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 Region al approach

................................ ................................ ................................ ......................... 445 3.2.10 Setting a floor

................................ ................................ ................................ ............................... 465 3.2.11 Glide Path

................................ ................................ ................................ ................................ ..... 478 3.2.12 Oth er ................................ ................................ ................................ ................................ ............. 5252 3.2 CO2 REDUCTION PO TENTIAL FROM GENERATION SHIFTS AM ONG AFFECTED EGUS (BUILDING BLOCK 2)

This section addresses comments on CO2 Reduction Potential 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 comment topics of these subsect ions are discussed below along with summaries the specific public comments.

At proposal , we referred to building block 2 as “Re

- Dispatch of Existing Unit s ,” and consequently this is the terminology used by the commenters on building block 2. We have retain ed the original words of the commenters in the comment summaries in this section, although for purposes of the final rulemaking we now 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 assessment of the ability to reduce CO2 emissions by shifting generation from existing coal

- fired EGUs to existing NGCC units.

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

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

Response 1: The EPA disagrees with the interpretation of the Rule. In response to additional analysis and many comments, we h ave 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 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 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 regulatory requirements and planning. 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.3 The following are summaries of the specific public comments under this comment:

Commenter s referenced a study and stated the study finds that short

- term natural gas may be worse than burning coal

. Commenter s stated these results 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 cost

effective.

Response 2: The EPA generally 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 Final Rule supporting the f inal 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 coa l is fully demonstrated. Commenter s stated that the states in the Clean Power Plan Implementation Group have experienced increased utilization of more efficient NGCC units while experiencing decreased generation at the most carbon

- intensive fossil

- fired EGUs. Commenter s elaborated that that for that group of states, electricity generation from natural gas

- fired EGUs increased 37 percent between 2005 and 2012, while generation from more carbon

- intensive coal

- fired EGUs has decreased 36 percent over the same period. 50 C ommenter s stated this sh ift to less carbon

- intensive fossil fuel

- fired generation was a major factor in the 23 percent reduction in carbon emissions achieved by those states over the same period of time. Commenter s referred to success achieved by the RGGI and California's Global Warming Solutions Act which focuses on shifting generation from more carbon

- intensive EGUs to less carbon

- intensive EGUs. Commenter s added that the power sector has been constructing and generating electricity with natural gas in combined cycle natural gas plants for many decades and a significant switch of baseload capacity from coal

- fired steam generation to NGCC has occurred. Commenter s cited EIA data that indicate from 2003 to 2012, coal generation fell from about 2 million GWh to 1.5 million GWh.478, a nd during the same period, natural gas capacity increased from 165 GW to 242 GW and generation climbed 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; com menter s stated that natural gas consumption for electricity generation increased 20 percent from 2011 to 2012. Commenter s said that today natural gas plants are commonly operating as baseload plants, providing 27 percent of U.S. net power generation in 201 3, compared to only 10 percent in 1994. Likewise, commenter s added, the use of natural gas
to co

- fire alongside coal in steam generating plants and the conversion of coal

- fired power plants to operate on natural gas is well established. Commenter s said tha t potential carbon pollution reductions are well established; burning coal to generate a given unit of energy generates nearly twice the carbon at the stack as does burning natural gas to generate the same unit of energy.

Commenter s agreed with the EPA's proposal that increasing utilization of existing NGCC units is a component of the BSER, and noted that this has been demonstrated by the experience of the4 states in the Clean Power Plan Implementation Group. Commenter s stated that NGCC units that
were oper ating in their states in 2005 increased their generation 21 percent by 2012. 51 Commenter s added that this significant increase in utilization at existing NGCCs is a significant component of the system our states have collectively used to achieve emission r eductions a nd improve emissions intensity.

Comm ent 3 : Commenters agreed that significant CO2 reductions are 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 the 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:

Commenter s said that the use of natural gas for power generation has proven to be an effective method of lowering carbon dioxi de emissions. According to the Energy Information Administration, commenter s said, US energy

- related carbon dioxide emissions have declined in four of the last seven years since 2007 and are down a total of 10 percent from 2005 levels due in part to increa sed natural gas

- fired generation. Commenter s described the large role natural gas has played in GHG emissions reductions in the US over the last several years and noted that the proposed Clean Power Plan looks to natural gas to continue this trend. According to the Sustainable Energy in America Factbook, commenter s 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, commenter s added, power generation from combined cycle units and other natural gas generators reached an all

- time high of 30 percent and contributed to carbon dioxide emissions falling to a 20 year low. Commenter s said that these reductions demonstr ate the ability of the natural gas industry and competitive markets to reliably deliver emission reductions without additional regulations. Commenter s concluded that natural gas generation has a proven track record of lowering emissions, and its inclusion in the proposed rule recognizes its environmental benefits.

Commenter s stated that a recent "bottom

- up" analysis of the potential carbon mitigation from re

dispatching the fleet of coal generating units to NGCCs by researchers at the National Renewable En ergy Laboratory (NREL) found that this strategy holds the technical potential to mitigate over 500 million metric tons of CO2, or about 25 percent of the power sector's total emissions in 2012. C ommenter s stated the study found that over 300 million metric tons of CO2 could be avoided at EPA's proposed 70 percent NGCC utilization "ceiling"

Commenter s 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 . Commenter s supported the EPA's approach regarding the increased 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. Commenter s stated that various studies show5 EPA's assumption of 13% emission reductions to be not only feasible, but that dispatch changes could bring about emission reductions of 20% or more. Commenter s referenced the following studies: (1) the Massachusetts Insti tute of Technology 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 dispatch could reduce about 25% of the sector's total emissio ns; and (3) a report by SNL Financial found that output from existing units could be increased by as much as 23 percent, 41 percent, and 55 percent in the areas covered by the SPP, MISO and PJM.

Commenter s indicated that to some extent, the system 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 th eir annual capacity factors by more than 10 percent (from 63.7 to 56.7 percent), according to EIA's Electric Power Monthly. Commenter s pointed out that as a result, electric sector CO2 emissions were at their lowest level since 1996. Commenter s added, howe ver, that this shift in utilization was not consistent across all states, and there are operational considerations that the c ommenter s believe should be reflected in the standard setting calculations.

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

Commenter s stated NGCC units can produce as much as 46 percent more electricity from a given quantity of natural gas than steam EGUs, making re

- dispatch from coal and oil

- f ired EGUs a significantly less expensive way to reduce CO2 emissions than through natural gas conversions

or co

- firing. Commenter s noted this estimate assumes 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

.

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

Response 4: The EPA disagrees. The rule does not mandate that certain units are run. 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 substantial flexibi lity 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 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 reliabilit y, fuel diversity, other regulatory 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 prea mble 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 related to re

- dispatch and reliability, as noted below.

Commenter s stated the EPA has not adequately considered the feasibility or costs related to re

dispatch and premature unit retirements, or considered the effect on system reliability, and there is no analysis of whether the existing transmission system can accommoda te the dramatic changes that EPA's proposal may necessitate. Commenter s requested the EPA to ensure that rules do not mistakenly accelerate the removal of electric generation capacity when corresponding alternatives are not available endangering the availa bility of reliable, base

- load energy, there by endangering our regional, state and national economies. Commenter s noted that Arkansas's coal plants were designed and built to provide baseload power, while the non

- merchant NGCC units were designed to provid e electricity during periods of higher demand and stated that changing the purpose and design of these units so drastically will have a substantial adverse impact on utility rates and the reliability of service.

Commenter s stated that for many existing NG CC units there is simply insufficient pipeline, gas availability, or transmission infrastructure to permit operating year

- round at a 70 percent capacity factor. Commenter s stated that these infrastructure limitations are exacerbated by the fact that the pr oposed state goals are calculated assuming that states will fully implement Building Block 2 by 2020, giving states and utilities only a few years or less in which to expand gas and transmission infrastructure as needed to reach the target level, which c om menter s regard as impossible. Commenter s stated that the infrastructure to transport natural gas to increase the dispatch of NGCC units to 70% capacity factor is inadequate.

Commenter s stated this building block dramatically oversimplifies the ability of one generation source to substitute for another. Commenter s stated that relying on natural gas for high

- capacity factor, baseload operations creates significant dispatch, reliability, and transmission concerns for operators. Commenter s stated that, while n atural gas has played a valuable role in producing high levels of power while load following to support variable power supplies and peak demand, and contributing to system voltage and frequency needs, all of these roles will be complicated by acute fuel su pply and price issues. Commenter s stated that both the Federal Energy Regulatory7 Commission (FERC) and the North American Electric Reliability Corporation (NERC) have expressed concern about the reliability implications of increased natural gas use.

Comme nter s stated that Building Block 2, which is predicated 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 an undesirous market redes ign. Commenter s agreed with NERC concerns that continued assessment of the reliability implications of the proposed Clean Power Plan need to occur, because the over dependence on one fuel type can expose customers to the potential of detrimental price vola tility.

Commenters listed some reliability concerns identified 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 Review at ii (No v. 2014).]

First, NGCC units have traditionally been used for load following purposes, and while some are capable of operating at a high capacity factor, they are generally less well

- suited to serve as baseload resources than coal generation. Second, the P roposed Guidelines would accelerate an ongoing utility industry shift from coal

- to gas

- fired generation, threatening the fuel diversification that utilities traditionally rely on to help to preserve reliability. Third, as the events of the winter 2014 "po lar vortex" demonstrated, 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

ma nage cold weather conditions and threaten reliability. Fourth, Building Block 2's assumption that "the power industry in aggregate can support higher gas consumption without the need for any major investments in pipeline infrastructure" is unrealistic. Th ere are "critical areas," including Arizona, Nevada and New England that already face pipeline constraints, and those areas will need still more pipeline capacity to the extent that coal generation is replaced by natural gas generation.

Commenter s stated that, with the Proposal's assumed significant shift from coal

- fired to gas

- fired generation, the power delivery system's fuel diversification and associated resiliency will be seriously degraded, and its reliability negatively impacted. Commenter s referenc ed the NERC Initial Reliability Review and highlighted the following:

Higher dependence on natural gas can expose additional reliability risks, including pipeline transportation constraints that could result as more gas

- fired generation is built. NGCC uni ts could displace coal

- fired generating units as baseload units, forcing less

- efficient coal units out of service, further increasing demand for natural gas. Adequate timing is required to add new pipeline and generation resource capacity where it is neede d to offset coal plant retirements and supply natural gas to new generation. 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

- congest ion regions, increasing the risk for potential blackouts.

