emission rate reductions by 2020, and which would provide the EPA and states a more m easured way to gauge progress toward the 2030 goals. Commenters stated that a more reasonabl e, phased-in timetable is important for states like California that have both significant N GCC capacity and few high emitting resources.

Commenters recommended that, in addition to allowin g for more credit for early action (addressed under another comment in this section), EPA should modify the 2020-2029 glide path to allow more flexibility in the timing and impleme ntation of efforts to achieve the final goals.

Complicated and Difficult to Implement NODA Approac hes

Commenters agreed with stakeholder concerns that th ere may be technical challenges associated with achieving all of the reductions that states wo uld be required to make as early as 2020, when the interim period commences, such as additional in frastructure improvements (e.g., natural gas pipeline expansion or transmission improvements) ne eded to support more use of existing natural gas-fired generation. However, commenters did not s upport either of the alternative approaches that EPA has requested comment on in the NODA to ad dress stakeholder concerns with the "front-loading" of Building Block 2 because they be lieve they are complicated, cumbersome, subjective and difficult, if not impossible, to be implemented on a uniform basis across the states.496

Commenters recommended another glide path approach that they believed might offer states the flexibility they need to address stakeholder concer ns with the "front-loading" of Building Block 2 while still ensuring that they can achieve the fi nal goals.

Implementation of NODA Options Would Not Be Suffici ent to Address Compliance Concerns

Commenters stated that, although they agree that bo th of the options provided in the NODA can help temper the near-term compliance challenges, ev en if implemented together they are not sufficient to fully address concerns.

Commenters asserted that, in the NODA, the EPA did not provide any additional data to support either of their proposed approaches. Moreover, acco rding to commenters, because the EPA did not change the December 1 comment deadline, there w as insufficient time for them to fully analyze EPA's proposals. However, based on the comm enters' limited review, they asserted that neither of the alternate glide path proposals provi des reasonable alternatives to Rule 111(d) as proposed. First, commenters stated Building Block 2 is an "outside the fence" activity over which the EPA has no authority. Commenters stated t hat the EPA is neither authorized nor qualified to dictate to states how their natural ga s units should be operated or dispatched. Second, commenters stated that Rule 111(d) does not provide flexibility for their state (Texas), but instead would require their state to implement appr oximately 77% of its emission reductions by 2020, which they opined is both unreasonable and un achievable. In conclusion, commenters stated that the alternate glide path proposals in t he NODA do not appear to provide any meaningful flexibility for their state to meet EPA' s interim emissions goals.

Commenters stated that, while they understand the c ritical importance of maintaining system reliability both before and during the plan perform ance period, they are concerned that the options set out in the NODA may not result in a red uction of total CO2 emissions at a level that the EPA's proposal would. Commenters asserted that climate change is a threat of epic proportions, and adequately addressing that threat must not be compromised.

Commenters stated that, while the EPA seems to reco gnize in the NODA that full re-dispatch by 2020 is problematic the Agency's attempt to address this issue (i.e., credit for early actions and a phasing in of NGCC units) is inadequate. Commenters stated the NODA still fails to recognize the infrastructure, permitting and construction lim itations. Commenters stated that, while the proposal contemplates adjustment of individual stat e targets for this building block based on infrastructure needs and the time to complete them, such approach will require significant time to study and implement, which is not feasible given th e timing requirements for filing of state plans. Commenters added that construction timelines are difficult to accurately predict and thus create unnecessary compliance uncertainty and risk.

Commenters opined that, while the idea of a "glide path" to the final requirements of the year 2030 appears appealing, it will not work. Commenter s stated that, in addition to the glide path requiring a sharp decrease in emissions in the year 2020 or over-compliance in the latter years of the period, they had other objections as well: Comm enters asserted that the glide path proposed by the EPA would prematurely and unnecessarily caus e an increase in costs borne by Minnkota's member-owners by shifting generation away from coal -fired plants to more expensive lower emitting carbon dioxide sources prematurely.497

Commenters stated that the EPA has begun to recogni ze that a sudden shift to natural gas generation by 2020 may be unreasonable and unachiev able and has requested comment on a phase-in approach aimed at avoiding the likely cons equences of a hasty reduction in coalgeneration. However, according to the commenters, t he suggestion of a glide path is not the answer, and they believed they had insufficient tim e to address issues pointed out in the NODA.

Commenters expressed that, in the NODA, EPA appears to acknowledge the major timing issues associated with NGCC re-dispatch and has asked for comment on whether a more gradual phasein would alleviate concerns over workability and re liability. Id. at 64,548-549. The commenters asserted that, while the acknowledgement of stakeho lder concerns is laudable, it does not resolve the basic flaws of Building Block 2. First, accordi ng to the commenters, states have no authority to mandate dispatch of NGCC within their state; the dispatch of power is governed by the RTOs.
Commenters stated that NGCC units in existence were planned, permitted, constructed and
interconnected with transmission based on the needs of the operating/owning utility, and are limited by physical pipeline and transmission const raints, permit limits and gas availability, none of which can be simply ramped up to meet the 70% as sumed capacity factor by 2020. Commenters stated that the glide path's assumption that all NGCC can be ramped up to 70% in 2020 ignores basic operational issues. Commenters a sserted that the timing of the glide path does
not reflect the transmission or interconnection stu dies, revised agreements or RTO modeling that would have to be accomplished in a very short perio d of time to increase the capacity factor, while still meeting reliability requirements of the North American Electric Reliability Corporation (NERC). And of course, according to the commenters, that is predicated on the assumption that transmission capacity is available for the increase in NGCC operation. In fact, according to the commenters, if the existing units are in a transmission constrained area, new
transmission must be added to accommodate the load. Commenters stated that transmission studies on average take about two years to complete and that new transmission cannot be guaranteed to materialize in the time frame suggest ed by the proposed rules. Commenters reported, for example, the Minnesota CapX 2020 proj ect took roughly 10 years from initial planning stages, to permitting, to the placement of the new lines into service. Commenters further reported that the CapX project has taken ad ditional time as there have been contested court challenges to eminent domain and the Minnesot a "Buy the Farm" statute which requires affected agricultural land to be purchased in whole , and not just the impacted portion. See Minn. Stat. 216E.12, subd. 4. The commenters asserted tha t, as the EPA is well aware, contested case proceedings would significantly lengthen the timefr ame of building needed transmission, will be a significant barrier to states meeting glide path milestones, and are an inevitable part of transmission siting in the 21st century.

Concerned that Phase-In Proposals Would Weaken or D elay Carbon Pollution Reductions

Commenters stated that EPA's proposals to develop s tate carbon pollution reduction targets based on a gradual phase-in of Building Block 2 cou ld weaken or delay carbon-pollution reductions in the short term unless the EPA strengt hens the guidelines of the other building
blocks.

Commenters requested that EPA not adopt a phase-in for either building block 1 or 2 as it will undermine efforts to meet the national all-sector g oal of 17% by 2020 and 28% by 2025. Commenters asserted that, while there has been a re duction of emissions from power plants498

solely as a result of market forces, the nation as a whole must stay on track to achieve the needed reductions across all anthropogenic sources.

Commenters expressed that they do not support the N ODA proposed changes to the glide path. Commenters asserted that the draft proposal already allows significant flexibility to states in the timing for reaching their goals of the CPP and furt her delays in achieving emissions reductions are contrary to the overall goals of the CPP to mak e a significant contribution to reduce U.S. global warming emissions in a timely way. Commenter s requested that, if EPA decides to make changes to the glide path, it should only be done i n conjunction with strengthening the state emissions reduction goals required by CPP. Commente rs also asserted that delaying emissions
reductions could also result in more stranded asset s with utilities making investments to nearterm targets that may be unsuitable for meeting the long term targets.

Phase-In Not Needed

Commenters opined that, with respect to the proposa l for a phase-in for Building Block 2, EPA should refrain from adopting such methodology. Acco rding to the commenters, a phase-in methodology is not needed for Building Blocks 1 and 2, as it is for 3 and 4. Commenters believed the EPA was correct in its proposed rule i n determining that the BSER for Building Blocks 1 and 2 were feasible in the proposed timefr ame.

Comment 3: Commenters said that states should have authority to define their own glide path and timeline to address compliance concerns.

Response 3: The EPA disagrees with commenters. The interim stan dards are an important part

of this final rule and are essential for successful performance. The EPA has provided many pathways that states can choose to comply. The 111( d) final rule requires that states develop plans that establish emission standards for affecte d EGUs. The rule provides states with substantial flexibility as to how they structure th ose plans to achieve the 111(d) requirements. The flexibility includes, for example, the choice o f approaches, trading, time to develop plans, additional time before the start of the interim per formance period (postponed from 2020 until 2022), and the ability to shift emission rate achie vement between performance periods. The Building Blocks are not prescriptive, and states ma y consider local circumstances as they develop their plans, including other regulatory req uirements and the “useful life” of assets. See sections V.D, VIII.A, VIII.C and VIII.G of the fina l rule preamble of the CPP and Chapter 3 of the GHG Mitigation Measures TSD for the CPP Final R ule supporting the final CPP.

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

Commenters argued that, eliminating states' complia nce flexibility runs afoul of section 111(d)'s requirement that states be able to consider a units ' remaining useful life in complying with section 111(d).

Commenters urged EPA to recognize state authority t o determine the interim path and timetable to achieve 2030 carbon intensity targets.499

Commenters opined that states should be given flexi bility to determine the appropriate phasing of this Building Block based on electric and gas tr ansmission needs in their states and regions.

Commenters suggested that EPA allowing states to es tablish EGU-specific re-dispatch or refiring dates by permit or rule is reasonable.

Commenters asserted that, because states are in the best position to identify the pace at which additional re-dispatch can be incorporated into the system, the EPA should allow states the opportunity to develop and submit to the EPA adjust ed interim targets for 2020-2029 that account for a more gradual ramp-up of NGCC capacity factors. Commenters expressed that states' final 2030 targets could remain the same.

Commenters requested that the EPA allow states to d etermine what level of re-dispatch is feasible and the reasonable schedule for implementi ng NGCC re-dispatch.

Commenters asserted that, while a phase-in of the r e-dispatched generation assumed in Block 2 might mitigate the impacts of Block 2, the EPA does not have the necessary expertise to decide what implementation rate is appropriate for each st ate. Commenters stated that, incorporating a phase-in of the re-dispatching as discussed in the October 30 NODA (79 FR 64548) would mitigate some of the near-term impacts of Block 2. However, commenters asserted that the EPA is not qualified to determine the feasibility of su ch a fundamental shift in a state's energy policy. Commenters opined that only the state public utilit y commissions are in a position to evaluate the feasibility of shifting generation from one fue l source to another on the scale that the EPA is assuming under Block 2. Furthermore, commenters ass erted that, what may be feasible in one state is not necessarily feasible in another state.

Commenters believed that each state should be allow ed significant latitude in how it achieves a glide-path over the period of 2020 through 2029 to achieve an end goal set in the rule and that both options described in the NODA, credit for earl y reductions and phasing in of Building Block 2 are all options that a state should be able to use when establishing its glide-path.

Commenters suggested that the EPA allow the states to determine how quickly Building Block 2 may be phased in. Commenters reported that the EPA suggests that an appropriate phase-in schedule could be based on "whether, and to what ex tent, any additional infrastructure improvements (e.g., natural gas pipeline expansion or transmission improvements) are needed to support more use of existing natural gas-fired gene ration," or on avoiding stranded investments considering the "book life" of generating assets. I d. at 64,548-49. Commenters asserted that states are in a much better position than EPA to as sess these factors and determine an appropriate phase-in schedule. Commenters also stated that the EPA gives no indication as to how it would go about assessing these factors and developing a p hase-in schedule on its own for the states.

Commenters indicated a preference for a glide path approach to meet the final goal. The commenters noted that, while the EPA has stated ver bally that this approach is not provided for in section 111(d), the commenters also noted that t he interim goal is not provided for in section 111(d).500

Comment 4: Some commenters supported eliminating or adjusting interim goals, while other commenters opposed the idea of eliminating the inte rim compliance period or allowing states to devise their own interim compliance period.

Response 4: The EPA thanks the commenters. The EPA agrees with those opposing the idea of eliminating interim compliance, and has provided ma ny ways to comply with this final rule. The 111(d) final rule requires that states develop plan s that establish emission standards for affected EGUs. The rule provides states with substantial fle xibility as to how they structure those plans to achieve the 111(d) requirements. The flexibility in cludes, for example, the choice of approaches, trading, time to develop plans, additional time bef ore the start of the interim performance period (postponed from 2020 until 2022), and the ability t o shift emission rate achievement between performance periods. The Building Blocks are not pr escriptive, and states may consider local circumstances as they develop their plans, includin g other regulatory requirements and the “useful life” of assets. See sections V.D, VIII.A, VIII.C and VIII.G of the final rule preamble of the CPP and Chapter 3 of the GHG Mitigation Measure s TSD for the CPP Final Rule supporting

the final CPP.

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

Support Eliminating Interim Goals

Commenters suggested that the EPA not finalize an i nterim goal for implementing the NGCC dispatch. Most of the commenters believed that elim inating interim emissions goal so that states can determine the most appropriate phase-in schedul e for Building Block 2 reductions would better address state-specific concerns. Rather than mandating enforceable interim goals, commenters recommended that the EPA give states dis cretion to develop individualized plans for the 2020-2029 time period that establish programs a nd measures that lead to compliance with the 2030 emission goals. In particular, commenters stat ed that the EPA must allow each state to
make its own determination as to which measures can be implemented on a timetable that is manageable for the state but leads to achievement o f the 2030 goals. Commenters stated that, although both of the approaches set out in the NODA address some of their glide path concerns, neither approach provides states the same ability t o design cost-effective compliance plans that
are consistent with the technical realities of shifting generation between existing coal- and gasbased units that would be provided by eliminating t he interim goals. Commenters suggested that the EPA can consider the phase-in as part of its re view of the state plan, but should not establish a set of unattainably harsh interim goals governing it. Commenters asserted that, if EPA is to set BSER standards, the interim standards should be eli minated and EPA must allow states, in concert with ISOs and RTOs, to develop their own mo derated glide paths in order to avoid grid reliability and economic problems. Commenters sugge sted that interim targets be dropped and replaced with objective criteria that include both procedural and substantive criteria that states would be required to include in their compliance pl ans to demonstrate a reasonable glide path to the 2030 targets.

Commenters asserted that the flexibility that the E PA advertises with this proposed rule would be more credible if the interim goals were eliminated. Commenters stated that, in its current form, the interim goal glide path is very specifically ta ilored to an exact combination of building501

blocks implemented by a precise schedule set by the EPA. According to the commenters, if a state were to vary from this combination of buildin g blocks or schedule in even the slightest way, there is a high likelihood that the interim goals o r final goals would not be able to be met.
Commenters asserted that the elimination of the int erim goals would promote the flexibility to implement building blocks, at a state or regional l evel, on a schedule that is appropriate given the individual factors contributing to that state or re gion's ability to reduce carbon emissions. Commenters also asserted that states or regions sho uld be able to determine this schedule in their implementation plans and not be mandated to meet in terim goals as long as the timeline proposed in the SIP (and approved by the EPA) inclu des appropriate measures taken to ensure compliance with the 2030 goals.

Commenters requested that the EPA consider a glide path approach by 1) removing the interim goals from the final rule and/or 2) delaying the co mpliance deadline by five years from 2030 to
2035.

Commenters stated that, if the EPA were to eliminat e interim goal and instead only require states to achieve their final emission rate goals in 2030, states would then be allowed to tailor the contour of its glide path to attaining its 2030 goa l based on the unique circumstances and limitations for implementing the four building bloc ks. Commenters stated that the state would be required to establish a plan, subject to EPA approv al, with enforceable milestones for phasing in the reductions during the 2020 to 2029 period, and a demonstration that its proposed time frame for phasing in those reductions is as expeditious a s practicable. Commenters asserted that such an approach is consistent with section 111(d) and t hat EPA has discretion to allow states to achieve their state-specific emission goals based o n various factors enumerated in section 111, including costs, energy requirements, and the remai ning useful life of existing source.

Commenters expressed that the effect of the interim goal severely limits the opportunity to fully take advantage of remaining asset value of existing coal-fired generation.

Commenters requested that EPA eliminate the interim state targets or recalibrate them to account for a more gradual phase-in of redispatch to NGCCs over the 10-year interim compliance period. Commenters believed that both of these steps would help to alleviate many of the negative impacts this aspect of the Proposed Rule.

Commenters supported all options that provide the s tate with flexibility to achieve the state goal based on state procedures, legislation and with coo rdination with all appropriate stakeholders.
Commenters believed that states should continue to be allowed to choose rate-based or massbased goals and single-state and/or multi-state pla ns to achieve state goals according to the glide path developed by the state. Commenters specificall y supported states being able to design a "rate of progress" plan and should not preclude the use of any means the state chooses to reach the end goal (including whether to adopt the "alter nate" 2025 state goal or adopt what are termed in the current proposal the interim and final goals . Commenters suggested that if a state develops a "rate of progress" plan that satisfies the final goal, then the interim goal should be eliminated. Commenters believed that the interim goal creates u nnecessary reliability risks, increases consumer cost, and improperly restricts the state's ability to exercise its statutory prerogatives under the CAA to develop appropriate compliance pla ns and alternatives, including consideration of remaining useful life of existing resources.502

Commenters stated the EPA should not finalize any i nterim goal and should allow states to determine and set reasonable schedules for implemen ting NGCC re-dispatch. Commenters noted there are obstacles to increased NGCC operation by 2020 that will make meeting the Proposal's goal unlikely, if not impossible. Commenters stated increased NGCC operation at individual units may require upgrades to natural gas pipelines , additional electric transmission facilities, or air permit amendments, as well as changes to the op eration of the electrical grid. Commenters were concerned that neither EPA nor regulated entit ies fully understand the extent of new construction and upgrades that will be necessary to comply with the proposed rule, and encouraged relevant parties to undertake studies to ascertain what may be required, the associated costs, and the timeline to properly comp ly. Commenters suggested that an industry group and/or NERC are the appropriate entities to c onduct such a study, and EPA's role should
be to set a timeline that will accommodate it. In t he event that EPA includes a mandatory interim goal, commenters suggested the EPA should assume a ramp-up period for re-dispatch implementation, similar to EPA's treatment of renew ables and energy efficiency.

Commenters stated that the EPA should at a minimum permit a compliance timeline based upon the assessment made by the Kentucky Division of Air Quality working with the affected EGUs that recognizes both the reality of the time requir ed to complete the steps necessary to replace existing generation with lower emitting natural gas generation and to reflect the useful life of existing EGUs. Commenters described the following p rocedure and timing for construction of
new NGCC.

At the earliest, the Kentucky SIP would be approved by EPA in June of 2017. For an interim reduction compliance date of January 1, 202 0, OMU would need to take immediate action to find an acceptable site for con struction of natural gas generation,
which would take 6-12 months at a minimum. Permitti ng a new natural gas EGU would take a minimum of 18 months after engineering is co mpleted to the level necessary to support the air permit application. Large Generator Interconnect Agreements (LGIA) and associated required studies pursuant the LGE/KU Ope n Access Transmission Tariff will
take a minimum of 12 months after the definitive si te is identified and engineering was completed. The LGIA process is further complicated because to the extent LGE/KU has additional LGIA requests in queue, OMU and any othe r applicant must wait until their project reaches the number one queue position befor e the OATT prescribed time clock begins. Construction of required interconnection in frastructure will take at least 24 months with complications likely due to right-of-wa y acquisition for transmission facilities and natural gas pipelines. With a minimu m construction period of 24 months depending upon start date, the retirement of an ESG S unit in 2020 would expose OMU ratepayers to market prices for a minimum of two ye ars before a replacement natural gas fired generating facility comes online.

Commenters recommended the EPA to eliminate the int erim goal and allow states to determine a schedule for implementation based on feasibility an d cost. Commenters stated that, if EPA chooses to retain the interim goals and allow state s to phase in Building Block 2 over the entire compliance period, a phase-in schedule should consi der any additional necessary infrastructure improvements needed to eliminate existing natural g as supply constraints and ensure a reliable fuel supply. Commenters stated the EPA also should consider the time required to integrate any503

transmission enhancements needed to address impacts to reliability, as indicated by MISO and
NAERC.

Commenters stated that, based on the current and fu ture demand on the existing and underconstruction natural gas infrastructure and NGCCs a nd the economics and hurdles for the construction of new natural gas infrastructure and NGCCs, EPD believes the 70 percent capacity factor is not achievable by 2020. Commenters sugges ted that the EPA revise the CPP (specifically related to the interim goal) to allow states the flexibility of phasing in dispatch changes over time as long as the 2030 goal is met. Commenters stated that Georgia's NGCC fleet capacity is not adequate to support a reliable powe r grid and 70% dispatch rate for NGCC. Commenters stated that, while Georgia currently mai ntains a reliable power grid with NGCCs operated at a dispatch rate of over 51%, with the i ncreased burden of NGCCs operated as baseline, future system reliability will be decreas ed.

Recommended Adjusting Interim Goals

Commenters suggested that, as an alternative to eli minating the interim goals, EPA should adjust the stringency of the states' interim goals to acco unt for the barriers and delays that states may face when implementing Building Blocks 1 and 2. Und er this approach, the commenters asserted that the state would still achieve the 2030 final g oal established by the EPA based on the four building blocks, but the stringency of the interim goals would be adjusted to reflect the statespecific schedule for the expeditious implementatio n of the control measures within the state. According to the commenters, this would enable each state to develop a workable and reasonably achievable plan based on its ability to install the control measures, the cost of compliance, impacts on reliability, and other relevant state-sp ecific factors. Commenters further stated that the state plan would include federally-enforceable milestones, for implementation of the emission reductions necessary to meet the final goa l.

Commenters requested that, in cases where EPA may b e unable to adjust state interim goals prior
to the issuance of the final rule due to insufficie nt data, EPA establish a procedure for the adjustment of the state goals. Commenters stated th at, under this procedure, a state would have the option to seek an adjustment of its interim goa ls based on a detailed technical demonstration that it was not feasible or practicable to implemen t all of the CO2 reductions under Building Blocks 1 and 2 by the start of the program in 2020. Commenters suggested that such state requests could be submitted to the EPA within 6 mon ths from the promulgation of the final emission guidelines. Commenters further suggested t hat EPA could review and approve of such requests based on specified criteria, such as the a mount of generation that would need to be redispatched as well as the barriers or limitations f or achieving the re-dispatch.

Commenters recommended that the EPA reconsider seve ral assumptions used in goal-setting and that EPA adjust the interim goals.

Opposes Idea of Eliminating the Interim Compliance Period or Allowing States to Devise Their Own Interim Compliance Period

Commenters expressed opposition to the idea of elim inating the interim compliance period or allowing states to devise their own interim complia nce period requirements as some stakeholders504

have suggested, because they think it is important that that states achieve emission reductions in a consistent manner across the compliance period an d not delay emission reduction programs to
the latter half of the decade.

Comment 5: Commenters requested that the "glide path" be limi ted to those states that can demonstrate that they are unable to cost-effectivel y or technically comply (e.g., because of the need for more time for infrastructure improvement) with their interim goal as proposed.

Response 5: The EPA does not believe these comments are warran ted but has modified the final rule compliance path and provided additional flexib ilities. The 111(d) final rule requires that states develop plans that establish emission standa rds for affected EGUs. The rule provides states with substantial flexibility as to how they structu re those plans to achieve the 111(d) requirements. The flexibility includes, for example , the choice of approaches, trading, time to develop plans, additional time before the start of the interim performance period (postponed from 2020 until 2022), and the ability to shift emission rate achievement between performance periods. The Building Blocks are not prescriptive, and states may consider local circumstances as they develop their plans, including other regulator y requirements and the “useful life” of assets. See sections V.D, VIII.A, VIII.C and VIII.G of the final rule preamble of the CPP and Chapter 3 of the GHG Mitigation Measures TSD for the CPP Fina l Rule supporting the final CPP.

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

Commenters requested that, in the final rule, EPA c larify that amendments to the "glide path" are
limited to those states with a demonstrated inabili ty to cost-effectively comply with the interim goal as proposed. Minnesota's Clean Energy Organiza tions appreciate EPA's attempt to make state compliance with the Clean Power Plan as flexi ble as possible. Commenters also requested that EPA set an interim goal based on average emiss ions during the 2020-2029 timeframe. Commenters stated that, as with EPA's expectation r egarding the need to demonstrate technical infeasibility as a whole before individual building blocks will be modified, EPA should similarly require states to demonstrate the infeasibility of complying with the interim goal in a costeffective manner before EPA makes any changes to th e "glide path," such as those identified in the NODA. According to the commenters, for states l ike Minnesota - states that have renewable energy generation in 2013 beyond the 2030 goal, rob ust RESs and energy efficiency standards, and coal-fired EGUs with existing natural gas infra structure - it is possible that the current interim goal structure will be entirely feasible us ing cost-effective measures. Commenters stated that, in other words, early action credit is likely unnecessary for states that have already taken significant early actions because those states, lik e Minnesota, are well positioned to comply with
the Clean Power Plan in a cost-effective manner.

Commenters considered the NODA phase-in schedule ap proach based on the need for additional time for infrastructure improvements (e.g., natural gas pipeline expansion or transmission improvements) acceptable where the need for such a phase-in schedule is clearly demonstrated.505

Comment 6: Some commenters supported or conditionally support ed an allowance for early action credit, while other commenters felt that thi s was not needed.

Response 6: The EPA thanks the commenters. The EPA has provided early action credit in this final rule. See Preamble Section VIII on state plan s.

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

Specifically Support Early Action Credit

Commenters believed that early crediting should be allowed.

Commenters supported providing full credit for earl y actions that result in reduced CO2 emissions before the compliance period begins in 20 20.

Commenters reported that, allowing states to recogn ize early action that reduces emissions between 2012 and the start of the interim complianc e period is an important tool that could be useful to some states when designing compliance pla ns. Commenters agreed with the EPA's assertion that it is important to recognize early r eductions so as not to create disincentives for pre-2020 reductions and that the final guidelines s hould permit early recognition of reductions as states develop their individual glide paths to the 2030 goal.

According to commenters, however, early recognition does not address fully the concerns raised in their comments about the interim compliance goal and the magnitude of reductions that are required before 2020. Commenters asserted that, whi le states may be able to use some reductions from RE and EE measures, it is unlikely that these reductions would be significant enough to offset the need to increase significantly utilizati on of existing NGCC units to meet the interim goals. Commenters further asserted that credit for early RE and EE reductions also does not
address infrastructure concerns or other technical challenges associated with increasing the utilization of existing NGCC units.

In addition, commenters argued that, given the timi ng challenges states face in submitting timely compliance plans for EPA approval, it is unlikely t hat states would be able to begin compliance plans early in order to take advantage of pre-2020 reductions. Commenters asserted that, if states would like to do so, the final guidelines should ma ke it clear that this is an option. Nonetheless, commenters reported that early recognition, is not sufficient to alleviate these concerns and does not obviate the need to eliminate the interim compl iance goals.

Commenters stated that, while the EPA identifies ea rly action crediting as a potential response to stakeholder concerns regarding Building Blocks 1 an d 2, they believe that such an approach is justified for reasons beyond smoothing out a "glide path." Commenters asserted that early crediting for new actions will also spur states to act earlier, accelerating the expansion of the advanced energy markets, driving earlier emission r eductions, and providing states a longer period for compliance activity. Commenters stated t hat early action crediting can achieve all of this without weakening the stringency of the emissi on targets. Conversely, commenters asserted that providing no credit for early action threatens to counter-productively stall continued expansion of advanced energy markets, and their ass ociated emission reductions, until after 2020
when "full credit" would be available.506

Commenters opined that early credit for emissions r eductions would help ease issues related to interim goals. In addition, the commenters believed that early credit would send a signal to states encouraging early action on emerging problems.

Commenters strongly supported EPA allowing early re ductions credit to ease the 2020-2029 glide However, the commenters asserted that the EPA should only consider such approach with respect to energy efficiency measures. According to the commenters, this is because energy efficiency is a unique resource. Unlike other inves tments, the commenters stated that energy efficiency continues to replace demand long after t he actual measures themselves are installed. Commenters stated that the EPA's proposed rule woul d limit credit for energy efficiency savings installed prior to 2020, but would allow EGUs to cl aim credit for pre-2020 measures with respect to the savings those measures achieve after 2020 an d beyond. Commenters expressed belief that the EPA should consider allowing credit for savings experienced as early as the baseline year of 2012, so long as EGUs can demonstrate a precise amo unt of savings using the Evaluation, Measurement and Verification (EM&V) methodology app roved or developed by EPA. Furthermore, the commenters stated that allowing EG Us to claim credit for past and/or current efficiency investments will avoid the threat of EGU s delaying large efficiency investments until later years so as to claim maximum credit when it c ounts.

A couple of commenters specifically supported the a llowance for compliance of measures which occur between the baselines year(s), and the first interim compliance deadline in 2020. Commenters opined that this would encourage states to act early in building renewable generation and energy efficiency incentive programs to create a smooth transition into the compliance period, and would also provide some cred it to states already making these investments. Commenters stated that, while it would not be appropriate to make these early reductions legally enforceable prior to 2020 given the timeline for SIP submission and approval, these reductions can be noted as part of a state's plan as a source of emissions reductions. Commenters supported incentives for early action to encourage investments in renewables and energy efficiency and a shift away from fossil-fire d generation after a state compliance plan has been approved by the EPA, as long as incentives do not undermine the overall level of emissions reductions achieved by the CPP.

Commenters supported incentives for early action to encourage investments in renewables and energy efficiency and a shift away from fossil-fire d generation after a state compliance plan has been approved by the EPA, as long as incentives do not undermine the overall level of emissions reductions achieved by the CPP.