Commenter s stated the EPA over

- estimated the amount of NGCC capacity available for re

dispatch by failing to consider limitations like operational constraints, reliability, infrastructure, and statutory and regulatory barriers that may impede re

- dispatch. Commenter s stated the EPA's8 economic impact analysis failed to consider stranded asset costs and state

- specific employment impacts of such extensive re

- dispatch.

Gas supply and storage

Commenters stated that, unlike coal, gas plants typically have no storage capab ility which can lead to interruptions in service.

Commenter s stated that coal fired plants have on average a thirty

- day supply of energy on

- site, whereas natural gas fired plants typically have no fuel storage capability. Commenter s stated that supplying NGCCs with adequate gas year round will cause some NGCCs to run on liquid fuels or shut down, reducing capacity factors

. Commenter s stated coal has always been the reliable fuel, as coal can be safely and conveniently stored on the plant side removing risk s of failures in the delivery systems such have been experienced by natural gas. Commenter s 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 network of pipelines and bulk gas storage. Commenter s noted that, unlike with coal, the ability to store natural gas onsite at the plant is very limited, making interruptions to delivery service a very serious issue concerning grid reliability.

Commenter s stated that demand for natural gas will grow and the ability to supply the gas may cause interruptions in service. Commenter s added that demand for natural gas is expected to grow in other sectors (e.g., transportation, exports, and manufacturing), furth er affecting its availability for EGUs. Commenter s also noted that an 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 factor

- transportation of larger quantities of natural gas at higher pressure through an aged infrastructure may cause public safety issues that EPA is not appropriately considering. Commenter s stated that a continuous supply is critical to support electr ic generators; however, natural gas is 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 transpo rtation service in the power sector.

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

Commenter s noted that during the winter "polar vortex" in January 2014, NGCC units were unable to come online due to the cold temperatures and natural gas curtailments. Commenter s noted that according to PJM, "Among the challenges for PJM and its members in maintain ing grid reliability during the month were unplanned generator shutdowns from the cold and the stress of extended run times, natural gas curtailments and fuel

- oil delivery problems." 16 Commenter s noted that in Chapter 3 of its Polar Vortex Review, Septembe r 2014, NERC states: "Increased reliance on natural gas during the polar vortex exposed the industry to various challenges with fuel supply and delivery. This increased reliance, compounded by generation outages during the extreme conditions, increased the risks to the reliable operation of the BPS." Commenter s noted last winter's polar vortex weather event in the PJM interchange when over 9,000 MW during a peak demand day of natural gas fired units went into a forced outage due to natural gas fuel curtail ment. Commenter s stated there was simply not enough natural gas9 transportation capacity available to satisfy the home heating and power generation needs of the area. Commenter s stated that on January 7, 2014, when temperatures fell to below zero, near a
qu arter of the PJM operators faltered due to low temperatures, with natural gas generators being 47% off line at one time. Commenter s stated that almost 90% of the planned 7,100 MW of AEP coal unit retirements were called to operate during that time. Comment er s stated that as observed during the 2014 polar vortex, the relationship between gas

- fired generation availability and low temperatures challenges the industry's ability to manage extreme weather conditions

- particularly when conditions affect a wide ar ea and less support is available from the interconnection. Commenter s stated that extreme weather conditions have the potential to strain BPS reliability and expose risks related to natural

- gas

- fired generation availability. Commenter s asserted that with g reater reliance on natural

- gas

- fired generation, the resiliency and fuel diversification that is currently built into the system may be degraded, which NERC has highlighted in recent gas

- electric interdependency assessments.

Commenter s stated that establ ishing a dispatch

- based mitigation goal that impacts other existing generation types without thorough consideration of the impacts to resource adequacy may significantly degrade reliability. Commenter s gave the example that during the extreme cold temperat ures across most of the Southern and Eastern 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 example, commenter s noted th at in the PJM footprint 9,700 MW of gas generation capacity was unavailable due to forced plant outages and another 9,300 MW unavailable due to natural gas supply constraints, such that approximately 36% of the natural gas generation capacity was effective ly forced out.

Commenter s expressed concern regarding the reliability of gas supplies to EGUs and households for home heating purposes. Commenter s stated that implementation of the CPP could raise reliability issues associated with availability and distri bution. Commenter s stated that, in the absence of adding expansive new natural gas pipeline capacity, the current infrastructure in Indiana is limited and may not be able to handle the increased demand for natural gas to both residential customers and EGUs . Commenter s stated Indiana is currently evaluating the infrastructure to determine the effect this rule will have on grid reliability. Commenter s stated that a shortage of fuel capacity during cold Indiana winters could pose serious consequences for resid ential heating needs, as well as grid reliability, and this would present a serious threat to public health and welfare for the citizens of Indiana.

Load following

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

Commenter s indicated that today's coal fleet may not be able to provide adequate flexible operations capabilities for the overall fleet as most existing coal plants were not originall y designed for such duty. Commenter s stated that NGCC units are better suited to follow load and that cycling coal

- fired EGUs reduces heat rate efficiencies, causing their CO2 emission rates (lbs/MWh) to deteriorate, and offsetting the Building Block 1 ass umptions. Commenter s stated that, because some NGCC units were specifically designed and permitted to provide dedicated backup generation for intermittent sources of renewable energy, such as wind and solar

- for10 these units, a significant portion of their capacity would need to be preserved for reliability purposes, limiting the capacity available for re

- dispatch to displace coal

- fired generation and serve base load. Commenter s stated that operational and reliability issues arise as lost dynamic response capabilities to match intermittent load exist when CCNG fast ramp optionality is eliminated. Commenter s stated that by dispatching NGCCs as baseload resource, less capacity is available to quickly adapt to the changing load, making the power system less reliable, or at least

r equiring the addition of more intermediate or peaking capacity. Commenter s stated that, because fuel source diversification helps maintain affordable energy prices and ensure reliability, a greater reliance on any one fuel source, such as natural gas, make s the power system more susceptible to fluctuations in price and availability of that one fuel source.

Commenter s stated that coal

- fired unit generation must remain an integral part of Indiana's baseload power generation to maintain current system reliabi lity. Commenter s stated that, under the Proposed Rule, coal

- fired units historically used for baseload power generation would effectively need to transition into load

- following units. Commenter s noted that, at NIPSCO, current average coal

- fired unit ramp r ates are much slower than the NGCC ramp rate. Commenter s 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. Comm enter s stated that coal

- fired 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. Commenter s stated that more frequent forced outages pose increased reliability risk.

Commenter s stated that the forced re

- dispatching of natural gas generation and the addition of large amounts of renewable energy resources will impact the stability and reliability of transmission grids in varying degrees. Comme nter s noted that coal

- fired generation often provides real and reactive power to load centers; for example, TVA's Gallatin coal plant in middle Tennessee not only is a primary source of real energy needed by the Nashville region, but it also is the source of reactive power that is essential for keeping the transmission grid stable in the area. Commenter s indicated that to shift generation from that plant to a natural gas

- fired plant located elsewhere increases the risk of service disruptions. Commenter s sta ted that the EPA recognized such risks in its enforcement memorandum addressing when it would provide utilities additional time to comply with the MATS rule.

Commenter s 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 intermittency of renewable energy technologies. Commenter s stated that increasing the capacity factors of NGCCs and operating t hem as more base

- load resources reduces their ability to turn down 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.

Commenter s indicated that the EPA's justification that the current NGCC fleet is designed for and is demonstrably capable of reliable operation at 70 percent capacity is based on the NGCC11 fleet's average availability, but such an analysis says nothing of t he reliability of units operating at a 70 percent or greater capacity factor for prolonged periods. Commenter s stated that, while there is little evidence that the 70 percent capacity 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. Commenter s stated that a 70 percent capacity factor would change the purpose and design of the nation's NGCC fleet at

- large, and the E PA must consider whether fleets by state or NERC reliability zones can operate reliably at such a capacity factor. Commenter s referred to several reports concerning reliability. Commenter s asserted that the EPA should defer to the expertise and jurisdictio n of System Operators, NERC, and balancing authorities in ensuring resource adequacy and grid stability.

Commenter s stated the EPA has not adequately considered reliability in the development of state goals under Building Block 2. As an example, commenter s 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 percent from NGCC is not feasible, the reliability implications of this im proper assumption will be very significant and serious. Commenter s 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 displaced coal and O/G generation. Commenter s stated that the EPA does not even acknowledge, let alone adequately address, the constraints preventing existing EGUs from operating at a 70 percent or higher capa city factor. Commenter s added that the EPA completely ignores potential technical or permit limits on NGCC unit operation and dismisses infrastructure concerns. Commenter s asserted that the Agency's primary
response

- that the allowance for "emission rate averaging 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 factor is achievable. Commenters stated the EPA makes no attempt to determine whether each state will have a sufficient number of existing NGCC units that are able to generate sufficient electricity above a 70 percent capacity factor to make up for units that are not able to approach this level . As a result, c ommenter s characterized the Agency's reliance on "averaging flexibility" as "mere speculation or conjecture"

.

Commenter s stated the EPA's analysis of the existing NGCC capacity "available" for re

- dispatch fails to consider reserve margin r equirements. Commenter s stated reserve margin is the amount of generation capacity an entity must maintain in excess of its peak load

- serving obligation. Commenter s stated that erosion of the reserve margin increases the likelihood that MISO would need to manage peak demand through the use of emergency operation procedures.

Commenters stated that the assumption that the capacity factor at all NGCC units can be raised to 70% is an overreach into the resource planning authority of utility regulators. Comment ers said economic dispatch is based on the principle of providing the least cost option from available fleet resources to deliver the required power to the grid. Commenters added that the diverse energy portfolio that Georgia utilities have cultivated less ens rate impacts due to unexpected price shocks. Commenters said the proposed rule takes that option away from the utility and mandates which electric generating units are used irrespective of cost.

Regional Issues12 Commenter s expressed concern that the EP A may not have adequately addressed regional issues that could affect grid reliability. Commenter s stated that the need for, the accessibility to, and the impacts of the increased use of natural gas in electricity generation are not uniform in all parts of the country

- there are regional differences in fuel diversity, the use of firm or interruptible natural gas pipeline capacity by electric generators, natural gas pipeline capacity availability and flexibility, natural gas storage availability, integratio n of variable renewable resources, communication protocols as well as potential reliability impacts or system vulnerabilities that may occur as the generation fuel mix changes in the various regions. Commenter s gave the example that while New England has c oncerns 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 storage and has concerns related to the flexibility needed on the gas side to address challenges associated with the increased deployment of variable resources. Commenter s stated that the electricity sector's growing reliance on natural gas raises concerns regarding the electricity infrastructure'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 already being articulated in light of gas

electric dependency studies and analyses, and include ISO/RTOs, electricity market participants, industrial consumers, national and regional regulatory bodies, and other government officials. Co mmenter s added that the extent of these concerns varies from region to region; however, concerns are most acute in areas where power generators rely on interruptible pipeline transportation as the natural gas use for generation rapidly grows.