Early Action Credit Unnecessary for States that hav e Already Taken Significant Early Action

Commenters stated that early action credit is likel y unnecessary for states that have already taken significant early actions because those states, lik e Minnesota, are well positioned to comply with
the Clean Power Plan in a cost-effective manner.

Concerned Early Crediting Will Not Result in Simila r Emission Reductions to What Was Proposed/Provides Conditions for EPA to Consider If Early Action Credit Mechanisms Allowed507

Commenters expressed concern that allowing for earl y action credit may not result in the same level of emission reductions to the proposal. Comme nters urged that, if the EPA believes that reliability claims must be addressed through some s ort of early action credit mechanism as identified in option (2) of the NODA, the EPA take a broad perspective of the EGU portfolio and disallow any attempt to "cherry pick" early actions only from low-emission EGUs or emission reduction systems. Commenters opined that early act ion must consider all statewide EGU emissions in an early action period - it makes no s ense to provide a state with early action for renewable energy deployment at the same time the st ate was increasing emissions from fossilfueled generators.

Comment 7: Commenters said that the EPA should account for re tirements occurring in the near term in Building Block 2 calculations and described how this would affect Tennessee.

Response 7: The EPA thanks the commenters. The goals are based on an overall CO2 emission performance rate calculated using data on affected sources rates during the 2012 base year. The EPA does recognize retirements of high emitting uni ts during compliance period because they

will lower the emissions rate when a state selects the rate approach and lower the level of emission under a rate based approach.

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

Commenters requested that the EPA account for retir ements occurring in the near term in Building Block 2 calculations. Commenters expressed that the EPA's Building Block 2
calculation assumes that emissions from units that retired in 2012 (the base year) or that will retire (according to their operators) in the next f ew years are relevant for purposes of setting a baseline. However, the commenters reported that the rule's proposed compliance period will not begin until 2020. According to the commenters, by i ncluding business-as-usual retirements in the target-setting exercise, EPA fails to identify the best system of emission reductions, since states with recent or imminent coal plant retirements may face relatively more lenient standards than other states. Commenters urged the agency not to al low states to ignore near-term changes in the generation mix, including the large number of retir ements expected to occur between 2012 and 2017 or 2018, when final state plans are due.

Commenters argued that, under EPA's approach, gener ation from fossil fuel-fired steam EGUs is expected to be reduced in equal measure to the exce ss NGCC capacity that is available for redispatch. For example, according to the commenters, in Virginia, re-dispatch to underutilized NGCC units would generate approximately 6 million M Wh, so the state is expected to reduce its coal-fired generation by that same amount. Commente rs reported that Virginia's coal-fired generation amounted to 13.6 million MWh in 2012, bu t only 10.3 million of those MWhs were generated by units that are expected to continue op erating past 2015. Commenters stated that, after a 6 million MWh reduction, the units that con tinue to operate can either generate 7 or 4 million MWh depending on whether or not EPA account s for near-term coal retirements in its final guidelines. Commenters opined that this is a much more substantial difference in stringency than the range of options under consideration for B uilding Block 1: a one-percent difference in508

heat rate improvements at these Virginia units is c omparable to 40-70,000 MWh of generation
reduction.

Commenters asserted that Tennessee's situation also illustrates this point. As of this writing, the commenters reported that three coal-fired units in Tennessee that were included in EPA's goalsetting calculation have either retired or have ann ounced plans to retire prior to the 2020 compliance period: Allen Steam Plant, Johnsonville Fossil Plant, and John Sevier Fossil Plant. According to the commenters, these three facilities generated approximately 7.5 million MWh in 2012, and Tennessee's 2030 target emission rate und er the Clean Power Plan is 1,163 lbs CO2/MWh. Under Building Block 2, EPA calculates tha t Tennessee can re-dispatch approximately 3.3 million MWh annually from existin g coal plants to existing gas plants if it scales up its gas-fired generation to a 70 percent capacity factor. But, the commenters explained, because the three retired (or retiring) units noted above will be removed from the state's generation mix regardless of the rule, the state ca n simply bypass the reductions needed satisfy Building Block 2. Commenters reported that, even if Tennessee were to replace the 7.5 million MWh produced by these retiring units with generatio n from new combined-cycle gas plants (which the commenters urged EPA not to permit for u se as a compliance mechanism), it could avoid re-dispatching any existing gas units entirel y and still achieve a final emission rate of 1,111 lbs CO2/MWh if it adopted the measures specif ied under Building Blocks 1, 3 and 4. In fact, according to the commenters, these three reti rements would give the state enough of a compliance margin that it could reduce its heat rat e improvements at existing coal plants to just two percent and still meet its final target, assumi ng full compliance with Blocks 3 and 4. On the other hand, the commenters stated that, if these th ree plants were simply deleted from both EPA's target-setting process and from a determination of state compliance, Tennessee would need to find some other way of achieving the emission reduc tions under Building Block 2, which would be determined by the then-available excess NGCC cap acity.

Commenters requested that the EPA improve the fairn ess and effectiveness of the proposal by excluding near-term "business-as-usual" plant retir ements from the determination of BSER and the state emission targets. Commenters asserted tha t the most accurate process would be for EPA or each state to calculate the state's Building Blo ck 2 target based on the most recent available data when the state submits its compliance plan for the agency's approval. Thus, according to the commenters, if Tennessee were to submit its plan to EPA in 2016, the agency would use 2015
data rather than 2012 data to calculate Tennessee's interim and final target emission rates. If the state took an extra year and submitted its plan in 2017, the commenters stated that the EPA
would use 2016 data. Commenters stated that this wo uld ensure that plants that existed as of
2012 but have retired since that time are not inclu ded in either the target-setting or compliancedetermining process. It would also ensure, accordin g to the commenters, the use of the most accurate information concerning available underutil ized NGCC capacity for purposes of calculating the enforceable state emission targets. Moreover, the commenters requested that the EPA delete from its target calculations and complia nce determinations any still-existing plants with legally enforceable retirement obligations in place at the time the compliance period begins.
Commenters asserted that this would ensure that Bui lding Block 2 is fully effective in states like
Tennessee.

Commenters argued that their recommended approach f or plant retirements would have the added benefit of resolving uncertainties regarding combined cycle plants that are currently under509

construction. Commenters stated that these plants a re defined as NGCC units that were in
existence as of the effective date of the section 1 11(b) proposal January 8, 2014 but that were not operating as of 2012. According to the commenters, under EPA's current approach, 15 percent of the generating capacity of an under-construction NG CC is included in Building Block 2's redispatch scenario, whereas the other 55 percent is reserved "to meet other system needs presumed to have motivated the construction of the 'under construction' NGCCs" namely, to replace recent or imminent coal retirements. Howeve r, the commenters argued that, by using 2015 or 2016 data as a baseline, any facilities und er construction as of January 2014 will likely be in operation and can simply be considered existi ng NGCC units. As such, the commenters reported that any underutilized capacity can be inc luded in the re-dispatch scenario described in Building Block 2.

Comment 8: Commenters said that EPA does not have authority t o establish either of the EPA's Building Block 2 phase-in approaches.

Response 8: The EPA disagrees and has explained its authority i n Preamble Section III: Rule Requirements and Legal Basis.

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

Commenters asserted that both of EPA's Building Blo ck 2 phase-in approaches require EPA to have authority that it does not possess. According to commenters, under the first option identified, EPA has suggested, "to the extent that more infrastructure is needed, the methodology for Building Block 2 could be modified on the basis of how much utilization shift toward existing NGCC generation would be possible by 2020. " 79 Fed.Reg. at 64548. Commenters stated that the EPA does not have the authority to prescribe energy policy for a state. Under the second option identified, commenters reported that the EPA has indicated that it "believes that the proposal provides states the flexibility to spe cify appropriate requirements for individual EGUs, including coal-fired EGUs, taking into accoun t the potential for stranded investments and other unit-specific factors." However, commenters r eported that, the EPA provides that if the tools available to the states are "inadequate to ad dress concerns regarding stranded investments, an additional way to address these concerns may be for the agency to take account of the book life of the original generation asset, as well as t he book life of any major upgrades to the asset, such as major pollution control retrofits." Fed.R eg. at 64548-49. Commenters argued that the EPA does not possess this authority; in their state (West Virginia), this authority resides with the
WVPSC.

Comment 9: Some commenters said that the final rule should ac count for remaining useful life of the affected EGU and suggested taking into accou nt the book life of the facility when determining the timeline for attaining interim goal s, while other commenters opposed using the concept of book life.510

Response 9: The EPA thanks the commenters but has determined th at it is not necessary to make any special provision for remaining useful life as the issue is covered by the terms of compliance

with the final rule. See Preamble Section VII.G.

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

Remaining Useful Life

Several commenters argued that the proposal did not adequately account for the remaining useful life of the affected EGUs subject to the rule and t hat any improvements to Building Block 2 and the interim period must also take into account the remaining useful life of affected EGUs.

Commenters complained that the EPA did not consider remaining useful life as required under the CAA, nor does its proposal allow the states to consider it. According to the commenters, the EPA relies upon the purported flexibility affor ded states under its Proposed Carbon Rule, as somehow excusing its failure to consider the remain ing useful life concept. However, the commenters, not all states have the same degree of flexibility under the Proposed Carbon Rule (cites Arizona as such a state). According to the c ommenters, Arizona has a younger coal fleet and Arizona utilities have made large investments i n their coal plants in recent years to comply with EPA regulations. Commenters reported that two coal plants were placed in service less than ten years ago. Commenters asserted that failure to consider the age of coal generating units will result in stranded investment from premature closur e of coal plants, which will have significant retail rate implications and reliability implicatio ns.

Commenters asserted that Arizona is home to some of the newest coal fired units in the country with the most recent units commencing operation as recently as 2009. Commenters expressed that investments assume a long and useful life of 4 0 years or more. According to the commenters, the application of Building Block 2 wou ld require the retirement of virtually all if not all coal generation in the state by 2020, with no consideration to the useful life of the existing coal fleet. Commenters stated that retiring these u nits far earlier than a reasonable planned useful
life would result in excessive stranded costs and r atepayers essentially paying twice for this generation capacity.

Commenters recommended that the EPA adjust the Buil ding Block approach to exclude remaining useful life units from the re-dispatch ca lculation and phase in the application of Building Block 2 evenly over the 2020 to 2030 time period, similar to the application of Building Blocks 3 and 4. According to the commenters, the ad ditional timing will enable more cost effective decision making and reduce the cost and r eliability impacts associated with stranded coal investments and simply defaulting to natural g as for compliance.

Commenters stated that EPA's proposal requested tha t comments be submitted to EPA, so that EPA can determine how to account for the remaining useful life of coal plants, and asserted that the request exposed a fundamental error in the Rule Proposal. According to the commenters, the CAA does not direct EPA to consider remaining usefu l life, rather it commands that the EPA "shall permit the State in applying a standard of p erformance to any particular source under a plan submitted under this paragraph to take into co nsideration, among other factors, the remaining useful life of the existing source to whi ch such standard applies." Commenters further511

stated that the EPA has established emissions targe ts that states are not allowed to alter and, through the NODA and Rule Proposal, withholds the s tatutorily guaranteed power to states to assess useful life (and other factors); rather than giving that authority back to the states, EPA assumes this role itself. According to the commente rs, this is in direct and illegal conflict with the CAA. Commenters asserted that the EPA must prov ide the states the ability to account for the remaining useful life of existing sources and " other factors," which must include the ability to modify the interim and final emissions targets.

Basing the Glide Path on the Book Life (and Remaini ng Useful Life) of a Facility

Several commenters expressed that "book life" of th e original asset and any major upgrades to the asset is a useful way to address concerns about excessive cost due to the stranding of assets with significant useful life.

Commenters believed that the final EPA rule must al low states to consider and use book life and remaining useful life (assuming 40 years) of the or iginal generation asset, as well as consider the impact on book life and remaining useful life of an y major upgrades for pollution control equipment to the asset, even if that results in tho se units operating beyond 2030. According to the commenters, book life and remaining useful life can be used to extend the glide-path or to raise the overall goal. Commenters stated that, for Arizona, five coal-fired generating units have remaining book lives that would result in their eco nomic operation into the period between 2020 and 2030: Cholla (through 2024), Springerville (thr ough 2025), and Springerville (through 2030). According to the commenters, there are also five coal units that have remaining book lives that would result in operation beyond 2030: A pache ST, Coronado, and Springerville. Commenters reported that, absent consideration of b ook life and remaining useful life, the stranded investment in Arizona could be up to $3 bi llion.

Commenters stated that the EPA could either take bo ok life into consideration itself or allow states to do so in calculating state-specific goals

.

Commenters caution, however, that book life is not, by itself, an indication of "useful life." According to the commenters, many assets, including EGUs, will have useful lives that far exceed the nominal "book life" due to care in opera tion and maintenance practices, investment in emissions controls, state prudency requirements, re liability needs, and overall economic value. Thus, the commenters asserted that the fact that an EGU may be beyond its nominal "book life" is not an indication that the EGU is no longer used and useful, is inadequately controlled, or is the subject of inappropriate life extension. Any su ch conclusion would require evaluation of many factors that are beyond the scope of this rule making.

Commenters explained that, book life does, however, present a potentially useful way of better integrating cost considerations related to "remaini ng useful life" into implementation of Building Block 2, consistent with the Act's requirements. Re -dispatch of an EGU to a lower emitting EGU (e.g., forced reduction in EGU usage) prior to the end of the book life, according to the commenters, has cost implications - unrecovered cos ts from running an EGU at a reduced capacity factor or not running an EGU that was expe cted to run for a period of at least the book life and potentially much longer under careful and prudent management as well as costs for replacing that EGU's output. Commenters stated that , if the EGU does not run, those costs that512

would have been recovered during the longer run lif e must still be absorbed by the utility's customers (if investor owned or a non-tax-supported publicly-owned utility), members (if cooperatively-owned), or taxpayers (if the publicly -owned utility is tax supported). Commenters asserted that the earlier re-dispatch (reduced util ization) occurs within the life of an EGU, the higher the cost of that re-dispatch.

In summary, commenters are proposing that EPA modif y the methodology used in Building Block 2 to re-dispatch coal-fired EGUs to NGCC EGUs such that re-dispatch does not occur until the latter of 2020, the end of initial book l ife, the end of 20-year pollution control project book life, or, for EGUs subject to a shutdown or na tural gas conversion requirement prior to December 31, 2029, the date of such shutdown or con version. Commenters expressed belief that it is important to emphasize that their propos al is specifically intended to promote the
calculation of more reasonable and achievable CO 2 intensity targets and is not intended to suggest a date by which EGUs could or should be ret ired or cease burning coal.

Commenters asserted that a book life of 40 years is one way to account for the remaining useful life of the source; however, they believed that the EPA should allow state public utilities determine the remaining useful life of sources in t heir state when setting Building Block 2 targets

Several commenters specifically opposed/conditional ly supported the EPA basing the glide path on the book life of a facility.

Commenters objected to EPA's suggestion that book l ife is an appropriate means of implementing this statutory mandate. According to c ommenters, book life is an accounting and rate-making concept that concerns depreciation. Com menters stated that it does not describe the end of useful life of an asset, which should be det ermined on a case-by-case basis. Moreover, commenters opined that the statutory mandate to con sider the remaining useful life by implication includes the discretion to exempt such sources from regulation.

Commenters asserted that basing the glide path on b ook life does not account for circumstances where continued operation of the facility beyond th e end of its book life is needed for system reliability. Commenters stated that a facility may have an additional 20 years of remaining useful life beyond the end of its book life. Commenters al so stated that building book life into the glide path will not necessarily protect facility owners f rom stranded investments. Commenters reported that facilities selling power into organiz ed markets recover their capital investments according to market conditions, without a recovery guarantee and that operating units beyond the
end of their book lives is therefore often necessar y to recover investment capital. According to commenters, future market conditions cannot be pred icted and states will not be able to predetermine a glide path for these units that ensu res cost recovery. Commenters asserted that, even facilities that sell into unorganized markets, and thus may have some form of guaranteed return through a FERC tariff or state rate, may not be able to recover the costs of pollution
control retrofits if these are not included in thei r respective tariff or rate.

Commenters asserted that "book" life is not the cri teria section 111(d) authorizes states to consider. Instead, commenters reported that states may consider "remaining useful life" which is likely to be very different than "book" life, which depends on application of accounting principles and the Internal Revenue Code.513

Commenters suggested that, if EPA determines to rec ognize book life when calculating state goals under Building Block 2, it should be coupled with other approaches to address the full range of near-term compliance concerns.

Comment 10: Commenters were concerned that the EPA's proposed glide path will incentivize significant natural gas infrastructure in the early years of the compliance period at the expense of renewable energy development.

Response 10: The EPA thanks the commenters. The EPA believes the modifications in the final rule will provide sufficient incentive for renewabl e energy development. See the GHG Mitigation Measures TSD, Chapter 4 and see the RIA for the impact of the rule on renewable

energy.

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

Commenters were concerned with the "glide path" pro posed by the EPA and the incentive it might create to build significant natural gas infra structure in the early years of the compliance period. Commenters recognized the need for some com pliance flexibility early on. Therefore, commenters proposed limited banking and urged EPA t o carefully consider whether the proposed "glide path" will create an early incentiv e to construct significant natural gas
infrastructure that will make it more difficult and expensive for states to reduce emissions through the deployment of renewables and other meas ures in the long term. Commenters reported that natural gas has a history of price fl uctuations, and a low cost in the U.S. in 2014 doesn't guarantee it will remain inexpensive in 202 0 or 2030, particularly given the very high price for natural gas elsewhere in the world and in creasing demand for the product. Commenters recommended that a portfolio of energy resources ca n act as a hedge against price increases in natural gas; particularly as the price of renewable energy continues to decrease. Commenters stated that their plants, for example, use conventi onal steam turbines, and when combined with thermal energy storage have the same operational ch aracteristics of fossil fueled power plants, without their emissions. Commenters also urged the EPA to recognize the speed of solar deployment, along with the modularity of solar, whi ch makes it a great choice for meeting incremental generation needs and can assist states in quickly achieving compliance with EPA regulations under section 111(d). Commenters highli ghted that the development and construction timeline for a large, centralized conventional foss il fuel power plant is typically a multi-year process (and longer for nuclear energy) and that th e time from conception to operation for renewable energy projects can be much faster.

Comment 11: Commenters supported the EPA's glide path approach for Building Block 2 in the NODA if narrowly limited to any existing, binding a nd enforceable agreements between states and operators of coal-fired power plants to cease c oal combustion at a date certain during the interim compliance period.514

Response 11: The EPA thanks the commenters. The EPA has modified the start of compliance and the application of the interim goals and believ es that this revised path does not need the extra provisions recommended by the commenters. See Pream ble Section V.

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

Commenters stated that they would support EPA's gli de path approach for Building Block two in the NODA if narrowly limited to any existing (as of either the proposal or finalization of the Clean Power Plan), binding, and enforceable agreeme nts between states and operators of coalfired power plants to cease coal combustion at a da te certain during the interim compliance period. Commenters asserted that these agreements e ffectively shorten the book life of those plants. Commenters reported that a limited book lif e approach would maintain legally binding commitments in Oregon and the few other states that have already secured agreement to close coal plants and transition to cleaner sources of en ergy during the interim compliance period.

Comment 12: Commenters suggested that states could rely on othe r existing market mechanisms to define emission reduction glide paths (e.g., competitive wholesale markets administered by RTOs).

Response 12: The EPA thanks the commenters. The EPA believes tha t the final rule provides sufficient flexibility and guidance to states that plans can be developed consistent with these comments. In response to additional analysis and ma ny comments, we have modified the proposal and RIA. The 111(d) final rule requires th at states develop plans that establish emission standards for affected EGUs. We are providing state s with substantial flexibility as to how they structure those plans to achieve the 111(d) require ments. The flexibility includes, for example, the choice of approaches, trading, time to develop plans, additional time before the start of the interim performance period (postponed from 2020 unt il 2022), and the ability to shift emission rate achievement between performance periods. The B uilding Blocks are not prescriptive, and states may consider local circumstances as they dev elop their plans, including other regulatory requirements and appropriate mechanisms. See sectio ns V.D, VIII.A, VIII.C and VIII.G of the final rule preamble of the CPP and Chapter 3 of the GHG Mitigation Measures TSD for the CPP Final Rule supporting the final CPP

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

Commenters asserted that states could rely on other existing market mechanisms to define emission reduction glide paths. For example, accord ing to commenters, the competitive wholesale markets administered by RTOs could be use d to define a reduction trajectory for states. Under such an approach, commenters explaine d that states could choose to require in-state resources to include a carbon adder pre-determined by the EPA when bidding resources into the
market. Commenters stated that this would alter the dispatch of units to better reflect their CO 2 emissions and provide a mechanism for continued emi ssion reductions from existing units in a515

way that both respected system requirements and ens ured reliable operation of the portions of the grid administered by the RTOs.

Commenters suggested that the EPA could provide tha t while the carbon adder is used to affect dispatch, states would not be required to file annu al compliance reports or otherwise demonstrate compliance with the proposed guidelines in recognit ion of the fact that the maximum amount of re-dispatch that could be supported by the system o perated by the RTO would be accomplished. Commenters stated that this "safe harbor" would giv e states and electric utilities time to
undertake actions and measures that result in emiss ion reductions later, in recognition of, as discussed above, the infrastructure challenges rela ted to implementing Building Blocks 1 and 2 and the timing issues related to implementing legis lation necessary to implement Building
Blocks 3 and 4. Commenters further stated that it w ould also provide an appropriate incentive to maintain zero carbon resources and avoid (at least in the short term) the concerns expressed
above about the treatment of nuclear resources in t he emission rate formula proposal.

Commenters stressed that, importantly, because the carbon adder relies on existing market structures, it could be implemented soon after stat e compliance plans are approved (and before 2020) to start reducing emissions. Commenters added that, as noted, the EPA should strive to create state flexibility that promotes early achiev ement of emission reductions. Further, commenters suggested that, to address concerns abou t costs for electricity customers, the carbon adder could be collected by the market operators an d then used to offset increased costs to customers, ensuring that electricity remains afford able for end-users.

Commenters suggested that, to support the potential use of this option to define state glide paths, the final guidelines should recognize the value of using existing market dispatch structures to achieve emission reductions and specifically note t hat states could pursue this option as part of an approvable plan. Further, commenters suggested t hat the final guidelines could include a carbon adder value for states to require affected u nits to use when bidding into competitive
markets.

Comment 13: Glide path flexibility should also be applied to o ther methods of compliance (i.e.,

should be available for electric infrastructure dev elopment, should not be limited to coal to gas re-dispatch).

Response 13: The EPA thanks the commenters. The EPA has provided a glide path in setting the state goals for the interim period and increased th e flexibilities in the path in the final rule. The EPA believes that states have the flexibility to ad just their plans to accommodate their own

infrastructure timeline needs within this overall c ompliance glide path. The flexibility in the CPP includes, for example, the choice of approache s, trading, time to develop plans, additional time before the start of the interim performance pe riod (postponed from 2020 until 2022), and the ability to shift emission rate achievement betw een performance periods. The Building Blocks are not prescriptive, and states may consider local circumstances as they develop their plans, including other regulatory requirements, gas infras tructure, and electric infrastucture. See516

sections V.D, VIII.A, VIII.C and VIII.G of the fina l rule preamble of the CPP and Chapter 3 of the GHG Mitigation Measures TSD for the CPP Final R ule supporting the final CPP

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

Some commenters, though supportive of the additiona l "glide path" flexibility proposed by EPA for gas infrastructure development in the NODA for Building Block two, expressed that such "glide path" flexibility should also be applied to electric infrastructure needs.

Commenters requested that the EPA apply the "glide path" flexibility proposed in the NODA to address gas pipeline and transmission infrastructur e ("gas infrastructure") to also address electric system infrastructure ("electric infrastructure") d evelopment where: (1) the 2030 compliance deadline is achievable and (2) flexibility is neede d due to the timing of necessary electric infrastructure development.

Specifically, commenters opined that, while EPA's p roposal provides incremental reliability value relative to the proposed rule, such "glide pa th" flexibility should also be applied to electric infrastructure needs that could impact the overall State Plan's achievability over the compliance period. Commenters opined that such flexibility wou ld better position states, EPA, and entities responsible for reliability to most effectively mit igate and/or respond to potential reliability challenges resulting from electric infrastructure n eeds that require flexibility in the overall compliance strategy set forth in the State Plan, wi thout jeopardizing the 2030 compliance
deadline.

Commenters explained that, while entities affected by the final rule have greater ability to develop electric infrastructure than gas infrastruc ture, electric infrastructure development is still subject to many of the same complexities and uncert ainties as gas infrastructure development, e.g., state and federal permitting processes, const ruction and equipment constraints and/or delays, right of way processes, and other technical and/or legal issues. In particular, commenters reported that, while the responsibility for assessi ng electric infrastructure needs and identifying related projects lies with certain reliability enti ties, the technical, engineering, legal, regulatory

, and financial aspects of such projects lies with th e "owning" entity, which must coordinate all such projects with both state and federal regulator y entities (depending on the regulatory scheme for applicable regulations). Further, according to commenters, where projects involve regional electric systems, such coordination can involve mul tiple state agencies. Commenters reported that, in this way, electric infrastructure developm ent is similar to gas infrastructure development, i.e., it involves multiple entities with different interests and roles, which creates a degree of complexity and uncertainty regarding implementation timing that warrants inclusion of electric infrastructure development in the scope of the addi tional flexibility contemplated in the NODA. More simply put, commenters stated where such issue s justify flexibility for gas infrastructure development, they should also justify flexibility f or electric infrastructure development involving each of the building blocks and their interaction u nder a State Plan. Further, commenters explained that whether and when generation resource s are built (and whether existing electric infrastructure is adequate to serve such new genera tion resources) is a variable beyond the control of relevant reliability entities in many re gions of the country where generation is a deregulated, competitive commercial function. Comme nters asserted that this further supports517

the inclusion of electric infrastructure developmen t with gas infrastructure development in the scope of the additional flexibility contemplated in the NODA.

Commenters requested that the final rule provide th at, where a demonstrated reliability issue would result without construction of necessary elec tric infrastructure, a state or region may depart from the "averaging requirements" for emissi ons reductions during the 2020-2029 compliance period and, instead, propose a more flex ible (or region-specific) "glide path" so long as the 2030 compliance goal is met and affirmative steps are being taken during the compliance period. Commenters respectfully submitted that eith er of these approaches, or a combination of the two, authorized in the Final Rule would provide flexibility that may be necessary due to the complexities and uncertainties of electric infrastr ucture development up front, resulting in certainty as the industry undertakes the significan t actions needed to bring itself into compliance with the final rule's requirements by 2030.

Although commenters supported the application of "g lide path" flexibility to electric infrastructure needs, they wanted to be clear that, while the additional flexibility described in the NODA and in its comments above would provide substa ntial benefits to reliability, such flexibility would not be available where attainment of the 2030 compliance deadline is in jeopardy. Furthermore, according to commenters, the NODA flexibility, even if expanded to electric infrastructure, may not address every situ ation that could arise during implementation of State Plans that may negatively impact grid reliabi lity.

Commenters expressed that additional electric infra structure needs will not be known until State Plans are developed and evaluated; however, it is a nticipated, in both the Proposed Rule and the NODA, that there will be substantial modifications to the overall generation resource mix during the compliance period. According to commenters, thi s is significant because the current electric
infrastructure has been built and maintained to ser ve existing load from existing generation resources. As the generation portfolio changes, in terms of Megawatt output or geographical and electrical locations, commenters asserted that it i s likely that the electric infrastructure necessary to support such shift will need evaluation and upgr ading or additions. Hence, commenters believed that, as State Plans contemplate meeting C O2 reduction goals through means that impact the generation portfolio - e.g., shifts to s ignificantly higher utilizations of natural gas and renewable resources, the Final Rule should accommod ate the complexities associated with the upgrading and/or addition of electric infrastructur e. To address such potential circumstances,
commenters reiterated their recommendation that the "glide path" flexibility designed to accommodate gas infrastructure for purposes of Buil ding Block 2 also be applied to the overall compliance requirements during the interim period, rather than limiting this flexibility to those portions of the glide path associated with re-dispa tching existing resources to less CO2 intensive resources under Building Block two. Commenters stat ed that this flexibility should also apply where: (1) electric infrastructure needs are identi fied; (2) additional flexibility is needed between 2020 and 2029 regarding achievement of interim perf ormance goals and/or expectations in the State Plan for the other aspects of a state plan (i ncluding achievements of building blocks one, three, and four and the interaction of all building blocks in a state plan); and (3) the State Plan still contemplates meeting the 2030 compliance dead line.

Commenters asserted that, as delays in the siting a nd construction of electric transmission infrastructure could impact achievement of complian ce through the use of renewable energy518

goals as much as the use of coal to gas re-dispatch goals and as the need for specific units to provide local voltage support or other localized ne eds could affect units that otherwise might wish to retire placing increased pressure on achiev ing compliance through the use of any other compliance options, the flexibility in developing a more state or region-specific "glide-path" should not be limited to use coal to gas re-dispatc h as the NODA outlines. Rather, commenters asserted that, so long as specific reliability issu es affecting plan achievement can be supported by the applicable reliability authority, the ability o f a state or region to tailor its "glide-path" trajectory should be available as an overall tool t o ensure reliability without being artificially constrained solely to achievement of one particular method of compliance.

Commenters reported that detailing of this RSV-styl e flexibility (and the evidentiary requirements surrounding same) would provide welcom e certainty as the industry undertakes the significant action needed to bring itself into comp liance with the final rule's requirements by
2030.

Comment 14: Commenters recommended alternative glide path optio ns and recommended changes (e.g., defined exceptions, allowance for st ates to depart from strict averaging of emissions, Building Block 2 calculation changes) to the glide path.