Commenter s s tated that the regional nature and complexity of natural gas availability issues have been discussed by FERC Commissioners: Chairman LaFleur noted in 2013 Congressional testimony that "[i]n certain regions, there may be inadequate local pipeline capacity t o 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, Commissioner Moeller has voiced his concern about "whether there will be sufficient pipeline capacity to support this increase in natural gas generation." Commenter s noted that during a September 18, 2014 public meeting convened by Commissioner Moeller, electric gener ation owners voiced 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 pipeline service agreements, a lack of transparency surrounding available services and illiquidity in the natural gas market." Commenter s stated that FERC began examining this issue in August of 2012, and, since that time, electric utilities, system operators and state commissions also have examined the reliab ility issues associated with the increased use of natural gas for electric generation in their respective regions. Commenter s noted that FERC has recently turned its attention to natural gas and electric scheduling in an effort to determine whether and how natural gas and electric industry schedules and practices could be harmonized to achieve the most efficient scheduling systems for both industries. Commenter s stated that in addition to FERC, the RTO/ISOs also are discussing these issues through their sta keholder 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 additional reliability risks, including pipelin e transportation constraints that could result as more gas

- fired generation is built" (Initial Reliability Review at 10). Commenter s asserted that if the organizations charged with maintaining reliability and ensuring the functioning of electricity systems and markets are13 concerned about natural gas infrastructure and gas

- electric coordination, EPA cannot ignore these issues in its BSER analysis. Commenter s stated that chief among these issues are the sufficiency of the current natural gas pipeline infrastr ucture, as well as the financing mechanisms for future pipeline construction and the competition for existing pipeline capacity.

System

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

Commenter s expressed concern that, in projecting a non

- economic dispatch of natural gas EGUs to become baseload generation, EPA's models have failed to recognize that coal plants idled are no longer likely to be economic and wil l be forced to retire, many prematurely, leaving the US with a huge national electric generation reserve deficit. Commenter s 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; transitioning 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. Commenter s stated Building Block 2 i s impractical because it ignores the need to keep coal resources online for reliability support. Commenter s stated PowerSouth must keep a set amount of spinning reserves available at all times under NERC requirements, and to do this it typically keeps at l east one of the Lowman units online at all times. Commenter s stated that, in order to prevent rolling blackouts or brownouts, PowerSouth must be able to dispatch the Lowman coal

- fired power plant in order to maintain stability and reliability under extreme, but foreseeable, loading conditions. Commenter s stated tha t this extra capacity supplied by the Lowman unit (and required by NERC) may prevent the NGCCs from operating at a 70 percent capacity factor. Commenter s noted the power demands during the severe winter season earlier this year and stated that system failu re was avoided only through the sustained peak generation of several coal

- fired power plants. Commenter s suggested that, instead of substituting a method of power generation that is unproven at capacities needed to fulfill grid demands, the EPA should reco gnize the already

- proven reliability of coal

- fired EGUs as the preferred method of power generation.

Commenter s stated that given the system requirements that must be met in order to maintain reliability, even the seemingly simple decision to close a sing le fossil base load unit and replace it with a renewable generator requires consideration 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 infra structure to deliver it, the impact on the transmission system and the need to maintain inertia, frequency and voltage control, and that choosing to increase the generation at an existing unit that already is interconnected to the transmission system requi res consideration of similar issues. Commenter s indicated 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 to go through the inter connection study and analysis process, whether the change is to the capacity of an existing generator or a new generator is proposed. Commenter s described the required studies as follows: "The purpose of these studies is to assess the impact of a new gener ating 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 possible faults in the system that could result in14 cascading failure of the transmission system. No generator can be attached to the transmission network unless and until these studies show that the system can withstand the injection of energy at that particular point. However, these studies only determine whether the system will be harmed by adding the generator or increasing capacity. 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 p oints on the transmission system. The results of this study determine whether transmission upgrades or expansions are needed to accommodate the increased generation." Commenter s noted that MISO's Generator Interconnection Procedures describe these required studies in more detail.

Commenter s stated the EPA did not consider market challenges associated with additional integration of the natural gas and electric markets. Commenter s 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. Commenter s stated that, in evaluating the impacts of increased reliance on the natural gas and electricity market, NERC highlights issues associated with the "planning gap," the period of time in which natural gas delivery needs to be scheduled before a power plant owner or operator knows the extent to which it will be dispatched. Commenter s stated NERC noted that increased reliance on natural gas for elect ricity generation merits increased coordination to address some of the issues associated with this "planning gap." Commenter s stated that when the EPA assumed that natural gas fired power plants could dispatch at 70 percent capacity factors in order to set state based emissions targets, it is not apparent that the Agency considered this challenge which the NERC has identified.

Timing

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

Commenter s stated the Proposed Rule does not allow sufficient time to replace generation capacity that is expected to be retired. Commenter s anticipated that the Proposed Rule would require the retirement of approximately 11 gigawatts of generation capac ity in or around 2020. Commenter s stated that, to avoid reliability and resource adequacy issues, this generation would need to be replaced in a timely manner. Commenter s 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. Commenter s 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.

Commenter s stated that the EPA failed to take into a ccount 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 infrastructure is built, to respond to the Proposed Guidelines' tight time frame and changing generation mix the SPP region will face a significant loss in load and violations of reliability standards. C ommenter s stated under the Proposed Guidelines SPP's anticipated reserve margin would be 4.7 percent, representing a reserve

- margin de ficit of almost 4,600 MW in 2020 and an additional deficiency of 10,000 MW by 2024 Commenter s indicated that given the 8 to 10 year time frame needed to design, permit and15 construct these additional generation and transmission resources, SPP has concluded there is not a sufficient amount of time to achieve compliance with the Proposed Guidelines' Interim Goals and that widespread reliability impacts are likely. Commenter s stated that a Bloomberg Government report illustrated the severe transmission bottlen ecks facing New York. C ommenter s stated that in 2012 the average day

- ahead power prices in New York City (Zone J) were more than $10 per megawatt

- hour higher than prices 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. Commenter s 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 facilities can easily transmit power to displace coal

- fired capacity elsewhere in the state

- but current experience in New York indicates that this is not necessarily true. Commenter s asserted that the EPA did not consider these pos sible transmission constraints.

Commenter s stated Southwest Power Pool (SPP) studies have shown that the EPA's schedule of proposed unit retirements will have severe impacts on system reliability. Commenter s stated that, in a November 2014 "Analysis of EP A's Proposal to Reduce CO2 Emission from Existing Electric Generating Units" report, Midcontinent Independent System Operator, Inc. (MISO)
states:

MISO's review also indicates that the interim targets in the proposed rule will require significant CO2 redu ctions in the 2020 timeframe. This study indicates that this short timeline may not allow cost

- effective, long

- term planning. If coal plant retirements are part of the compliance strategy for 2020, corresponding capacity additions (for reliability and reso urce 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 expan sion, this timeline may be even longer. This finding suggest that in order to meet the 10

- year average identified in the proposed rule, it is likely that entities will need to take immediate action. Since it is possible that state plans will not be finaliz ed until the 2018

- 19 timeframe, there will be little time for decisions and implementation for infrastructure changes before 2020.

Commenter s stated the potential reliability issues of the CPP are being largely overlooked by EPA because the proposal does not consider the coordination of transmission line and gas pipeline infrastructure needed to make the interim targets achievable. Commenter s s tated that expanding the gas pipelines and/or transmission power line infrastructure to accommodate new renewables and NGCC to replace coal requires extensive amounts of time to study, permit and construct. Commenter s stated it often takes providers in our region up to a decade to plan, permit and construct major extra high voltage (EHV) transmission projects, obviously not aligning with the interim time period and barely complying with the final goal. Commenter s stated the CPP's interim goals do not allow the time required to permit and construct the necessary infrastructure for this shift. Commenter s stated that, in the majority of instances, siting NGCC at existing coal generation sites is not possible without the development of new or the extension of ex isting natural gas pipelines. Commenter s stated that, currently, 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 co mes online to comply with the CPP, these new NGCC facilities will quickly diminish existing pipeline and/or transmission capacity.16 Transmission Reliability

Commenters suggested the EPA did not adequately consider the transmission resources needed to imple ment the CPP.

Commenter s stated the changes in the utilization of the various generating plants driven by this proposal could have a significant impact on transmission reliability due to potential large changes in power flows across the system and retireme nt of generation that contributes to transmission system voltage and frequency performance. Commenter s stated that the change in generation will almost certainly require development of new transmission to ensure operational reliability, but scheduling outa ges of existing facilities will be difficult if simultaneous upgrades across many systems are needed such that time lines for commissioning of new transmission facilities may be delayed. Commenter s asserted that to understand the full reliability, economic

, and financial impacts of the proposed rule, detailed transmission reliability evaluations should be conducted. Commenter s stated that the proposed rule considers only the resource adequacy perspective with regard to potential electric system reliability impacts and does not address the potential thermal, voltage, and frequency impacts, nor does the proposed rule consider the associated potential transmission economic implications of additional facilities required to ensure operational reliability or finan cial implications of stranded transmission investments that become underutilized. Commenter s encouraged the EPA to conduct detailed transmission reliability evaluations to understand the full reliability, economic, and financial impacts of the proposed rul e.

Commenter s expressed concern that the proposed re

- dispatch of coal generation to NGCC shifts power generation geographically across the state from eastern Arizona to primarily Maricopa County in west central Arizona. Commenter s stated such a significant relocation of power resources leads to a concentration of generation resources in one area raising reliability issues and creating large infrastructure needs in a nonattainment area to accommodate the shift in generation.

Commenter s expressed concerned th at the EPA's proposal does not identify the consequences on Florida's electric service reliability, transmission load flow, or the scheduling of how its program of displacing existing coal

- fired baseload facilities could reasonably be implemented. Comment er s noted that Florida's coal

- fired facilities and NGCC facilities are not typically co

- located nor generally located within the same utility system, and that in Florida, the existing transmission system has not been developed with the expectation that NGC C facilities would displace all or most of the baseload coal

- fired facilities. Consequently, c ommenter s believe d that it would be necessary to conduct a Florida

- 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 schedule. Commenter s stated that the EPA's NODA appears to acknowledge these are significant and material issues, but no changes to the Proposed Rule were presented. Commenter s indicated that while the EPA has assumed future wholesale level transactions between reliability r egions, it has not provided the commenter s with any support documentation of electric reliability within 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 ommenter s stated they do not believe that electric reliability will be maintained if the Proposed Rule is implemented.17 Comment 5: Commenter s stated that, while existing oil/gas

- fired steam EGUs located in New York City are necessary to comply with four mandatory 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 and potentially lead them to retire.