Response 14: The EPA thanks the commenters, and has made modific ations that address these issues. In response to additional analysis and many comments, we have modified the proposal and RIA. The 111(d) final rule requires that states develop plans that establish emission standards for affected EGUs. We are providing state s with substantial flexibility as to how they structure those plans to achieve the 111(d) require ments. The flexibility includes, for example, the choice of approaches, trading, time to develop plans, additional time before the start of the interim performance period (postponed from 2020 unt il 2022), and the ability to shift emission rate achievement between performance periods. The B uilding Blocks are not prescriptive, and states may consider local circumstances as they dev elop their plans. See sections V.D, VIII.A, VIII.C and VIII.G of the final rule preamble of the CPP and Chapter 3 of the GHG Mitigation Measures TSD for the CPP Final Rule supporting the final CPP.

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

Several commenters suggested alternative glide path options or recommended changes to EPA's proposed glide path option.

Linear Glide Path

As an alternative "glide path" option, commenters s tated that the EPA could, as they have suggested in previous comments submitted to the EPA , adopt a linear glide path for Building Block 1 and Building Block 2 that is consistent wit h the 10-year glide path provided for Building Block 3 and Building Block 4. Commenters included a n appendix to their comment letter that provides examples of what a linear glide path, comb ined with other proposals they include in their comments, might look like.519

Case by Case Relief/Defined Triggering Events

Commenters asserted that, on a regional approach, t he "glide path" may be achievable. However, according to commenters, there is little flexibilit y in the rule for specific conditions arising eithe r at the outset or during the 2020-2029 compliance pe riod. Commenters opined that this could make the strict averaging of emissions reductions o ver the 2020-2029 compliance period unachievable, in spite of the inter-temporal flexib ility the "glide-path" offers to effectively bank
and borrow emissions rate reductions over the initi al 10-year "glide-path." Commenters suggested that the EPA address up-front any identif ied reliability challenges in one of two ways:

(1) Case by Case Relief - Indicating in the final r ule that a demonstrated reliability issue would allow a state or region to depart from the stricter averaging requirement during the interim 2020- 2029 compliance period and instead propose a more a ppropriate state or regional "glide-path" so long as: (a) the 2030 compliance target is met and; (b) affirmative steps are being taken during the interim compliance period to timely and cost-ef fectively address the identified reliability issues; or

(2) Relief Based on Defined Triggering Events - Ame nding the proposed rule to allow for defined exceptions to meeting the state specific av erage interim target, if specific infrastructure additions are not being added on a timely basis to meet the emissions averaging requirement during the interim compliance period such as additi ons of new electricity transmission or natural gas pipeline infrastructure.

According to commenters, the first approach outline d above would allow for case-by-case determinations to be made initially at the state le vel and ultimately approved by EPA based on specific fact circumstances presented at the time. Commenters reported that the second approach would be more structural in nature by identifying t hose "triggering events" up front in the Proposed Rule and enumerating the process a state w ould use to justify its departure from the averaging requirement presently found in the propos ed rule. Commenters opined that either of these approaches, or a combination of the two, auth orized in the final rule would signal needed flexibility in the final rule (and the evidentiary showing required by a state or reliability entity t o meet the standard) up front rather than simply leav ing the issues to later litigation and enforcement actions during the compliance period it self.

Changes to Building Block 2 Calculation

Commenters stated that, as much as the shift EPA ha s proposed as a part of Building Block 2 is about increasing NGCC utilization, it is also about decreasing steam generation and replacing the services that steam capacity currently provides to the grid. Accordingly, the commenters recommended the following two adjustments to EPA's Building Block 2 calculation:

(1) Commenters recommended that, in developing the proposed state targets, the EPA assume a ramping to a 70 percent NGCC fleet capacity factor in order to provide states with additional flexibility to make sure the infrastructure necessa ry to support this level of utilization is in place or to increase the use of other compliance strategi es.

(2) Commenters recommended that 2012 generation fro m oil/gas steam units be excluded from the goal computation.520

To address the "front-loading" issue, the commenter s recommended that EPA assign to each state a specific annual increase that is calculated based on the difference between 70 percent and the state's actual average annual NGCC capacity fac tor in 2012 (recommendation number 1). (In 2012, the commenters reported that the natural gas prices were relatively low, so NGCC utilization rates were relatively high.) According to the commenters, the EPA could take a range of approaches to introducing NGCC to the goal setti ng equation. Commenters suggested that, to be consistent with the proposed approaches to renew able energy and energy efficiency, EPA could start increasing NGCC from 2012 levels in 201 7 to the 70 percent target in 2029. Alternatively, the commenters suggested that EPA co uld consider reaching the 70 percent level in 2025. Commenters suggested that EPA arrive at a ramping rate that considers the potential system constraints described above.

With regards to the commenters’ second recommended change, oil/gas steam units serve a different segment of the dispatch curve and are oft en used as a backup to coal and natural gas base load generating facilities. In 2012, the comme nters reported that NGCC capacity factors increased significantly and coal steam utilization rates declined. However, the commenters reported, the average utilization of natural gas an d oil steam units was virtually unchanged between 2011 and 2012, demonstrating that utilizati on rates of oil/gas steam units do not correlate with NGCC capacity factors. According to the commenters, by including these units in the goal computation, EPA is setting standards that , in some cases, assume these units are interchangeable.

To implement this change, the commenters stated tha t the EPA would treat 2012 oil/gas steam MWhs like it does "Other Generation" in there-dispa tch analysis, meaning not subject to NGCC re-dispatch. According to the commenters, this woul d avoid situations where the re-dispatch of NGCC capacity would effectively eliminate 100% of o il/gas steam MWhs in the state goal computation and would preserve an element of fuel d iversity that we believe is important to capture in the goal computation.

Commenters recommended a few targeted changes to th e Building Block 2 calculation that, according to the commenters: (1) would not threaten electric reliability; (2) would still result in
substantial reductions in carbon emissions both in Arizona and nationwide; and (3) would be substantially more cost-effective and attuned to th e statutorily-mandated "remaining useful life" concept. The commenters’ recommended changes includ e the following:

• Re-dispatch from coal-fired EGUs to NGCC EGUs shoul d occur upon the later of any of the following, if re-dispatch would occur pr ior to January 1, 2030:

• January 1, 2020;

• January 1 of the year following 40 years after init ial commencement of operation;

or

• January 1 of the year following 20 years after comm encement of operation of significant air pollution controls at any EGU if in stallation occurred prior to issuance of the final 111(d) rule, or after commenc ement of operation of selective non-catalytic reduction (SNCR) or electrostatic pre cipitators (ESPs) at an EGU521 owned by a small utility, as defined by the Federal Energy Regulatory Commission (FERC), if installation occurred prior t o the first year of the compliance period (i.e., 2020).

• For coal-fired EGUs that either shutdown or convert to natural gas-fired operation, re-dispatch would occur as specified in an applicable implementation plan or enforceable Title V permit, provided that s uch commitment is entered prior to the effective date of the final rule and t he date of shutdown or natural gas conversion is prior to January 1, 2030.

• Coal-fired EGUs that do not re-dispatch prior to Ja nuary 1, 2030 remain coalfired EGUs for purposes of calculating the interim and final goals.

The commenters believed that their proposal is cons istent with concepts introduced in the NODA, and would provide significant and much-needed relief to states that would be overly burdened by Building Block 2, with minimal impacts to the overall emissions intensity reductions EPA will achieve with its Proposed Rule. According to the commenters, not only would their proposal accommodate proper considerati on of remaining useful life in setting performance standards for existing sources, but it would ultimately rectify a basic equity issue that they believe is associated with the currently proposed state goals.

Commenters provided a figure to illustrate that the impact of the changes they proposed would be minimal nationwide and that only a handful of st ates would be significantly and disproportionately impacted by Building Block 2 wou ld be affected by their proposed changes.

Commenters supported the Clean Energy Group's alter native proposal that promotes a "glide path" approach for increasing the rate of utilizati on of NGCC plants to ensure reliability is maintained and the goals of the regulation are achi eved. The commenters noted that the following three recommendations are made as a packa ge, and are not meant to be taken separately.

• First, the commenters recommended that, in developi ng the proposed state targets,

EPA assume a ramping to a 70 percent NGCC fleet cap acity factor in order to provide states with additional flexibility to make sure the infrastructure necessary to support this level of utilization is in place or to increase the use of other compliance strategies.

• Second, the commenters recommended that 2012 genera tion from affected oil/gas steam units be excluded from the goal computation s ince oil/gas steam units serve a different segment of the dispatch curve and are o ften used as a backup to coal and natural gas base-load generating facilities, as opposed to a replacement for
those facilities.

• Third, the commenters -- recommended that EPA retai n 10% to 12% of coal steam MWhs in the state goal computation.522

The commenters further stated that other stakeholde rs have suggested a higher capacity factor and suggested that EPA evaluate the viability of a higher capacity factor for states with an increased penetration of natural gas and zero-emiss ion resources as a lower target may, in fact, be appropriate.

Milestone Approach

Commenters favored a milestone approach for measuri ng progress during the years preceding the 2030 goal. Commenters stated that a milestone appro ach would allow for stepped reductions in a manner that comports with the Nevada Public Utiliti es Commission's integrated resource planning (IRP). Commenters further stated that it w ould give states greater flexibility in meeting their final goals and would create meaningful targe ts that take into account planned retirements of coal-fired EGUs. According to the commenters, a milestone approach based on the IRP process would involve measured decision-making taki ng into account various stakeholder interests, including inter alia individual states, tribes, utilities, and ratepayers. Commenters opined that such a process is more likely to result in targets that address stakeholder concerns, such as infrastructure improvements, stranded inves tments, continued safety and reliability of the grid, and overarching federal laws such as the Nati onal Environmental Policy Act.

Shorten the compliance trajectory; create a least-e missions dispatch hierarchy

Commenters stated that the EPA should strengthen ra ther than weaken the compliance trajectory or "glide path" of emission reductions. Commenters believed that, assuming that a life-cycle analysis shows that natural gas plants do outperfor m coal-fired plants, Block 2 should create a dispatch hierarchy that favors the least-emitting s ources (rather than NGCCs only) whenever possible. Commenters stated that under a least emis sions dispatch hierarchy, increasing utilization of NGCC units to 70% of capacity or enc ouraging additional use of natural gas for other means, such as for co-firing at coal plants, would no longer be the goal per se; rather, an ever-increasing use of renewables, and ever-decreas ing use of fossil fuels, should be the policy driver informing the target. Commenters asserted th at the targets for RE and EE should be steeply increased while their phase-in time is shor tened, decreasing the frequency of dispatch to
NGCCs. Commenters added that these measures should make the EPA's concerns about any potential infeasibility of higher NGCC utilization rates unnecessary.

Commenters also noted that the EPA's concerns about the effects of the Proposed Rule on states that currently lack sufficient NGCC capacity to mee t the Block 2 target is focused solely on
whether those states can or should build additional NGCCs. According to the commenters, a least-emissions dispatch approach diminishes or avo ids that concern as it will incentivize the construction of new renewable generation over new f ossil-fuel generation. Commenters pointed out that the EPA has already set extremely low targ ets for those states that have both few renewable energy resources and few natural gas-fire d plants, and suggested these states also can use emission-reducing measures outside of the Propo sed Rule and/or join regional plans.

Commenters concluded that stakeholder fears that so me coal-fired plants may have to stop operating by 2020 even though they have made signif icant capital investments are not legitimate reasons to re-design the Proposed Rule. According t o the commenters, section 111 is concerned with exorbitant costs to the industry, not to a few individual facilities, and in this case the vast523

number of flexibilities in the Proposed Rule assure s that states can comply with their targets in
any event.

Comment 15: Commenters do not support the concept of a glide p ath.

Response 15: The EPA thanks the commenters. In response to addit ional analysis and many comments, we have modified the proposal and RIA. Th e EPA would agree with the commenters that further introduction of a glide path is not ne cessary if the commenters means that extending a nuclear plant life would permit emissions reducti on consistent with the requirements for the interim goal. The 111(d) final rule requires that s tates develop plans that establish emission standards for affected EGUs. We are providing state s with substantial flexibility as to how they structure those plans to achieve the 111(d) require ments. The flexibility includes, for example, the choice of approaches, trading, time to develop plans, additional time before the start of the interim performance period (postponed from 2020 unt il 2022), and the ability to shift emission rate achievement between performance periods. The B uilding Blocks are not prescriptive, and states may consider local circumstances as they dev elop their plans, including other regulatory requirements and the “useful life” of assets. See s ections V.D, VIII.A, VIII.C and VIII.G of the final rule preamble of the CPP and Chapter 3 of the GHG Mitigation Measures TSD for the CPP Final Rule supporting the final CPP.

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

Commenters expressed that, for states like North Ca rolina that have already achieved high heat rate improvements (HRI), there exists little to no room for further HRI in the next few years. Commenters reported that the North Carolina Departm ent of Environment and Natural Resources (NCDENR) does not support the concept of a glide path, and believes that a state should not be denied the right to meet the final go al through infrastructure changes such as extending the life of a nuclear plant or conversion from coal to gas late in the 2020-2029 performance period (were those mechanisms found to be legally authorized).

Comment 16: Commenters requested that the EPA delay the compli ance deadline.

Response 16: The EPA disagrees with this comment on moving the d eadline. In response to additional analysis and many comments, we have modi fied the proposal and RIA. The EPA has determined that the compliance deadline should not be moved, but has added modified the timeline and path. The 111(d) final rule requires t hat states develop plans that establish emission standards for affected EGUs. We are providing state s with substantial flexibility as to how they structure those plans to achieve the 111(d) require ments. The flexibility includes, for example, the choice of approaches, trading, time to develop plans, additional time before the start of the interim performance period (postponed from 2020 unt il 2022, although the final compliance year is 2030), and the ability to shift emission rate ac hievement between performance periods. The Building Blocks are not prescriptive, and states ma y consider local circumstances as they524

develop their plans, including other regulatory req uirements and the “useful life” of assets. See sections V.D, VIII.A, VIII.C and VIII.G of the fina l rule preamble of the CPP and Chapter 3 of the GHG Mitigation Measures TSD for the CPP Final R ule supporting the final CPP.

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

Commenters specifically requested that EPA consider delaying the compliance deadline for the
rule.

Commenters requested that EPA consider a glide path approach that would include eliminating the interim goals from the final rule (discussed in another comment summary) and/or delaying the compliance deadline by five years from 2030 to 2035. Commenters stated that under the proposed rule, significant carbon reductions (80 % of the final compliance requirements) would be needed by 2020 in order to meet the 2020/2029 in terim goals. Commenters stated that a delay of five years would not materially impact the re-di spatch obligation, but would allow time to make the necessary transmission and gas infrastruct ure improvements to accommodate the proposed plant retirements and the construction/ope ration of new gas-fired power plants. As for the impact on the ETCs, the commenters reported tha t a five year delay shifts approximately $1.1 B of $2.9 billion impacts to later years. Also, acc ording to the commenters, operating Nelson 6 and ISES-2 for an additional five years would bring these plants right up to the point when significant expenditures (-$400 million per unit) w ould be required for flue gas desulfurization systems (FGD, or scrubbers) for S02 National Ambien t Air Quality Standards (NAAQS) compliance and Selective Catalytic Reduction (SCR) for Ozone/NOx NAAQS compliance.