Response 5: The EPA disagrees. 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 substantial flexibility 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 before the start of the interim performance period (postponed from 2020 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 circumstances 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 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:

Commenter s 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 generation also provides va luable fuel diversity to the state as a whole. Commenter s stated that existing oil/gas

- fired steam EGUs located in New York City are necessary to comply with four mandatory local reliability rules and provided the following additional information regarding these reliability rules and impacts :
These rules are designed to protect against the loss of electric load in the event that there is an interruption in the natural gas supply fueling generators in New York City or a forced outage on a transmission or ge neration 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 reliability rule

- Minimum Oil Burn

- supporte d by gas tariffs and interconnection requirements for New York 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 certain units maintain alternate fuel capability. To prevent such a loss of electric load, these dual

- fueled facilities are required either to run on oil or to enable their auto

- swap capability under certain conditions in order to maintain generation suppl y should the gas supply be interrupted. The other three local reliability rules

- Thunderstorm Alert, Second Contingency Unit Commitment and Locational Operating Reserves

- protect against loss of electric load in the event that an electric transmission fa cility or generation facility serving New York City is suddenly 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 ru les 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 by Building Block 2 would make it impossible to comply with the loca l reliability rules described above and would undermine reliability in New18 York City. Dual

- fuel generation also provides valuable diversity in New York's generating fleet, which is dominated by natural gas burning units. High consumer demand for natural ga s during periods of extreme cold weather over a large portion 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 s carcity and helps avoid interruptions in electric generation when natural gas availability is disrupted. This was vividly demonstrated during this past winter's polar vortex when severe and sustained cold weather threatened natural gas supplies to generato rs. Increased demand on New York's natural gas transmission infrastructure resulted in fuel interruptions to gas

- 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 ensu re that its final goal for New York recognizes the significance of dual

- fuel units to reliability and allows for them to run on oil when necessary because circumstances limit the availability of natural gas as a generation fuel.

Comment 6: Commenters exp ressed concerns with the EPA's approach 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 analysis and many comments, we have modified t he 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 substantial flexibil ity 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 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 reliability, fuel diversi ty, infrastructure, and the “useful life” 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

Commenter s stated that re

- dispatching the bulk of the existing coal fleet to natural gas generation must be done judiciously given that gas

- fired generation is still a sign ificant GHG emitter, and given the uncertain future of natural gas availability and price volatility. Commenter s stated there is not enough existing NGCC in this country, and in Indiana particularly, to make up for the forced reductions in coal generation. Commenter s urged the EPA to reconsider the proposed rules which removes an abundant, and widely utilized nature resource from the nation's energy19 mix in such a dramatic and expeditious fashion, thereby hindering the reemergence of manufacturing in the nat ion's heartland and moving carbon emissions to global competitors with less pollution controls.

Fuel Diversity

Commenter s stated that a balanced approach to fuel diversity is necessary to maintain reliability and affordability. Commenter s stated that their current generation mix provides the Orlando Utilities Commission (OUC) with the ability to switch between coal and natural gas as needed based on the market price conditions, fuel supply challenges and extreme weather. Commenter s noted that, once the oper ation of gas transportation 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.

Commenter s expressed concern th at the proposed rule would remove coal EGU's from the electrical generation portfolio in Nevada and relies totally on NGCC for base load power. Commenter s stated this is contrary to PUC goals, which seek portfolio diversity in order to maintain relative pr ice stability in electrical markets and mitigate the potential for fuel supply disruptions. Commenter s noted that coal units have the ability to stockpile fuel on site, whereas natural gas units receive their fuel through pipelines and are therefore vulner able to pipeline disruptions. Commenter s stated the FERC reported that, during last winter's cold weather, numerous natural gas generators were forced to cease generation because of interruptions in pipeline deliveries, both because of the physical inability of frozen pipelines to deliver natura l gas and because suppliers cut off interruptible load to serve other load under much higher spot prices. Commenter s stated the EPA failed to consider these real and negative consequences in determining that every state's "best" utility system should entai l the wholesale substitution of natural gas for coal.

Commenter s stated that NERC has determined that the CPP will cause a generation shortage. Commenter s stated that natural gas units are best suited to follow load, rather than serve as base load units. C ommenter s stated that employing diverse fuel sources (coal

- fired in addition to NGCC and renewables, when available) ensures a secure and reliable energy supply. Commenter s stated that reduced reliance on coal

- fired power, combined with increased reliance on NGCC, will decrease diversification of fuel sources which will constrain the power grid's ability to respond to unforeseen events such as regional transfers, labor strikes, unplanned outages and abnormal weather conditions. Commenter s noted that, durin g the 2014 polar vortex the following fuel delivery complications were encountered: (1) natural gas interruptions (supply injection, compressor outages, and one pipeline explosion); (2) oil delivery problems; (3) inability to procedure gas; and (4) fuel oi l gelling. Commenter s stated that low temperatures during the polar vortex hindered power generation in the following ways: (1) low temperature limits for wind turbines; (2) icing on hydro units; (3) failed auxiliary equipment; (4) stress of extended run t imes; and (5) frozen instrumentation.

Reliability

Commenter s stated the EPA should not presume that coal units can be retired or curtailed in favor of increased natural gas generation because coal generation and natural gas generation20 serve different func tions, with coal units required to ensure grid stability. Commenter s stated that coal and natural gas generation are not interchangeable such that each kWh of increased natural gas generation replaces on kWh of coal generation.

Commenter s referred to the E PA's IPM run results and stated the Proposed Rule would effectively eliminate coal

- fired generation from PowerSouth's generation portfolio. Commenter s stated this has long

- term implications, including impacts to PowerSouth's ability to provide reliable and affordable service to its members. Commenter s stated the EPA cannot systematically phase out coal

- fired EGUs. Commenter s explained that, if external factors affect natural gas delivery, PowerSouth can rely on the coal resources in its fleet to meet demand . Commenter s stated the ability to choose from a suite of fuel options during resource planning retains fleet flexibility and reliability, and also ensures that economic and efficient electricity is provided to our members. Commenter s stated the additional baseload generation capacity projected to retire due to the Clean Power Plan would increase the risks of brownouts, load curtailments, and other power disruptions in regions impacted by these retirements

. Commenter s 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.

Commenter s stated the shift to NGCC will eliminate stability in the energy market beca use gas

fired technology is not as mature and reliable as coal

- fired generation. Commenter s 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. Commente r s 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. Commenter s stated that, if the utility i ndustry 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 energy can be generated at all times, particul arly during prolonged maintenance outages.

Commenter s stated that, as SPP delineates, there are significant reliability impacts resulting from the forced closures and other modifications to baseload generation output required in order to comply with the proposed Rule. Commenter s stated that, in addition, MISO addresses the fact that reserve margins (the cushion electric generating entities must have to avoid outages when unexpected events occur) will fall well below what is needed to support the regional electric grid. Commenter s stated the EPA should be mindful of the fact that the Arkansas Electric Cooperative Corporation must comply with RTOs' mandates, which are derivative of their FERC

- jurisdictional authority and when the reliability coordinators ra ise red flags, those warnings should be carefully considered.

Commenter s cited a NERC report and stated that extreme weather events highlight the need for adequate reserve margin and fuel diversity. Commenter s stated that many regions relied on coal

fired generation, with a ready fuel supply stored on site, for grid reliability during these conditions, while the Proposed Rule anticipates that many of these same units will be retired in or around 2020.

State

- Specific Concerns21 Commenter s expressed concern t hat the combination of Building Blocks 1 and 2 in New York results in a scenario where certain reliability

- must

- 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 cl ose as the economic viability of the operation would erode to unsustainable levels. Commenter s stated that the complete eradication of coal

- fired units from New York's fleet presents concerns related to fuel diversity and reliability. Commenter s stated that coal remains a viable option for grid operators to mitigate unexpected natural gas contingencies: it can be stored

on

- site and units can be operated to follow load variations, unlike nuclear which is much less flexible.

Commenter s noted that i n the EPA's goal setting methodology for Building Block 2 under Option 1, it essentially retires all coal capacity in 11 states (Alaska, Arizona, California, Connecticut, Massachusetts, Mississippi, Nevada, New Hampshire, New Jersey, Oregon and Washington) and replaces that generation with existing NGCC. C ommenter s stated two of these states (Oregon and Washington) have announced the retirements of their entire coal

- fired capacity as a result of various state agreements, but the remaining nine states have o nly announced the retirement of some of their existing coal capacity and have plans to keep their remaining coal fleet operating into the future. Commenter s stated that the EPA's calculated requirements show a disconnect between the operational reality of the U.S. electric system and the Agency's assumptions. Commenter s stated that the 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 meet demand in Arizona, Massachusetts, Mississippi, Nevada, and New Jersey.

Commenters expressed concern that there is a disconnect between EPA's assumptions related to NGCC re

- dispatch in Building Block 2, and the EPA's modeling of state compliance with Opti on 1 goals. As an example, the commenters noted that the EPA's Building Block 2 calculations displace (retire) all of Arizona's existing coal

- fired capacity; however, IPM's 2025 results for Option 1 under a state approach indicate that Springerville Units 1 through 4 will be needed to generate 5,653 GWh of electricity, which is equivalent to 23.2 percent of the state's 2012 coal

fired generation. Commenters asserted that, in assuming a state can shift all of its coal

- fired generation to its NGCC units witho ut taking into account the reliability needs of specific electricity markets, the EPA shows a lack of understanding of how electric utilities plan and operate to meet electric demand and ensure reliability of the grid. Commenter s stated that even more coal capacity would be needed if EPA had properly applied summer capacity (as opposed to nameplate capacity) for NGCC.

Commenter s expressed concern that, with the re

- dispatch of NGCC to a 70% capacity factor combined with the unobtainable RE and EE targets included in the calculation of Mississippi's CO2 goal, it is very likely that under the EPA's rule as proposed, SMEPA's coal fir ed generating facility, Plant Morrow, will be forced into early retirement. Commenter s also expressed concern over the impact the Clean Power Plan will have on the Plum Point Energy Station which is a coal fired generating plant located in Oscelola, Arkans as. Commenter s referred to Attachment A to their comments which express some of these concerns.