Commenters stated that, in order to prepare adequat ely to meet the 2030 emissions target, given the long-term nature of utility operations planning , the majority of the steps taken to achieve those emissions reductions will need to be made pri or to 2020. Commenters asserted that additional time for compliance with the proposed ru le would give utilities more flexibility in the near-term to meet the initial targets, and addition al time in this instance would lower cost and other impacts on electric utility consumers.

3.2.12 Other

This section discusses issues related to building b lock 2 that do not fit in the other subsections of
section 3.2.

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

Comment 1: Commenters stated the EPA should amend the final r ule to prioritize and drive permanent retirements from high-intensity sources.

Response 1: The EPA thanks the commenters. In response to addit ional analysis and many comments, we have modified the proposal and RIA. Th e final rule is designed to drive permanent reductions, but to provide flexibility ab out how these are achieved, rather than driving525

any particular pattern of retirements. The 111(d) final rule requires that states develop plans that

establish emission standards for affected EGUs. We are providing states with substantial flexibility as to how they structure those plans to achieve the 111(d) requirements. The flexibility includes, for example, the choice of approaches, tr ading, time to develop plans, additional time before the start of the interim performance period (postponed from 2020 until 2022), and the ability to shift emission rate achievement between performance periods. The Building Blocks are not prescriptive, and states may consider local cir cumstances as they develop their plans, including infrastructure, and the “useful life” of assets. With attention to reliability, the emission performance rates reflect not maximum stringency, b ut reasonable stringency. See sections V.D, VIII.A, VIII.C and VIII.G of the final rule preambl e of the CPP and Chapter 3 of the GHG Mitigation Measures TSD for the CPP Final Rule supp orting the final CPP.

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

To ensure that the CPP achieves the maximum intende d emission reductions, commenters suggested the EPA finalize the CPP to prioritize an d encourage permanent retirement of the oldest and highest-intensity sources of carbon poll ution. Commenters stated that there is no dispute that there are multiple different approache s to compliance with EPA's CPP, and to some extent, Sierra Club supports the rule's flexibility . Commenters provided modeling analysis to show, however, that the EPA can (and should amend) the final rule to remove any artificial and arbitrary constraints on the deployment of renewabl e energy generation and energy efficiency savings. Commenters stated that, only by doing so, can the EPA drive the kind of carbon emission reductions necessary to meaningfully impac t the spiraling costs of climate change.

Commenters stated they used a modeling tool develop ed by Synapse Economics and ran multiple scenarios assuming that certain coal-burning EGU th at will turn 50 years old during the compliance period actually retires on that date. Co mmenters provided a table on pages 22-23 which lists units, first year operated, the 2011 CO 2 emissions, the announced retirement (MWs) and the Total MWs. Commenters stated that, using EI A's 2012 Form 860 data, Sierra Club also included the installation and operation of planned natural gas projects in Texas listed in a table on pages 23-24, based on EIA data. Commenters state d Sierra Club then ran low-, mid-, and high-renewable energy scenarios based on: (1) EPA's alternate approach for renewable energy growth; (2) baseline or preferred assumptions for g rowth, and (3) the Union of Concerned Scientists' observed annual growth of 1.1% of gener ation for the 2009-2013 time frame. For each scenario, Sierra Club used assumed EPA's baseline e nergy efficiency growth rate and low-bound energy efficiency cost, which for the reasons state d above, Sierra Club believes are also unduly conservative and unrealistically low. Commenters st ated the Sierra Club subsequently incorporated the remaining building blocks and then ran a "business as usual" scenario that assumed EPA's baseline/preferred rate of renewable energy deployment, its baseline energy efficiency assumptions, incorporated building block 1 and 1, but only included retirements that are planned or required.

Commenters stated that these modeling runs demonstr ate that, given the expected addition of natural gas units in Texas, the state will likely b e able to comply with EPA's carbon emission targets relatively easily. Commenters stated that, as a result, the CPP does little to encourage or compel any permanent retirement of coal-burning ele ctric generation units, despite the fact that526

these units are at the end of their useful life. Co mmenters stated the most direct and straightforward means of meeting EPA's overall carbon reduc tion target in Texas would be to simply retire the dirtiest and oldest coal burning plants in the state's fleet, and replace them with renewable energy, energy efficiency, or already-pla nned natural gas generation. Commenters noted that by simply retiring each of these 50-year -old units, Texas could reduce its overall emissions by some 76,874,904 tons--a reduction of m ore than 29% from 2012 levels.

Comment 2: Commenters urged the EPA, when considering stakehol der concerns about the stringency of building block 2 and its technical fe asibility, to maintain the guiding principle of requiring states to first demonstrate technical inf easibility of final targets before adjusting target s based on specific building blocks, or to demonstrat e the costs of implementation are significantly higher than EPA projections (79 FR 34893).

Response 2: The EPA thanks the commenters. The EPA requires st ates to develop plans that achieve the goals of the 111(d) final rule.

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

Commenters urged the EPA to use these expectations to reject attempts by states to demonstrate infeasibility on a piecemeal basis without demonstr ating an inability to meet the final target - as well as to provide sufficiently valid estimations f or significantly higher costs projections.

Comment 3: San Miguel refers the EPA to the expansive comment s of the National Rural Electric Cooperative Association and the Gulf Coast Lignite Coalition for additional issues on this Building Block.

Response 3: The EPA thanks the commenters. In response to addit ional analysis and many comments, we have modified the proposal and RIA. Th e 111(d) final rule requires that states develop plans that establish emission standards for affected EGUs. We are providing states with substantial flexibility as to how they structure th ose plans to achieve the 111(d) requirements. The flexibility includes, for example, the choice o f approaches, trading, time to develop plans, additional time before the start of the interim per formance period (postponed from 2020 until 2022), and the ability to shift emission rate achie vement between performance periods. The Building Blocks are not prescriptive, and states ma y consider local circumstances as they develop their plans, including other regulatory req uirements and the “useful life” of assets. See sections V.D, VIII.A, VIII.C and VIII.G of the fina l rule preamble of the CPP and Chapter 3 of the GHG Mitigation Measures TSD for the CPP Final R ule supporting the final CPP.

Comment 4: Commenters asked for clarification regarding EPA's selection of capacity factors and raised issues regarding the adequacy of pipelin e infrastructure.527

Response 4: The EPA thanks the commenters. In response to addit ional analysis and many comments, we have modified the proposal and RIA. Th e 111(d) final rule requires that states develop plans that establish emission standards for affected EGUs. We are providing states with substantial flexibility as to how they structure th ose plans to achieve the 111(d) requirements. The flexibility includes, for example, the choice o f approaches, trading, time to develop plans, additional time before the start of the interim per formance period (postponed from 2020 until 2022), and the ability to shift emission rate achie vement between performance periods. The Building Blocks are not prescriptive. The building blocks are not requirements, but were used to calculate CO2 emission performance rates, and state s may consider local circumstances as they develop their plans, including other regulatory req uirements, natural gas and electric transmission infrastructure, and the “useful life” of assets. See sections V.D, VIII.A, VIII.C and VIII.G of the final rule preamble of the CPP and Ch apter 3 of the GHG Mitigation Measures TSD for the CPP Final Rule supporting the final CPP

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

1. In 2012, the Natural Gas Combined Cycle (NGCC) flee t capacity factor was 44-46%.
How did the EPA determine that 70% utilization was BSER?

2. What was the technical basis for this determination ? What literature did the EPA rely on and what additional analysis was performed? Why di d the EPA not rely on peerreviewed data? Why is 70% a "reasonable ceiling"? S ee GHG TSD p.3-11. What is the physical maximum technically feasible utilization r ate given hourly variability patterns? See GHG TSD p. 3-15.

3. Why didn't the EPA account for reliability services provided by coal and oil units when determining BB2's 70% re-dispatch requirement? Why did the EPA not consult FERC on
this issue?

4. In integrating BB 2 into specific state goals, the EPA only increased NGCC utilization as much as it could displace coal, however, why did th e EPA not look at coal generations numbers after all other BBs were applied?

5. Why did the EPA not make any attempt to exclude NGC C units with low capacity factors, which would be exempt from 111(d) state pl ans under the proposed applicability language.

6. If the EPA is expanding the applicability criteria for the 111(d) rule, why did the EPA not explain how this impacts the applicability of the 1 11(b) NSPS for new and
modified/reconstructed sources?

7. Why does Table 3-4 of the GHG TSD not demonstrate t he ability for capacity factor growth to facilitate generation growth, but rather name plate capacity growth to facilitate generation growth.528

8. In many states, as coal-fired units are ramped down , the communities they formerly
served will need new transmission connections to NG CC units elsewhere. Why didn't
the EPA consider the additional electric transmissi on infrastructure required?

9. What technical analysis did the EPA undertake to ju stify its assumption that existing gas pipeline infrastructure will expand by a sufficient amount to accommodate BB 2?

10. Based on what analysis does EPA believe this expans ion will occur by 2020? What did EPA estimate the cost of necessary pipeline expansi ons would be? What was the technical basis for this calculation? What pipelin e expertise or authorities did EPA rely on for making these determinations? What was the me thodology for determining what authorities to rely on? Were all authorities peer-r eviewed?

11. Why didn't the EPA account for the fact that capaci ty from NGCC units in one state may already be committed to other states through firm c ontracts (and consequently unavailable for re-dispatch within a state)?

Commenters stated that (1) the EPA proposal entails significant fuel switching from coal to natural gas, (2) most retiring coal plants cannot s imply be replaced by natural gas plants, (3) before this switch can occur, gas infrastructure, i ncluding storage facilities, must be built, (4) the necessary pipelines require permits, and in many ca ses, federal approval, (5) studies indicated the need for more than $300 billion in gas infrastructu re investment between now and 2035 and (6) the EPA projects that its proposal will result in n early 50 gigawatts of retirements of base-load coal generation between 2016 and 2020, creating an even greater demand for infrastructure investment. Commenters asked the following question s:

a. What steps will your Administration take to ensu re the necessary construction of interstate natural gas infrastructure, including pi pelines? Will you consider expediting the environmental impact study (EIS) process so that ga s transmission can be built to serve constrained regions?

b. What is the estimated cost of the gas infrastruc ture required to meet compliance targets under your proposal, and who does the federal gover nment foresee paying for it?

Comment 5: Commenters noted that West Virginia's energy produ cing infrastructure depends on both natural gas and coal, which will affect com pliance with the state’s CCP goal.

Response 5: The EPA thanks the commenters. Coal, as well as na tural gas, will continue to be an important part of the fuel mix under the rule (S ee the RIA for the impact of generation mix.) The 111(d) final rule requires that states develop plans that establish emission standards for affected EGUs. We are providing states with substan tial flexibility as to how they structure those plans to achieve the 111(d) requirements. States ma y consider local circumstances as they develop their plans, including other regulatory req uirements, fuel diversity and the infrastructure. See sections V.D, VIII.A, VIII.C and VIII.G. of the final rule preamble of the CPP and Chapter 3 of the GHG Mitigation Measures TSD for the CPP Fina l Rule supporting the final CPP :529

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

Commenters noted that West Virginia has significant natural gas resources in the Marcellus Shale, and indicated that developing West Virginia' s natural gas resources and investing in natural gas-based electricity generation will help the state comply with the Clean Power Plan and grow the state's energy economy. Commenters stated that the construction of new NGCC plants, co-firing existing coal plants with natural gas, an d building new combined heat and power (CHP) facilities would stimulate demand for West Virginia -produced natural gas, deliver consumers low-cost natural gas-fired electric generation, and provide emission reduction benefits under the
Clean Power Plan.

Commenters stated that despite the benefits of inte grating natural gas into state's electric power sector, combined with the increasingly high cost ofcoal-fired generation, West Virginia's rateregulated utilities have increased their dependence on coal-fired generation by acquiring three coal-fired generating facilities from affiliated co mpanies during the past year. As a result of these investments, commenters believes that West Virginia ratepayers will likely bear higher compliance costs under the proposed Clean Power Pla n, given the inability to avoid the costs of owning these plants while at the same time bearing the increased costs of pursuing opportunities under the third and fourth building blocks of the C lean Power Plan (i.e., renewable energy and energy efficiency). Commenters stated that although these recent acquisitions by West Virginia utilities may represent a step backward for reducin g the state's carbon dioxide emission intensity, natural gas fired generation can play an important role going forward. According to the commenters, the Moundsville station NGCC plant is a nticipated to go into service in West Virginia as early as 2018 and would provide 525 MW of high-efficiency natural gas generation capacity. Commenters noted that this additional cap acity would stimulate additional demand for West Virginia natural gas, provide much needed reso urce diversity, and reduce the emission intensity of the state's power sector.

Comment 6: Commenters expressed the view that a carbon emissi on regulation that targets coalbased power plants without encouraging a clear rein vestment strategy in the sector is impractical and unnecessarily burdensome.

Response 6: The EPA disagrees. The rule establishes emission pe rformance rates. It does not set specific rates for specific power plants, and it pr ovides inherent flexibility in operations. In response to additional analysis and many comments, we have modified the proposal and RIA. The 111(d) final rule requires that states develop plans that establish emission standards for affected EGUs. We are providing states with substan tial flexibility as to how they structure those plans to achieve the 111(d) requirements. The flexi bility includes, for example, the choice of approaches, trading, time to develop plans, additio nal time before the start of the interim performance period (postponed from 2020 until 2022) , and the ability to shift emission rate achievement between performance periods. The Buildi ng Blocks are not prescriptive, and states may consider local circumstances as they develop th eir plans, including fuel diversity and the “useful life” of assets. See sections V.D, VIII.A, VIII.C and VIII.G of the final rule preamble of530

the CPP and Chapter 3 of the GHG Mitigation Measure s TSD for the CPP Final Rule supporting

the final CPP.

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

Commenters noted that coal plays an invaluable role as a fuel for baseload power generation in most markets because it is an inexpensive and readi ly accessible fuel supply shipped on an extensive rail distribution system. Commenters stat ed the EPA's proposed rule creates powerful incentives for coal plants to retrofit with natural gas turbines - a far less universally available fu el (at present) with far greater price volatility. Com menters expressed appreciation that the emissions targets under the rule allow for many pat hs to compliance, but expressed the opinion that there is an effectively unequal treatment of c oal. Commenters asserted that owners in this sector must be allowed greater options for rescuing assets through reinvestment, longer compliance timeframes, and emission offset strategi es.

Comment 7: Commenters stated that as states convert power pla nts to natural gas, it is important that the resulting emissions be included in the sta tes' goals.

Response 7: The EPA thanks the commenters and agrees that the r esulting emissions of existing fossil steam plants converted to NGCC should be cou nted, as this final rule does.

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

Commenters stated that the transition to cleaner en ergy has been underway for decades. Commenters asserted that as Arizona converts its po wer plants to natural gas, it is vital that the resulting carbon emissions, even though they are lo wer than those from burning coal burning, be measured, reported and included in the state goal. Citing the EPA's estimates of the health benefits of the proposed rule, commenters expressed support for the proposed EPA emission reduction guidelines in order to accelerate the pac e of improvement and put targets in place that will promote continuous and measurable caps on carb on pollution.

Comment 8: Commenters contended that the Clean Power Plan upse ts the balance the policymakers in the state of Minnesota have strived to achieve by weighing strong environmental protections with the cost impacts and reliability r equirements in their integrated resource planning process.

Response 8: The EPA thanks the commenters. However, the rule do es not ignore integrated resource planning in states. The 111(d) final rule requires that states develop plans that establish emission standards for affected EGUs, but does not prescribe the choices states make in their plans to achieve their goals. We are providing stat es with substantial flexibility as to how they structure those plans to achieve the 111(d) require ments, so that plans can be consistent with other state approaches. The flexibility includes, f or example, the choice of approaches, trading, time to develop plans, additional time before the s tart of the interim performance period531

(postponed from 2020 until 2022), and the ability t o shift emission rate achievement between performance periods. The Building Blocks are not pr escriptive, and states may consider local circumstances as they develop their plans, includin g fuel diversity and the “useful life” of assets. See sections V.D, VIII.A, VIII.C and VIII.G of the final rule preamble of the CPP and Chapter 3 of the GHG Mitigation Measures TSD for the CPP Fina l Rule supporting the final CPP.

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

Commenters added that EPA's block two biases natura l gas generation but ignores Minnesota integrated resource planning process, which already considers factors such as natural gas price volatility, price risk hedging, and the types of el ectric generation needed to serve their customers. Commenters described specific needs in the state of Minnesota, such as serving metro daily generation peaks with volt swings and intermittent generation support to compensate for wind power down times.

Comment 9: Commenters provided a range of comments on the use of the term "redispatch."

Response 9: EPA agrees with those commenters that recognize tha t the CPP is consistent with current economic dispatch practice, and disagrees w ith those commenters who maintain that the CPP is inconsistent or otherwise problematic for cu rrent planning and dispatch of power. “Redispatch” as used in the proposal was, in practi ce, just the overall annual shifting of generation among resource types. The final rule us es the terminology of generation shifting, not redispatch. However, the proposed rule was intende d and designed to work with current environmental regulations that are consistent with the current security constrained economic dispatch (SCED) protocols and to continue that hist ory of compatibility between environmental regulation and economic dispatch. This final rule reinforces that approach by making clear that the concept of emissions rate trading is part of th e BSER process and can be implemented consistently with the building blocks on which it i s based. See Preamble Section V.

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

Commenters stated that it is important to understan d the EPA's use of the term "redispatch." The Commenters stated that normally, the term "dispatch " is used to define the order in which particular generating plants are lined up to feed e lectricity into the grid. The commenters stated that a number of factors, such as reliability, resp onsiveness of a particular type of generation to changing demand, and the marginal cost of operating the generating plant, go into the dispatch line-up at any particular time. The commenters stat ed that the dispatch line-up works differently in competitive markets, where generation has been d eregulated and therefore owners of generating plants are not guaranteed profits, and t hose where generation remains regulated with a guaranteed rate of return (subject to prudent manag ement). The commenters stated that for instance, in markets where generation has been dere gulated, generation that has the lowest marginal costs is dispatched first - this usually m eans dispatch of utility scale wind and solar generation first, unless there are technical reason s not to do so.532

The commenters stated that the EPA's use of "redisp atch" is not in the sense of a lineup of particular generating stations for dispatch of elec tricity into the grid at specific times; rather it is an estimate for each state of how much additional g eneration can be had from existing NGCC plants to displace coal over a one-year period. The commenters stated that of course, an increase in renewable energy, nuclear energy, hydropower, so lar energy, and other generation can also replace fossil energy. The commenters stated that h owever the EPA chose not to apply the "redispatch" concept to any additional generation f rom these other generation technologies. Yet,
the EPA itself noted in the CPP that "....renewable generation replaces predominantly fossil fuelfired generation and thereby avoids the CO2 emissio ns from that replaced generation." The commenters stated the use of the term "redispat ch" is not the most felicitous in the sense that a lower CO2 energy generation technology can be use d to displace a more CO2 intensive generation method. The commenters stated will use t he term "displace" instead since there is no possible confusion with the function of Independent System Operators (ISOs) who dispatch generation in a particular order at any given time. The commenters stated the term "shifting generation away from fossil units" used in the NODA , as noted above, is equivalent.

Commenters stated the CPP is not in synch with the priorities and operations of regional electric grids. Commenters said that Ohio's utilities are pa rt of the 13-state PJM independent system operator (ISO). Commenters said that PJM dispatches power based on price, with lowest cost generators used first, higher-cost generators used next. Commenters said that this is a sensible approach and in the future, if a singular fuel is m andated by state implementation plans, this normal price phasing would reverse. Commenters said these changes would quickly affect electricity as a commodity; prices would rise; econ omies would shift. Commenters said that businesses' long-term investment decisions would in creasingly exclude the Cincinnati region. Commenters said the CPP needs to clarify whether an d how carbon can be a controlling factor for ISO operations. Commenters said that within the states, steps to control carbon emissions will require deliberate and coordinated planning among u tilities, the ISO and a state's public utility commission and its General Assembly and Governor.

Commenters stated that all ISOs and RTOs use a form of regional, security-constrained, bidbased economic dispatch; commenters stated these re gimes are often designed to co-optimize the dispatch of resources to produce the most efficient combination of energy and "ancillary services". Commenters provided that Section 1.2 of FERC's pro forma Open Access Transmission Tariff ("OATT") defines "ancillary ser vices" as transmission or generation-related services "that are necessary to support the transmi ssion of capacity and energy from resources to loads while maintaining reliable operation of the T ransmission Provider's Transmission System in accordance with Good Utility Practice." [Prevent ing Undue Discrimination and Preference in Transmission Service, Order No. 890, 72 Fed. Reg. 1 2,266 (Mar. 15, 2007), FERC Stats. & Regs. paragraph 31,241 (2007), order on reh'g, Orde r No. 890-A, FERC Stats. & Regs. paragraph 31,261 (2007), order on reh'g, Order No. 890-B, 123 FERC paragraph 61,299 (2008), order on reh'g, Order No. 890-C, 126 FERC paragraph 61,228 (2009), order on clarification, Order No. 890-D, 129 FERC paragraph 61,126 (2009) ( "FERC pro forma OATT")]. Commenters provided that in ISO and RTO regions, se veral ancillary services may be procured from suppliers that offer to sell them at prices de termined by ISO and RTO dispatch algorithms.
Commenters stated that no ISO or RTO has rules or d ispatch software algorithms that would implement environmental dispatch, nor do they have rules or software that would enable them to target a seventy percent utilization rate for NGCCs within their own regions, let alone on an533

inter-regional or even a national level. According to the commenters, FERC Commissioner Moeller has testified, " simply put, the power plants with the lowest operat ing costs are called first to generate electricity - with various reliab ility requirements and other factors as part of the decision, depending on the structure of various mar kets ." [see FERC Perspectives: Questions Concerning EPA's Proposed Clean Power Plan and othe r Grid Reliability Challenges: Hearing Before the Subcomm. on Energy and Power of the H. C omm. on Energy & Commerce, 113th Cong. 3 (July 29, 2014) (written testimony of Phili p D. Moeller, Comm'r, FERC), available at http://energycommerce.house.gov/hearing/ferc-perspe ctives-questions-concerning-epa%27sproposed-clean-power-plan-and-other-grid ("Moeller Testimony”).] Commenters stated that switching to "environmental dispatch" would result in a system in which "units will be called to generate primarily based upon the emission profile of the unit." Commenters stated that Commissioner Moeller has also informed Congress tha t FERC-jurisdictional RTO markets "would need to be fundamentally altered and redesig ned to implement EPA's proposal to accommodate environmental dispatch." [see FERC Pers pectives: Questions Concerning EPA's Proposed Clean Power Plan and other Grid Reliabilit y Challenges: Hearing Before the Subcomm. on Energy and Power of the H. Comm. on Ene rgy & Commerce, 113th Cong. 3 (July 29, 2014) (Answers to Preliminary Questions for the FERC, Philip D. Moeller, Comm'r, FERC), available at http://energycommerce.house.gov/hearin g/ferc-perspectives-questions-concerningepa%27s-proposed-clean-power-plan-and-other-grid (" Moeller Responses")].

Commenters stated that it is, at best, disingenuous for the Proposed Guidelines to emphasize that ISOs and RTOs' existing economic dispatch rules hav e accommodated existing environmental rules on a plant-specific basis, e.g., by permittin g sellers to incorporate environmental costs into
their offers. Commenters stated that this is no def ense; EPA has proposed a radical transformation of electric dispatch rules that is n othing like current RTO rules, and, regardless, EPA has no authority to take such action. Commenter s stated that revising dispatch rules to focus on NGCC utilization rates instead of economic dispa tch would in fact be a radical transformation. According to the commenters, FERC C ommissioner Clark has explained that: "The Commission has allowed RTOs to acknowledge the operating limits of certain plants. Also the Commission allows generators to recognize vario us governmentally imposed costs like taxes and cap-and-trade schemes, but this is simply a mat ter of allowing generators to bid-in costs that they have legally incurred. To go beyond that by ch anging the fundamental market dispatch algorithms in the ways some have suggested would be a major change, to say the least." [see FERC Perspectives: Questions Concerning EPA's Propo sed Clean Power Plan and other Grid Reliability Challenges: Hearing Before the Subcommi ttee on Energy and Power of the H. Comm. on Energy & Commerce, 113th Cong. 3 (July 29, 2014) (Answers to Preliminary Questions for the FERC, Tony Clark, Comm'r, FERC), available at http://energycommerce.house.gov/hearing/ferc-perspe ctives-questions-concerning-epa%27sproposed-clean-power-plan-and-other-grid ("Clark Re sponses")].

Commenters raised questions regarding increased nat ural gas prices that prevent profitable operation, and equipment breakdown. Commenters indi cated that EPA's suggestion to increase re-dispatch of NGCC by limiting the operation of co al-fired EGUs through Title V permits conflicts with federal mandates of large utility pl ants to operate for reliability purposes.

Commenters stated that the proposed rule relies on a flawed understanding of regulated wholesale electricity markets and the bulk power sy stem. Commenters referenced and quoted534

Motor Vehicle Mfrs. Association v. State Farm Mut. Auto. Ins. Co., 463 U.S. 29, 43 (1983) (agency action will be upheld only if it "articulat es a satisfactory explanation for its action including a rational connection between the facts f ound and the choice made") (quoting Burlington Truck Lines, Inc. v. United States, 371 U.S. 156, 168 (1962)).

Commenters stated that all ISOs and RTOs use a form of regional, security-constrained, bidbased economic dispatch; commenters stated these re gimes are often designed to co-optimize the dispatch of resources to produce the most efficient combination of energy and "ancillary services". Commenters provided that Section 1.2 of FERC's pro forma Open Access Transmission Tariff ("OATT") defines "ancillary ser vices" as transmission or generation-related services "that are necessary to support the transmi ssion of capacity and energy from resources to loads while maintaining reliable operation of the T ransmission Provider's Transmission System in accordance with Good Utility Practice." [Prevent ing Undue Discrimination and Preference in Transmission Service, Order No. 890, 72 Fed. Reg. 1 2,266 (Mar. 15, 2007), FERC Stats. & Regs. paragraph 31,241 (2007), order on reh'g, Orde r No. 890-A, FERC Stats. & Regs. paragraph 31,261 (2007), order on reh'g, Order No. 890-B, 123 FERC paragraph 61,299 (2008), order on reh'g, Order No. 890-C, 126 FERC paragraph 61,228 (2009), order on clarification, Order No. 890-D, 129 FERC paragraph 61,126 (2009) ( "FERC pro forma OATT")]. Commenters provided that in ISO and RTO regions, se veral ancillary services may be procured from suppliers that offer to sell them at prices de termined by ISO and RTO dispatch algorithms.
Commenters stated that no ISO or RTO has rules or d ispatch software algorithms that would implement environmental dispatch, nor do they have rules or software that would enable them to target a seventy percent utilization rate for NGCCs within their own regions, let alone on an inter-regional or even a national level. According to the commenters, FERC Commissioner Moeller has testified, " simply put, the power plants with the lowest operat ing costs are called first to generate electricity - with various reliab ility requirements and other factors as part of the decision, depending on the structure of various mar kets ." [see FERC Perspectives: Questions Concerning EPA's Proposed Clean Power Plan and othe r Grid Reliability Challenges: Hearing Before the Subcomm. on Energy and Power of the H. C omm. on Energy & Commerce, 113th Cong. 3 (July 29, 2014) (written testimony of Phili p D. Moeller, Comm'r, FERC).] Commenters stated that switching to "environmental dispatch" w ould result in a system in which "units will be called to generate primarily based upon the emissio n profile of the unit." Commenters stated that Commissioner Moeller has also informed Congress tha t FERC-jurisdictional RTO markets "would need to be fundamentally altered and redesig ned to implement EPA's proposal to accommodate environmental dispatch." [see FERC Pers pectives: Questions Concerning EPA's Proposed Clean Power Plan and other Grid Reliabilit y Challenges: Hearing Before the Subcomm. on Energy and Power of the H. Comm. on Ene rgy & Commerce, 113th Cong. 3 (July 29, 2014) (Answers to Preliminary Questions for the FERC, Philip D. Moeller, Comm'r, FERC)].

Commenters stated that it is, at best, disingenuous for the Proposed Guidelines to emphasize that ISOs and RTOs' existing economic dispatch rules hav e accommodated existing environmental rules on a plant-specific basis, e.g., by permittin g sellers to incorporate environmental costs into
their offers. Commenters stated that this is no def ense; EPA has proposed a radical transformation of electric dispatch rules that is n othing like current RTO rules, and, regardless, EPA has no authority to take such action. Commenter s stated that revising dispatch rules to focus on NGCC utilization rates instead of economic dispa tch would in fact be a radical transformation. According to the commenters, FERC C ommissioner Clark has explained that:535

"The Commission has allowed RTOs to acknowledge the operating limits of certain plants. Also the Commission allows generators to recognize vario us governmentally imposed costs like taxes and cap-and-trade schemes, but this is simply a mat ter of allowing generators to bid-in costs that they have legally incurred. To go beyond that by ch anging the fundamental market dispatch algorithms in the ways some have suggested would be a major change, to say the least." [see FERC Perspectives: Questions Concerning EPA's Propo sed Clean Power Plan and other Grid Reliability Challenges: Hearing Before the Subcommi ttee on Energy and Power of the H. Comm. on Energy & Commerce, 113th Cong. 3 (July 29, 2014) (Answers to Preliminary Questions for the FERC, Tony Clark, Comm'r, FERC)].

Commenters also referred to the FERC Commissioners' statements that the EPA's proposal
would involve a fundamental shift from an economic dispatch system to an environmental dispatch system that would engender considerable co nflict, controversy, and uncertainty for resolution by FERC within its statutory directive t o provide safe, reliable electric service at just
and reasonable rates.