Stranded Investments22 Commenter s stated that, to preserve the investment Georgians have made and avoid stranded costs, EPA should remove from its calculations of the state goal the assumption that all existing NGCC units statewide can be ramped up to a 70% capacity factor. Commenter s stated that the draft rule summarily discards billions of dollars in investment Georgians have made in state

- of

the

- art emissions co ntrols on coal

- fired units. While the Georgia Public Service Commission has already approved the retirement of approximately 3000 megawatts of generation, EPA's proposal assumes that Georgia will retire another 3900 megawatts of coal

- fired generation in re sponse to this rule, thereby stranding the investment in those generating units, including billions of dollars' worth of environmental controls.

Commenter s stated that implementation of the proposed re

- dispatching would require premature closure of Missis sippi's remaining coal fleet, even though many of these units have taken recent steps to comply with the MATS rule by spending millions of dollars in control retrofits. Commenter s stated that full implementation of Building Block 2 is not an option for the se units because it would cause these upgrades to become stranded assets to the rate payers of Mississippi. Commenter s stated that, under the proposed application of Building Block 2, Mississippi would completely lose its fuel diversity with a projected ze ro coal and oil/gas steam power generation by 2020, which is an unacceptable result. Commenter s stated that removing fuel diversity jeopardizes power reliability and removes the ability to control power costs for consumers. Commenter s requested that the im pact of Building Block 2 on Mississippi's proposed goal align with the stated intent of the proposed rule, which is to reduce carbon emissions "while maintaining an affordable, reliable, and diverse energy mix". Commenter s suggested the EPA consider evalua ting the state's fuel usage profile for an acceptable level of natural gas usage prior to determining whether re

- dispatching is even necessary. Commenter s noted that, in 2012, Mississippi's NGCC generation provided for 73% of the total generation from its affected fossil fuel

- fired EGU's and stated that this percentage rate is more than sufficient to satisfy an acceptable NGCC generation requirement while still affording the state the opportunity to utilize a diverse energy mix. Commenter s stated that re

- dispatching to NGCC capacity for the Mississippi fleet does not consider the intended utilization of the units. Commenter s stated that many of Mississippi's units were not designed or included in the power system to provide extended power g eneration. Commenter s stated that many of these units were designed to chase peak demand and a detailed assessment of unit utilization would need to occur before many of the units could be committed to a high

- use re

- dispatch plan.

Commenter s stated that, while implementing Building Block 2 threatens to prematurely close several of OG&E's coal

- fired EGUs by requiring greater utilization of existing NGCCs, EPA's NODA proposes modifications to the CPP that would almost certainly lead to closures. Commenter s s tated these measures contravene Section 111(d) by forcing displacement of coal

fired EGUs with significant remaining useful lives. Commenter s stated section 111(d) requires EPA to take into account the remaining useful lives of the sources it regulates. Co mmenter s stated that, despite this provision, EPA did not assess the remaining useful lives of OG&E's and others' coal

- fired EGUs that are poised for closure under the Proposed Rule. Commenter s stated shutting down OG&E's coal

- fired EGUs will cause untold damage to local communities, including job losses at OG&E facilities and elsewhere in the supply chain, stranded investments, and reductions in revenue. Commenter s stated the abruptness of the transition risks destabilizing energy production and threatens reliability. Commenter s 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. Commenter s expressed concerns regarding unintended consequences sure to flow from the imposition of an arbitrarily high and hastily imposed shift from coal

- fired to natural gas

- fired generation.

Commenter s stated the EPA has not considered that re

- dispatch ing 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. Commenter s stated most 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 resulting from re

- dispatch could result in inadequate generation c apacity during peak load periods.

Commenter s supported the modifications proposed by the Arizona Utilities Group (AUG). Commenter s stated the AUG proposal requests EPA consider the remaining useful life and asset value of Arizona's coal plants, together w ith lowering CO2 emissions to achieve meaningful long

- term reductions. Commenter s stated the AUG proposal would mitigate the sharp cliff projected under the EPA interim goal for the State, thus providing a smoother glide path for emission reductions. Final ly, AUG's proposal would also lower the cost burden to be borne by

consumers.

Commenter s stated that, because South Dakota has only a single natural gas generation plant

- the Deer Creek Station, which is owned by Basin Electric Power Cooperative, the Deer Creek Station would need to operate at greater than 70% capacity, a level it was not designed for, to offset the loss of power from reductions at coal

- fired power plants. Commenter s stated the re

dispatch of Deer Creek Station to a level of 70% capacity w ould 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.

Commenter s expressed concern that, in projecting a non

- economic dispatch of natural gas EGUs
to become baseload generation, the EPA's models have failed 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 deficit. Comm enter s 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 transitioning these plants to mezzanine or peak period units results in insufficient r evenues to carry the staff and fixed costs that baseload coal plant must maintain to remain viable.

Comment 7: Commenters stated that the EPA has not considered the role of NGCCs in an integrated electric system. Commenters noted that utilities provide ancillary services to balancing areas to ensure reliability and availability of electricity to customers, which include scheduling, system control, and dispatch; reactive supply and voltage control; regulation and frequency response; energy imbalance; oper ating reserves; and supplemental reserves.

Response 7: The EPA disagrees that we have not considered the provision of ancillary services

. 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. The24 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

ac hieve 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 em ission rate achievement between performance periods. The Building Blocks are not prescriptive, and states may consider local circumstances as they develop their plans, including system reliability, fuel diversity, the need for “ancillary services” and othe r regulatory requirements. 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:

Must

- Run Requirements

Commenter s stated that re

- dispatch of NGCC resources may also interfere with NERC compliance requirements regarding capacity reserves, spinning reserves and similar requirements. Commenter s 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. Commenter s stated that coal generators serve an impor tant function in providing local reliability support, including black start capabilities (the ability to restart without any electrical input), voltage stability, and other ancillary services. Commenter s stated that, as a result, certain coal facilities ma y be "reliability must run" units which cannot be retired without imperiling local grid reliability. Commenter s cited a Western Electricity Coordinating Council study (2022 Resource Options, July 25, 2013, p. 51): "The path rating for Path 8 [the Montana t o Pacific Northwest corridor] is currently highly dependent on remedial action schemes that are directly linked with the coal

- fired and hydro generation in Montana. There are inertial concerns in the area. The local balancing authorities have advised cauti on when running studies that dispatch renewable generation before coal

- fired and hydro generation. In reality, the rating on Path 8 may have to be decreased when these conventional resources are backed down, or turned off completely."

Non

- Generation Servi ces

Commenter s stated that units located in New York City are required to run in order to provide needed voltage support and frequency stability in this heavily

- populated urban center. Commenter s stated that, while unit upgrades and re

- powering with natur al gas have dramatically improved the emissions profile of in

- city

- generation over the past decade, the system cannot maintain stability and reliability without these key resources.

Commenter s stated the EPA ignores non

- generation roles that certain power plants serve, as black start capability and voltage support, often dependent on coal power plants. Commenter s stated it is arbitrary and unreasonable for EPA to ignore these factors when makin g assumptions about the displacement of coal generation. Commenter s stated the EPA's proposal assumes that electricity generation is completely fungible and that NGCC facilities can substitute completely for coal

- fired electric generating units (EGUs). Com menter s stated this approach ignores the

non

- generating services that coal

- fired EGUs provide to the electricity generation and25 transmission sectors. Commenter s stated that coal

- fired EGUs may be located strategically to provide voltage support and other g rid reliability benefits and that existing and under construction NGCC facilities at other locations cannot replace these functions. Commenter s stated that certain coal

- fired EGUs may be designated as black start facilities that are capable of restarting w ithout any electricity input or for other reasons may be designated as must run facilities by FERC or regional transmission organization (RTOs). Commenter s stated these coal

fired EGUs cannot be retired and replaced by existing or under construction NGCCs. Commenter s stated that, because electricity generation is not truly fungible, there may be circumstances where coal generation is necessary, even if NGCC facilities are operated at 70 percent capacity. Commenter s stated this is particularly true in States where EPA's BSER analysis projects that coal

- fired generation will cease entirely.

Commenter s stated that it is important to note that all generating resources do not provide the same services to the electric grid and that all electrons may not be able t o serve all customers due to electric transmission or other constraints

- different sources are needed to ensure that electrons actually reach end

- users. Commenter s indicated that while all generating units produce electricity, some types of units only sup ply energy, others supply critical grid services (balancing, back

- up and ancillary services like voltage 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. Commenter s added that renewable generation units can provide electrons, but are limited in their ability to provide grid or peak period capacity services. Commenter s asserted that retirement of base load coal

- based units diminishes the poo l of resources that are able to provide these other services to the grid and places increased responsibility on natural gas based resources to serve as base load units, back up renewable resources, provide ramping capability and provide ancillary services to the grid.

Commenter s stated that adequate transmission and generation infrastructure, as well as other essential services, are critical for the reliable operation of the integrated grid, and that system operators do not have complete flexibility in the procurement of these services, many of which are often referred to as "ancillary services," as they often need to be provided by units in specific locations due to the physics of electricity. Commenter s noted that reactive power, for example, does not "tra vel" over distances and is, therefore, a "local" requirement that can be provided only by a few resources when needed. Commenter s indicated that FERC recognizes the following as ancillary services: scheduling, system control and dispatch; reactive supply a nd voltage control from generation service; regulation and frequency response service; generation and energy imbalance service; operating reserve

- synchronized reserve service; and operating reserve

- supplemental reserve service (Order Nos. 888, 890). Ac cording to the commenter s , 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 service s, for wholesale sales and purchases of electric energy under open access tariffs. (Commenter s added that black start service, an additional ancillary service, is a voluntary service that can be provided by some, but not all, generation resources. These
ge nerating units have the ability to go from a shutdown condition to an operating condition and start delivering power without any outside assistance from the electric grid. Hydroelectric facilities and diesel generators have this capability. These are the f irst facilities to be started up in the event of a system collapse or blackout to restore power flows in the grid. See FERC Primer at 37.) Commenter s stated that ancillary services, in addition to capacity and energy, are necessary26 to support the transmis sion of electric power from seller to purchaser, given the obligations of control areas and transmitting utilities within those control areas, to maintain reliable operations of the interconnected transmission system, and that ancillary services are so ess ential that FERC also requires that transmission service providers

- absent third

- party service

- provide them to ensure the reliable delivery of electricity.

Commenter s added that natural gas units are vulnerable to pipeline disruptions while coal units h ave the ability to stockpile fuel on site. Commenter s 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 for coal. Comm enter s referred to an April 1, 2014 FERC report regarding last winter's cold weather during which numerous natural gas generators were forced to cease generation because of interruptions in pipeline deliveries, both because of the physical inability of fro zen pipelines to deliver natural gas and because suppliers cut off interruptible load to serve other load under much higher spot prices.