Commenters stated that FERC is not an environmental regulator and has never implemented an environmental dispatch under the FPA or its regulat ions. Commenters stated that FERC has ensured that variable renewable generation -largely wind- can participate effectively in the
wholesale markets without undue discrimination. Com menters stated that it has not, however, ever required a generation dispatch preference for resources based on their emissions characteristics, or given a preference to certain t ypes of generation resources for purposes of setting wholesale power sales rates or regulating t ransmission service.

Commenters stated that FERC Commissioner Philip Moe ller has stated that FERC-jurisdictional
RTO markets " would need to be fundamentally altered and redesign ed to implement EPA's proposal to accommodate environmental dispatch " [see Commissioner Philip Moeller's Answers to Preliminary Questions for the Federal Energy Reg ulatory Commission, House Energy and Commerce Committee, Subcommittee on Energy & Power (July 29, 2014)].

Commenters stated that although EPA professes that any additional regional coordination under the Proposed Guidelines would be voluntary, it appe ars that the rule would, as a practical matter, effectively require further coordination to address the integrated nature of the interstate grid and to reduce compliance costs. [see, e.g., MISO, GHG R egulation Impact Analysis - Initial Study Results at 3, 11, 14 (Sept. 17, 2014) (finding that compliance costs in the MISO footprint could be reduced by approximately $3 billion annually by taking a MISO-wide approach to reducing CO2 emissions compared to making similar emission r eductions on a "sub-regional" basis) ("Initial MISO Study Results")]. Commenters stated that the Proposed Guidelines would mandate new regional coordination, e.g., by effecti vely compelling the creation of multi-state dispatching arrangements in non-RTO regions, expand ing the scope of existing RTO dispatch, or requiring RTOs to coordinate conflicting state plan s

Commenters stated that both regulated and competiti ve electricity markets operate on a lowest cost dispatch model; commenters provided that power systems operate through running the lowest cost generation first, with higher and highe r variable cost units then progressively operated until demand is met. Commenters stated tha t the proposed CPP instead assumes an536

arbitrary dispatch that is completely incompatible with Texas's policy goals of providing the most economically efficient dispatch of power plant s.

Commenters argued that for the members of their reg ional reliability and transmission organization (RTO/RE), both the economic and reliab ility dispatch of EGUs is not determined by the individual plant or the utility at all; those d ecisions are made wholly by the RTO/RE staff regardless of the owner or type of resource, so the EGU cannot implement building block 2.

Commenters stated that implementation of the CPP in RTOs and ISOs will be extremely difficult and raises many significant issues that will need t o be resolved. Commenters said environmental requirements could raise the level of complexity of market operations since there are some
threshold RTO/ISO issues that have not been resolve d by the proposal. Commenters said the first
is the set of issues created when a state is served by more than one RTO/ISO, or even an RTO/ISO and non-RTO/ISO vertically-integrated utili ty as is often the case. Commenters questioned what about states that are in RTOs/ISOs but have utilities that do not belong to the RTO/ISO and have to be dealt with separately?

Commenters asked how does a state determine which R TO/ISO or non-RTO/ISO within the state has which proportion of the compliance obligation?

Commenters asked what if one RTO/ISO uses one compl iance method while the other uses an incompatible method?

Commenters asked what if one RTO/ISO is in a cap an d trade system and the other isn't? How does the state determine proper dispatch of its gen erating plants in these circumstances?

Commenters said since the states don't typically ha ve regulatory control over independent power producers, the commenters questioned whether the st ate can order independent generators to
alter their emissions. Commenters said there are su bstantial equity issues in states, such as decisions on who gets to generate and when they can generate.

Commenters stated in cases of states with multiple entities performing dispatch, it may even be necessary for states to insist on their utilities w ithdrawing from RTOs so that dispatch within the state can be regulated by the state in a manner tha t allows the state to meet the EPA emission requirements in the most efficient way possible for the state, without concerns for regional impacts. Commenters said at the very least, states might insist on a certain dispatch order within the state to be conducted by the RTO so that the st ate ensures that it can meet its obligations at the lowest possible cost. That leads to the questio n of whether and how RTOs could conduct state by state environmental dispatch to meet indiv idual state emissions targets.

Commenters stated the key to RTO/ISO markets is tha t they are based on bids - no seller has to divulge its cost to the dispatcher, and the generat or itself is the one with responsibility to meet any applicable environmental laws or regulations ap plicable to it. Commenters said there are exceptions, such as certain plants may have to run to maintain voltage control in the system and thus reliability. Commenters said in these cases, t he RTO generally has must-run contracts with the generator which specifies when they can be call ed upon and how much they get paid.
Commenters said while each RTO has different rules and operates in different environments, they all have these common characteristics. Comment ers posed this question in order to comply537

with emission targets for the CPP: assuming for the time being that a single RTO/ISO emissions target (or emissions cap) would not be acceptable u nder the rule or cannot be developed by the RTO/ISO members, that without a regional solution, RTOs as the central dispatcher would have the responsibility for dispatching the generation i n each state according to the state's plan for meeting emissions targets. Commenters continued thi s means the RTOs would conduct state-bystate environmental dispatch, and questioned if the y can do that? Commenters said first of all, RTOs have no regulatory authority to dispatch (or o rder a plant to operate). Commenters said it would have to negotiate terms and conditions with e very owner of generation in its geographical footprint, and presumably would need Federal Energy Regulatory Commission (FERC) approval
for each one of those contracts. Commenters had the following questions: ...

Commenters stated that emissions guidelines mandati ng an electric grid system-based approach (i.e., the re-dispatch of EGUs based on a lower CO2 emission rate) should not be part of a 111(d) program; that this type of program could disrupt th e competitive energy market and could place EGUs at risk of early retirement, resulting in pote ntial grid reliability issues; and that the dispatch of EGUs is beyond the scope of the EPA's a uthority, and the regulation of carbon dioxide emissions is beyond the authority of Region al Transmission Organizations (RTOs) and Independent System Operators (ISOs). Commenters not ed that the operation of a competitive energy market is the role of RTOs and ISOs while th e regulation of environmental pollution in a state is the responsibility of the state/local air agencies.

Commenters stated that because of the importance of the underlying issues in Building Block 2 to reliable electric service, national security and resource portfolio planning, Building Block 2 should not be subject to federal enforcement.

Commenters stated that EPA maintains the NSPS for e xisting sources does not need to be a national standard that is achievable at plants thro ughout the country. Commenters remarked that by moving away from source-specific standards that can be met anywhere, EPA is regulating fuel choice and the means of energy production rath er than regulating emissions reductions.
Commenters stated that EPA maintains that electrici ty is fungible, and lower emitting fuels can be substituted for higher emitting fuels, and this policy would enable EPA in the future to claim a nuclear or wind plant obviates the need to build ne w natural gas plants. Commenters believed this regulatory approach enables EPA to de-emphasiz e the importance of fuel diversity in the IRP process and place an ever increasing reliance o n emphasizing CO2 emissions reductions over economic costs, the value of fuel diversity an d electric reliability.

Commenters stated that the re-dispatch measures in building block 2 are not "limited to affected sources" because owners or operators of affected EG Us do not dispatch electricity, citing that in the United States and Canada, Independent System Op erators (ISOs) and Regional Transmission Organization (RTOs) coordinate, control, and monito r the electrical grid, including re-dispatch. Commenters added that in Louisiana, RTOs include th e Southwest Power Pool (SPP) and Midcontinent Independent System Operator (MISO), an d these entities are not affected sources per the proposed rule.

Commenters raised issues about how dispatch under C PP would be managed in RTOs/ISOs

• Can the RTO force a generator to agree to be dispat chable?538 • Can EPA, FERC, DOE, the states (or anyone) force su ch a result? For FERCjurisdictional utilities? For utility-owned generat ion? For independent power facilities? For utilities (such as municipal utilit ies and cooperatives) that are not subject to FERC or state jurisdiction? For Power Ma rketing Administrations? For
PURPA facilities?

• While the federal government can impose limitations on power plant source emissions, can it impose and enforce dispatch requi rements if states or RTOs
can't?

• What new local market power problems or issues aris e as a result of any redispatch regime? What does that mean to end-use cus tomers?

Commenters brought up the following group of questi ons:

• How would the RTO consider economics in determining what plants get dispatched within emission limits.

• Would all plants still bid into the RTO but the RTO would eliminate bids coming in that don't meet a specified emissions limitation in a particular hour?

• And what hours would the RTO limit emissions and by how much, given that the targets are calculate annually, not hourly or daily ?

• And there are security and reliability consideratio ns that must be made as well. A state could decide on a certain dispatch order that has reliability implications in a larger region.

• And as Commissioner Moeller of FERC has pointed out , while a specific generating plant may not contribute much power to t he grid and might be a candidate for shutting down or not running to reduc e emissions, that plant may "have other outputs voltage support or "inertia" qu alities that may contribute significantly to grid stability."?

Commenters brought up the following group of questi ons:

• How does the RTO ensure that enough generation gets enough revenues to ensure that it doesn't retire and remains operational to m aintain reliability, amid what is likely to be a constantly changing base of generati on due to retirements of plants.

• Which plant retirement breaks the back of the syste m?

• Commenters said all plants, regardless of their emi ssions, are going to want to run in the hours with the highest prices. Commenters sa id plants that would be economic to continue running if they run in high pr ice hours might be uneconomic if they are shut out of those hours. Com menters said if they don't get to run in those high-price hours, it may not be eco nomic to keep the plants539 operational and more retirements will result. Will RTOs need to make some extra payments to keep those plants from retiring?

• Who will cover the costs of those payments?

• How is it determined what plants get such reliabili ty payments?

Commenters stated changes in dispatch will change f lows within the transmission system. Commenters said the existing transmission grid is b uilt and maintained based on fairly predictable patterns of load and the location of ge neration. Commenters said it is not clear that existing grids will be able to handle the new flows that result from environmental dispatch, and new infrastructure may be needed. Commenters said t ransmission constraints will change, which will have a feedback effect and may require further changes in dispatch. Commenters said it will certainly take time, and will be costly to build ou t the grid to reliably operate the system with changes in power flows that will result from change s in dispatch.

Commenters stated as Professor Bill Hogan at Harvar d has observed, mandating priority for low carbon technologies in energy dispatch presents mor e complications than might first appear because of the nature of the transmission system in teraction with electricity market design. Commenters said the complex interactions in the gri d mean that changing how demand is met at one point in the grid changes flows in the grid, af fecting multi-plant dispatch that may increase emissions elsewhere in the grid and increase overal l emissions. Commenters said the system impacts of emissions reductions at any particular p lant location are not always easily predictable. Commenters said under environmental dispatch, accor ding to Hogan, "market structures currently based on bids and locational market prici ng (LMP) in a framework of security constrained economic dispatch would confront a subs tantial disconnect between the economic prices applied in the settlements system and the op portunity costs of changes in the dispatch. As we have seen from much experience, whenever market prices used in settlements systems diverge materially from the costs of real system op erations, arbitrage opportunities and temptations are created that could undermine the di spatch and the market." (See Hogan, William W., "Electricity Wholesale Market Design in a Low C arbon Future," prepared for volume on Harnessing Renewable Energy edited by Jorge Padilla and Richard Schmalensee. Draft, January 23, 2010.).

Commenters stated within RTOs, transmission is free flowing, but there are a set of property rights to transmission which are known as financial transmission rights (FTRs). Commenters said owners of FTRs have rights to receive payments from RTOs for those rights, which are based on the differences in LMPs (or the congestion costs) between two locations within the RTO defined by the FTR. Commenters said in many cas es, these FTRs are owned or acquired by load-serving entities so as to be able to hedge aga inst their congestion costs consistent with their planned energy deliveries. Commenters said some RTO s auction FTRs and in some cases they are allocated to load-serving entities, but they ar e a tradable commodity. Commenters said FTRs are important in that changes in an RTO's dispatch methods affect FTR values significantly, and, thus, changes due to environmental restrictions tha t do not have an economic dispatch basis will be extremely controversial as there will be winners and losers created in the FTR markets. Commenters said changes in the value of FTRs result ing from environmental dispatch will have numerous unintended consequences.540

Commenters stated assuming that RTOs are to run env ironmental dispatch based on state direction, within states there will be options as t o what plants to run to meet environmental criteria (and some cases where there may be plants that must run for reliability purposes). Commenters said some of those plants could be indep endent generators beyond the reach of both RTOs and state regulators. Commenters questioned th e following:

• How will fairness be ensured among generators withi n a state?

• Can states even dictate to RTOs how plants in the s tate should be dispatched?

• Can states, RTOs or FERC require NGCC plant owners to operate their plants at higher capacity factors?

• Will NGCC owners demand higher payments to account for increased wear and
tear?

• And what about cases (described above) where there is no NGCC generation to

turn to.

• Who has the responsibility for ensuring gas supply so that the NGCC plants can increase their capacity factors?

• Does the RTO simply not dispatch the coal plants in that state and assume that regional demand will still be met by increased gene ration in other states that have their own targets to meet?

• What if a state or states in the region fail to mee t their target because other states have been leaning on them for lower emissions power ? Commenters said under an environmental dispatch scheme, there would not be a ny price signal to prevent such leaning if generators are bidding their margin al costs as expected.

Commenters stated state-by-state environmental disp atch by RTOs is likely to be extremely inefficient, and RTOs will not be able to take adva ntage of lower cost emission savings in other parts of their footprint. Commenters said it will b e important to understand the implications of an RTO dealing with a patchwork dispatch regime that t reats generators differently depending on the state where they are located. Commenters said p ower flows within the RTO would certainly be affected, and actions taken in one state could h ave detrimental effects on the emissions rate and costs of electricity generation in other states , as it would be inefficient. Commenters said it would no longer be clear what the extra expense of administering an RTO for a region is bringing to the table. Commenters said individual u tilities can environmentally dispatch their own generation just as effectively as an RTO can di spatch their generation, and while the back office systems of RTOs may still have value for bil ling and settlements, it seems all the existing dispatch algorithms and software would become sunk costs.

Comment 10: Commenters believed that EPA should augment buildin g block 2 of the Proposed Rule based on inside the fence natural gas measures so that, if outside the fence measures (such541

as energy efficiency) be deemed illegal as a basis for BSER, the ESPS can still maintain robust emission reduction targets. [EPA could also create an option where the increased use of natural gas inside the fence (including new NGCC and boiler conversions) is a separate building block, e.g. a building block "2A." EPA has created a sever ability provision whereby those building blocks that withstand judicial scrutiny should rema in, if other building blocks are found invalid. 79 Fed. Reg. 34,892. Allowing for these inside the fence natural gas measures to be characterized, in the alternative, as a separate bu ilding block could allow the measures to remain in place as a basis for BSER should other measures not withstand judicial scrutiny.]

Response 10: We appreciate the spirit of the commenters’ recomm endations. For the reasons discussed in section V.A. and V.B. of the preamble and in the Legal Memorandum, our interpretation of the BSER is reasonable and within the scope of EPA’s authority in light of the
statutory text, statutory context, statutory purpos e, and legislative history. Accordingly, we are confident that our interpretation will withstand ju dicial review.