Commenter s also expressed concern that the EPA's calculation of each state's best system fails to account for fuel

- pri cing stability. Commenter s provided 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 natural gas prices have been volatile.

Ramping and Regulation

Commenter s stated that NGCCs are often necessarily utilized for ramping (Scheduling, System Control, and Dispatch) and regulation (Regulation and Frequency Response) to maintain reliability and availability of electricity. Accordin g to the commenter s , any constraint on NGCCs' operation flexibility, such as proposed by EPA in Building Block 2, hinders these units' ability to serve their historic purpose, thus impacting reliability. Commenter s explained that "ramping" is a load following requirement and requires units to generate more or less as the system load or demand requirement progresses throughout the day, while "regulation" relies upon faster generating resources that respond to system demand changes from minute to minute (or even shorter durations). Commenter s 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 fact ors such as system demand, a unit's cost, a unit's ability to respond to ramping and regulation needs, and the system's capacity mix. Commenter s added that depending on the time of the year, different unit mixes may be committed to meet expected demand sha pes while still providing capacity to meet ramping and regulation needs, and that the system load shape often dictates the type of resources that will be committed to serve load. Commenter s provided a figure with examples of seasonal load shapes over a 24

- hour period for the winter, spring/fall, and summer seasons.

Commenter s described the differences between the typical load shapes in winter (a double peak and a mid

- day valley) and summer (a more uniform load shape, peaking in the afternoon) in the Southe rn Company footprint, and noted that a winter month's ramping and regulation requirements can be quite different than a summer month's requirements. Commenter s described the different roles that NGCCs may play during winter 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 operating states (e.g., 1x1, 2x1, Full Pressure, Power27 Augmentation) with minimum up and down times of approx imately 8 hours. Commenter s stated that it is not uncommon for NGCCs to operate at lower output levels to ensure that a unit is available to meet the system's ramping or regulation needs and in addition, as system demand reaches a minimum level during a gi ven time period, the ability of NGCCs to reduce output further (turndown) is valuable. Commenter s added that because NGCCs serve several different roles over the course of a year, they may maintain different capacity factors across the seasons. Commenter s indicated that historically, NGCC's have run at higher capacity factors during the summer, but it is important that these units maintain operational flexibility throughout the year to assist in meeting load. Commenter s provided figures illustrating NGCC qu ick 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 cour se of a 24

- hour day in winter; and the capacity factor for NGCC units in summer, transitional seasons, and winter.

Commenter s stated that requiring NGCCs to generate at a 70 percent capacity factor, despite system economics, will hinder system operations because NGCCs would not be available to provide critical regulation, ramping, and turndown needs for system reliability. Commenter s indicated that other units would need to perform these duties

- impacting system reliability and generation costs. According to the commenter s , the EPA modelers recognize the turndown constraints of other technologies (e.g., coal and oil/gas steam) in that the EPA's IPM Base Case v.5.13 maintains turndown limitations to "prevent coal and oil/gas steam units from operating stric tly as peaking units, which would be inconsistent with their operating capabilities". Commenter s also indicated that within IPM, the Agency states that the "[t]urndown constraints often override the dispatch order that would result based purely on the vari able cost of generation", and that the EPA states, "[T]he turndown constraints in EPA Base Case v.5.13 require coal steam units to dispatch no less than 50% of the unit capacity in the five base

- and mid

- load segments of the load duration curve [LDC] in or der to dispatch 100% of the unit in the peak load segment of the LDC. Oil/gas steam units are required to dispatch no less than 25% of the unit capacity in the five base

- and mid

- load segments of the LDC in order to dispatch 100% of the unit capacity in th e peak load segment of the LDC".

Commenter s also stated that almost all of Southern Company's NGCC fleet (excluding IGCC and CHP units) is Automatic Generation Control (AGC) capable. Commenter s indicated that maintaining AGC capability allows a unit to dynamically follow system demand in 10 minute time increments, which is necessary to serve regulation and frequency requirements. Commenter s added that NERC also requires minimum amounts of regula tion and contingency reserves to respond to unexpected system conditions and maintain system frequency

- commonly referred to as Control Performance Standards 1 (CPS1) and Control Performance Standards 2 (CPS2). Commenter s asserted that NGCCs are an import ant part of fulfilling these NERC requirements

Commenter s stated that as unit pricing has changed over time, so have the types of units fulfilling system regulation needs. Commenter s provided a figure showing a comparison between 3 years of the types of u nits regulating the Southern Company system (i.e., the units on AGC), which illustrates the relative percentages of regulation performed by resource types. Th e comment ers presented three pie charts , which show the changes in percent utilization of various sources for AGC over the period from 2008 to 2012. Commenter s asserted that as 23 percent of28 Southern Company's 2012 AGC resources close or transition to gas, Building Block 2's dispatch requirement that further limits units available for regulation become s more problematic. Commenter s stated that as demonstrated in the figure, the units performing regulation requirements can change as fuel prices change. Commenter s indicated that NGCCs are being called upon more often to perform regulation and as additiona l coal

- fired EGUs switch fuel or retire, NGCCs will be asked to perform even more regulation. Commenter s concluded that maintaining NGCCs' future flexibility is important to ensure regulation needs are met, and that operational limitations, such as EPA Bui lding Block 2, will impede NGCCs from performing regulation.

Commenter s stated the EPA fails to consider the role of NGCCs in an integrated electric system in asserting that s tates can set a standard based on achieving a fleet

- wide capacity factor of 70 percent. Commenter s 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). Commenter s explained that ancillary Services commo nly refer to services provided by the utility to help ensure reliability and availability of electricity to customers. These services may include: Scheduling, System Control, and Dispatch; Reactive Supply and Voltage Control; Regulation and Frequency Respo nse; Energy Imbalance; Operating Reserves; and Supplemental Reserves. 8 Commenter s stated utilities provide ancillary services 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 quick ramping capability. Commenter s 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).

Commenter s 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. Commenter s stated that, as system demand reaches a minimum level during a given time perio d, the ability of NGCCs to reduce output further (turndown) is valuable. Commenter s stated that some NGCCs may cycle across the day while other NGCCs stay online through a single ramp up and ramp down cycle. Commenter s stated that expecting NGCCs to genera te at a 70 percent capacity factor despite system economics and the need for ancillary services will unnecessarily complicate system operations at the least and impinge on reliability at the worst; in those circumstances, NGCCs would not be available to pr ovide critical regulation, ramping, and turndown needs for system reliability. Commenter s stated other units would need to perform these duties, thereby impacting reliability and generation costs; thus, any constraint on NGCCs' operation flexibility, such as proposed by EPA in Building Block 2, hinders these units' ability to serve their historic purpose. Commenter s stated this reliability concern is exacerbated because emission reductions through the other building blocks are infeasible; therefore, NGCCs w ould likely be required to operate at an even higher capacity factor to compensate for the lack of reductions possible under the other building blocks.

Commenter s stated NGCCs often are utilized for ramping needs (scheduling, system control, and dispatch) and regulation (regulation and frequency response). Commenter s stated that ramping requires units to move up or down as load varies throughout the day while regulation provides faster resources that respond to system demand changes minute to minute (or sh orter duration). Commenter s stated that employing a mandate of 70 percent 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 serv ice requirements. Commenter s 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 more renewables, (2) removing coal units, and (3) hindering more nimbl e units' (NGCCs) ability to respond to the resulting system needs. Commenter s stated these factors increase cost, reduce reliability, and complicate system planning needs.

Safety

- Valve

Commenters suggested the EPA should include "safety valves" to allow u tilities to ramp up a coal facility, rather than increase natural gas generation, to address short

- term conditions when dictated by reliability and safety. Commenter s noted that in very cold winters, the price of natural gas spikes and, in addition, increa sed natural gas generation is dependent upon adequate pipeline capacity. Commenter s stated that the reliability safety

- valve would be similar to the one

year compliance extension used to avoid retirement

- related reliability impacts due to MATS. Commenter s stated that there is no consensus as to what would trigger the safety

- valve. Commenter s stated the EPA should allow states to include a safety valve in their state plans to address situations where the increased dispatch of NGCC units could affect reliabil ity.

Comment 8: Commenters expressed concern that, as the industry relies more on natural

- gas

fired capacity to meet electricity needs, it is important to examine potential risks associated with increased dependence on a single fuel type.

Response 8: The EPA dis agrees that we have inadequately considered 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 flexibility as to how they structur e 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 many comments, we have modified the proposal and RIA

– the establishment of CO2 emission reduction standards 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, extreme events, o ther 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 Mitigation Measures TSD for the CPP Final Rule supporting the final CPP.
The following are summari es of the specific public comments under this comment:

Area

- Specific

Commenter s stated a large

- scale shift toward natural gas, especially beyond what Florida utilities are already planning, would greatly increase risks and reduce the state's fuel flexibility and diversity. Commenter s stated these risks and the need to have flexibilit y 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 supply. Commenter s stated the reliability of the entire state's electrical grid is i n jeopardy if we become more dependent on natural gas as the primary fuel source. Commenter s stated that price spikes in natural gas, like those that occurred in 2008, would have bigger impacts on customers' electric bills with less fuel diversity and a
gr eater reliance on natural gas. Commenter s stated the only way for Florida to achieve EPA's proposed reduction goals would be to use new zero

- carbon generation, and the options there are limited.

Commenters stated that in 2012, Florida utilities had 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 of which is already committed to the import of out

- of

- state generation to mee t the state's current and future power needs. Commenters stated that Florida's reliance on natural gas as a generation 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 with Florida's current dependency on natural gas generation pales in comparison to EPA's modeled projection that by 2025 Florida will be using natural gas generation to serve 85 percent of load.

Commenters stated that Florida law requires the FPSC to determine the need for new generating facilities and specifically to consider the need for electric system reliab ility 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 rele vant CO2 standards because a diversified fuel supply can enhance system reliability and significantly mitigate the effects of volatile fuel price fluctuations, extreme weather events and unplanned plant outages. Commenters stated that additional pipeline

c apacity would have to be built to accommodate a further reliance on natural gas as a generating fuel. Commenters stated that one of Florida's primary pipelines crosses the Gulf of Mexico and is subject to some risk of hurricanes, which adds to the concern of diminished fuel diversity.

Commenter s stated that the EPA's proposal threatens fuel diversity. Commenter s stated that the EPA's estimates for building block 2 in Louisiana, if utilized for SIP purposes, would entirely reconfigure the state's economic di spatch 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 commenter s , the EPA's analysis suggests 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 natural gas

- fired generation as forecast by the EIA in its most recent Annual Energy Outlook. Commenter s stated that t his considerable change in Louisiana's power generation configuration may very well lead to a significant increase in ratepayer costs as well as potential service interruptions. Commenter s quoted NERC as saying: "the power industry relies upon diversificat ion 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 "all

hazards" appro ach to system planning, which inherently provides resilience to the BPS." Commenter s indicated that with the current plans for retirement of coal

- fired capacity and the additional retirements estimated to result from the EPA's proposal, the U.S. electric p ower industry will need to compensate for over 100 GW of retired coal

- fired capacity. Commenter s31 stated that the EPA's proposal threatens to exacerbate this shift in the resource mix further threatening fuel diversity. Commenter s included a table (titled: “Building Block 2, Louisiana NGCC Units”), which shows listing the NGCC units included in the EPA's CPP baseline calculations for Louisiana, which provides base year (2012) generation, the estimated generation level arising from EPA's Building Block 2 anal ysis, the percent increase this generation represents relative to base year 2012 level, and the highest generation utilization levels for each NGCC unit over the past 10 years and 5 years. Commenter s 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. Thus, based upon the EPA's analysis, Louisiana should adopt policies that promote (or incent) one of its more efficient CHP unit s to operate at a lower, rather than higher operating efficiency. Substantially increased utilization would be required from the remaining units 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 cons iderable increases in generation are unrealistic for the implementation time afforded by the EPA for CPP compliance. The two columns that present the highest generation utilization levels for each NGCC unit over the past 10 years and 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 reached a level close (63 percent) to that assumed in the EPA's second building block, which it reached only in the 2012 base year. Over the past 10 years, Carville has operated, on average, around 50 percent and has operated at an average utilization of 57 percent over the past five years. On average, most Louisiana EGUs (excluding Louisiana Station No. 1) repor t 10 year average generation utilization levels of 20 percent and five year average utilization levels of 32 percent, both of which are significantly lower than the EPA's target of 70 percent.

Commenter s noted that ERCOT released a "Gas Curtailment Risk Study" in March 2012 that details risks related to curtailment and recommended that the EPA consider these risks. Commenter s stated that gas curtailment is a concern for electric generators who rely on nat ural gas, particularly in winter months when residential demand is high and supplies are jeopardized by freezing temperatures. Commenter s stated that limitations on natural gas pipeline capacity in Texas occurred during the very cold weather in February 20 11 and 2014, when a large amount of gas was being consumed for home heating. Commenter s stated that, with increased reliance on gas for electric generation, there will be an increased risk of having to curtail NGCC generation. Commenter s stated that relyin g on one fuel source so heavily will have unintended consequences on reliability and customer health, safety and costs; having and maintaining a diverse fuel portfolio is a safer and lower risk approach.

Commenter s stated that regional deliverability for the Midwest is in question and noted 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 r esidential and commercial customers.32 Extreme Events

Commenter s expressed concern that reduced reliance on coal

- fired power combined with increased reliance on NGCC will decrease diversification of fuel sources which will constrain the power grid's ability to respond to unforeseen events such as regional transfers, labor strikes, unplanned outages and abnormal weather conditions (as shown during the winter of 2014

- 14). Commenter s stated there is not enough existing NGCC generation in this country to make up for the forced reductions in coal generation and the gas supply and infrastructure in this country are not available or reliable enough to serve all the gas generation that will be needed. Commenter s stated this leaves a significant gap between the amount of energy that can be generated in compliance with the CO2 goals and the amount of energy that must be generated to supply reliable electricity to the population. Commenter s stated that natural gas units are best suited to follow load, rather than serve a s baseload units and employing diverse fuel sources (coal

- fired in addition to NGCC and renewables when available) ensures a secure and reliable energy supply.

Commenter s stated that with this shift toward more natural gas consumption in the power sector, the power industry will become increasingly vulnerable to natural gas supply and transportation risks. Commenter s indicated that overdependence on a single fuel type increases the risk of

common

- mode or area

- wide conditions and disruptions, especially dur ing extreme weather events. Commenter s referenced a September 2014 NERC report and stated that adverse winter weather, such as that experienced during January 2014, provided signs of natural gas supply and natural gas supply and deliverability risks. Comme nter s stated that this can be a local issue in areas where there is already a heavy concentration of natural gas generation. Commenter s added that while there are several plants with dual

- fuel capability, the capability to switch to a secondary fuel can be limited during certain operating conditions. Commenter s stated that an analysis of the CPP prepared by Energy Ventures Analysis (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 reach 35 percent in 2020, 39 percent in 2030, and 49 percent in 2040. Commenter s asserted that as reliance increases more on natural gas for both baseload and on

- peak capacity, it is important to also examine potent ial risks associated with reduced diversity and increased dependence on a single fuel type.

Commenter s stated that generally, 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. Commenter s added that fuel diversification is also a component of an "all

- hazards" approach to system planning, which inherently provides resilience to the BPS. Commenter s 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 Analysis maintains a complete list of announced power plant retirements in the contiguous United States, retirements as of 10/02/2014) (mostly due to MATS), the power industry will need to replace a total of 103 GW of retired coal

re sources by 2020, largely anticipated to be natural

- gas

- fired NGCC and CTs. Commenter s stated that considering the current and ongoing shift in the resource mix, the EPA proposes to further accelerate the shift, lessening the industry's diversification of fuel sources.33 Commenter s stated natural gas units are best suited to follow load, rath er than serve as baseload units. Commenter s stated that employing diverse fuel sources (coal

- fired in addition to NGCC and renewables, when available) ensures a secure and reliable energy supply. Commenter s stated abnormally cold temperatures impact fuel d elivery and the ability of the power grid to run reliably. Commenter s stated reduced diversity in power supply restricts the power sector's ability to respond to these events. Commenter s stated that, during the 2014 polar vortex the following fuel delivery complications were encountered: (1) natural gas interruptions (supply injection, compressor outages, and one pipeline explosion); (2) oil delivery problems; (3) inability to procure gas; and (4) fuel oil gelling. Commenter s stated that low temperatures du ring the polar vortex hindered power generation in 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. Commenter s stat ed Hoosier Energy experienced some of these adverse impacts during the polar vortex: physical limitations combined with differences in operational structure of the natural gas and electricity markets made it extremely difficult to obtain fuel and run the H olland Energy facility; as a result the plant ran only four days from 1/1/2014 through 3/31/2014 and the facility had a capacity factor of only one percent based on MWh versus potential.

General

Commenter s stated that natural gas supply to all users is a "just in time" supply system, meaning any disruption in the supply chain causes immediate hardships to the consumers of natural gas. Commenter s stated that, without reliable natural gas, utilities have gene rally turned to coal which can be stored on site and carries much less risk on the supply side. Commenter s stated a diversified electric strategy at any utility is needed to assure the availability of fuel to supply the electricity to meet customers' needs . Commenter s stated that electric reliability is a major concern for CWLP, whose mission, as a municipal utility, is to provide our citizens with reliable, affordable energy (not profits). Commenter s stated that, while the electric industry is spending maj or capital to increase reliability and reduce risk for grid reliability on cyber security and physical security, our nation's overall energy policy under the GHG Rule introduces more risk into reliability than any outside threat may provide. Commenter s sta ted 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 customer s. Commenter s stated 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 electric 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 (les s reliability).

Commenter s stated that both the timing and stringency 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. Commenter s stated that, from a reliability perspective, it is essential that base load generation (coal and nuclear) remain a feasible and cost

effective source of generation to meet existing and future energy needs. Commenter s stated that

over

- reliance on any one dispatchable generation makes the electric system vulnerable to price34 spikes, distribution disruptions, and even intentional human acts such as vandalism or terrorism. Commenter s stated it is unknown how operating at such a level will impact the long

- term reliability and efficiency of such facilities. Commenter s stated that the extent of these concerns varies from Region to Region; however, they are most acute in areas where power generators rely on interruptible natural gas pipeline transportation.

Commenter s expressed concern that a "prolonged dash to gas" will lead to over

- reliance on one fuel type and have adverse consequences for the balance and diversity of the power sector and the economy. Commenter s stated that the increased use of natural gas to generate electricity will put stress on the natural gas system, which is presently designed to meet peak winter heating needs, by requiring increasingly larger supply and flow rate to power plants. According to the
commenter s , this increased reliance on natural gas has already contributed to rapid price spikes in the cost of gas, which translates into much higher wholesale electricity prices. Commenter s 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 be fore extensive re

dispatching decisions are made.

Response 9: The EPA dis agrees with the interpretation of the rule’s requirements, or that the analysis of 111(d) inadequately addressed reliability.

. 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 su bstantial 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 peri od (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 reliabi lity, 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 Mitigation Measures TSD for the CPP Final Rul e supporting the final CPP.
The following are summaries of the specific public comments under this comment:

Commenter s stated that, as NERC has pointed out in its November 2014 Preliminary Reliability Assessment, the EPA's proposal will result in changes in the resource mix and new dispatch protocols that require comprehensive reliability assessments to identify changes in power flows and electric reliability services including: (1) load and resource balance; (2) voltage support; and (3) frequency support. Commenter s stated the EPA has not undertaken these assessments; for example, as the system experienced this past January 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. Commenter s stated this problem will become ever more challenging as demand from gas

- fired generation increases in the future.

Commenter s stated the Clean Power Plan's interim target 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 resources and complete the necessary evaluations to ensure a reliable electric system. Commenter s indicated that the us e of the Building Blocks in the proposed rule to meet emission targets will significantly affect balancing areas throughout the Western Interconnection in that implementation will result in resource retirements, changes in operating practices, changes in t raining procedures used by operators to control the electric system, changes in the capabilities of the transmission system, changes in how the transmission system is operated, a requirement for new transmission resources and transmission upgrades, changes in levels of natural gas

- fired generation used 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. Commenter s gave some examples of the ch anges 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 is critical. Commenter s stated that at present, states have only begun to plan for the impacts of implementing the proposed regulation, and asserted that it is imp erative that each state have sufficient time to implement its own compliance plan.

Commenter s asserted that it is not tenable for Nevada to meet the interim goal with Building Block 2 for the following reasons (which are addressed in greater detail elsewh ere in this document):

• System reliability has not been sufficiently evaluated to be able to retire the affected coal

- fired EGUs in northern Nevada by 2020.

• A 2020 retirement date fails to take into account the remaining useful life of the coal

- fired EGUs.

• Closure of the coal

- fired EGUs without new generation 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 would 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 site additional transmission is a lengthy one and unlikely to be accom plished 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 simple. The facilities would not likely be able to use the same footprint because new NGCC units must be36 cons tructed before closure of the coal

- fired units to ensure continuity of reliable service.

• New pipelines will have to be constructed, and siting 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.

Commenter s supported the Nevada State Agencies' position 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. Commenter s stated the coal plant 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 natur al gas and renewable energy generation. Commenter s stated that an assessment of Nevada's ability to reach the proposed interim and final goals should consider the planned retirement of almost all of Nevada's coal EGU capacity by the end of 2025, as coal re tirements can be used in place of a re

- dispatch strategy to achieve emission reductions.

Some c ommenter s responded to points made by other c ommenter s :

• Commenter s agreed that reliability is a critical concern that must be addressed. Commenter s noted that the WECC and other entities are working hard to analyze effects on balancing areas from Clean Power Plan modifications, and that Nevada has shown leadership by planning to join the Energy Imbalance Market being piloted by PacifiCorp and the Cal ifornia Independent System Operator (CAISO), which will help bring more renewable resources into play for participants to utilize. Commenter s added that the National Renewable Energy Labs (NREL) is conducting a long

- range analysis, the Renewable Energy Fut ures Study of how to integrate high levels of renewable energy onto the grid, which is extensive and detailed. Commenter s stated that Commenter s 22732 should submit specific concerns to the NREL for analysis in this plan so that any potential issues can b e addressed upfront, which would include addressing the voltage support concerns related to North Valmy.

• Commenter s indicated that with coal plants retiring westwide, major transmission lines will be freed up to serve other needs including wheeling renewa ble energy, and that renewable energy resources in the vicinity of the North Valmy plant include both geothermal, which is viewed as a "baseload" source, as well as solar
energy.

Commenter s disagreed with the assertion that new NGCC EGUs will need to be bu ilt to re

dispatch from coal to natural gas, stating that the Western Interconnect is awash in excess natural gas capacity at present and it is growing. Commenter s also refuted the contention that replacing a coal plant necessarily requires new gas to repl ace 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. Commenter s stated that this is37 inefficient and e xpensive use of coal power, and it does not necessitate replacement with 100% "baseload" power but could be replaced with a mix of resources to address the shape of the load including efficiency, renewables and demand response.

Comment 10: Commenter s said that because of their location s and other constraints, t he emission reductions that the EPA assumes can be obtained from Building Blocks 2 and 3 are unrealistic for many rural electric cooperatives.

Response 10: The EPA disagrees with the interpreta tion of the rules’ requirements. 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, 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 achie vement between performance periods. The Building Blocks are not prescriptive, and states may consider local circumstances as they develop their plans, including system reliability, fuel diversity, other regulatory requirements, infrastructure, and the “use ful life” of generation 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:

Commenters said that because of their location far from other sources of generation, and because of the unique cost constraints they face, many cooperatives lack affordable or practical access to enough gas

- fired and renewable energy sources to replace the coal that would be displaced by the new rule, which makes the emission reductions that the EPA assumes can be obtained from Building Blocks 2 and 3 unrealistic for many rural electric cooperatives.

Commenter s said that cooperative generators have limited equity available to them i.e., they are highly leveraged, and cooperative consumers must service the debt on units affected by the rule. In many case, commenter s said, units running even less that 10 percent below their operational norm on a continuing ba sis would be unable to generate enough revenue to service the outstanding debt on the unit. Commenter s said running them less (which is what the EPA effectively requires when it suggests that cooperatives can build new, lower

- emitting units or purchase ele ctricity from lower

- emitting sources in lieu of generating it from existing units) will lead to significant financial issues and a very high likelihood of creating stranded assets.

Commenter s noted that EPA's model presumes that Arizona's Tri

- State Genera tion and Transmission Association, Inc., (Tri

- State) coal

- fired facility, Springerville Unit 3, will dispatch at such a low level due to environmental dispatch that in reality its continuing operation will no longer be economically viable. According to com menter s , the EPA modeling projects almost 100% re

- dispatch of coal resources in Arizona by 2030. Commenter s 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 commenter s , the Springerville plant is a state

- of

- the

- art coal plant with air pollution controls including bag houses for particulate matter, scrubbers for sulfur dioxide, and selective catalytic reduction for nitrogen38 oxides. Commenter s added that Tri

- State will be installing additional controls in 2015 to reduce mercury emissions.

Commenter s described how the EPA modeling shows that Seminole Electric Cooperative coal

fired generating facilities have been arbi trarily scheduled for retirement well before the end of their useful life. Commenter s described the investment this plant has made (more than $530 million) in environmental control technology and recycling 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, commenter s said that approximately 70% of the byproducts produced at the coal facility are recycled for use in products that consumers use ev ery day, including wallboard and concrete. These continued investments have made Seminole's facility one of the cleanest coal

- based power plants in the country

, commenter s said. Should the EPA's proposed CO2 rule be finalized, commenter s stated, these cost ly investments will become stranded assets and Seminole's coal

- fired power plant will be forced to close, leaving 300 hard

working, skilled employees without jobs. Additionally, commenter s said, Seminole would have to build or purchase new power generation to replace the electricity produced from its coal

- fired facility. Such a drastic and sudden shift in Seminole's power portfolio will not only drive up the cost of electricity for its member cooperatives and member consumers, commenter s said, but could hav e sweeping unintended consequences for the fragile but recovering workforce and economy in Florida. Commenter s said that numerous cooperatives will have units that face premature phase

- out, creating stranded assets and consequently state regional economic disruptions.

Commenter s stated that nationwide concerns over natural gas availability prompted the U.S. Congress to enact the 1978 Power Plant and Industrial Fuel Use Act. Although repealed in 1987,
commenter s said that during implementation it required al l new electric generating facilities to be "coal capable." Commenter s 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 Fuel Use Act economically prohibited new EG Us that were coal

- capable from using natural gas as the primary fuel. During the time the relevant portions of the Fuel Use Act were in effect, commenter s said, electric cooperative generation needs grew substantially and, as a consequence, about 60 percen t of cooperative total baseload electric generation was constructed under Fuel Use Act and is coal based.

Comment 11: Commenters expressed concerns that existing capacity agreements, transmission rights, complicated ownerships, and unique loads would int erfere with implementation of the CPP.

Response 11: The EPA disagrees. 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) 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 examp le, 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 emission39 rate achievement between performance periods. The Building Blocks are not prescriptive, and states may consider local circumstances as they develop 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 TSD for the CPP Final Rule supporting the final CPP.
The following are summaries of the specific public comments under this co mment:

Commenters stated that the coal

- fired Big Stone Plant and the one combined

- cycle unit have no contractual relationship, are owned by different companies, and serve unique loads. Commenter s stated that Big Stone is South Dakota's only coal

- fired EGU, and there is only one NGCC plant, Deer Creek Station. Commenter s stated that Deer Creek Station was installed by Basin Electric Cooperative to meet that company's unique load and customer demand; it was never meant to meet a load reduction from Big Stone. Commenter s stated that the combined

cycle unit owner does has no obligation to provide energy to the owners and the customers of Big Stone Plant. Commenter s also stated that Big Stone Plant operates within the MISO centralized market. Commenter s stated th at the combined

- cycle unit will be placed in the Southwest Power Pool centralized market beginning in 2015; therefore, the two units will operate with entirely different commitment and dispatch processes. Commenter s stated that each Big Stone owner has a f irm transmission right from Big Stone to serve their respective loads; likewise, the NGCC plant has a firm transmission right to serve its loads.

Commenters stated that Building Block 2 fails to account for the fact that facilities may have already committ ed their capacity under long term power purchase agreements, which the states lack the authority to abrogate. Commenters stated that neither EPA nor the states have the authority to regulate the transmission or sale of energy to the extent that the Proposa l would require: the Federal Power Act ("FPA") imposes limitations on state authority with respect to energy; states whose transmission facilities are under the operational control of a System Operator will not be able to unilaterally implement the propos ed emissions standards under Building Block Two without impermissibly intruding upon the exclusive jurisdiction of FERC under the FPA.

Commenter s stated that Building Block 2 assumes that states can "substitute" the electricity produced by coal

- fired and oil/gas

- fired steam units with electricity produced by NGCC units through, essentially, preferential dispatch of NGCC units. Commenter s asserted that Building Block 2 fails to consider what percentage of electricity produced by NGCC units is currently

comm itted through long

- term sales contracts and, therefore, not available for dispatch.

Commenter s stated that independent power producers (IPPs), which are contracted for specific amounts of generation, may not have the immediate flexibility to re

- dispatch u nder the power purchase agreements (PPAs) between the buyer and the seller. Even in deregulated market

- based systems such as ERCOT, commenter s said, the operation of individual units and companies is still subject to the overall operational needs and const raints of the electrical grid.

Commenter s stated that PowerSouth's ability to meet a 70 percent capacity factor is constrained by its agreement to accept "must run" energy from SEPA hydro (for which it would not get40 credit in EPA's goal calculation). As a result of this, c ommenter s stated PowerSo uth reduces its NGCC's operation to fully utilize its "must take" hydro energy. Commenter s stated this flexibility reduces system carbon emissions, but PowerSouth would be penalized for it if Building Block 2 were implemented in Alabama.

Commenter s noted that, depending on the market structure of the region, natural gas

- fired generators may rely more heavily on firm contracts or interruptible contracts. Commenter s stated that electric generation owners who have the ability 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

- Atlantic markets, interruptible contracts are frequently used. Commenter s stated that, depending on th e region, the utilization of the pipeline capacity, and the specific pipeline tariff, firm pipeline costs vary. Commenter s provided a Figure 5 (Firm Natural Gas Transmission Rates, Individual Pipeline Tariffs) which shows the average, minimum and maximum c osts for firm natural gas fuel delivery in the respective regions based on existing pipeline tariff rates, assuming a 100 percent utilization factor of the pipeline. Commenter s noted that, while firm contracts on older pipelines are most often cheaper than contracts with newer pipelines because older pipelines' capital investments are fully depreciated, however, it may be more difficult to contract with older pipelines since they are often fully subscribed.

Commenter s stated the EPA overstates the amount of existing NGCC capacity available for re

dispatch because the EPA needs to account for NGCC units that may be unavailable for re

dispatch because they are contractually committed to out

- of

- state service or availability. Commenter s stated that plants with 1 0

- to 15

- year out

- of

- state power purchase agreements (PPA) would not be available for in

- state re

- dispatch. Commenter s stated that, even where merchant units have not presently committed to out

- of

- state service or availability, such units have no obligatio n to serve in

- state load. Commenter s stated that, for these reasons, it is inappropriate to assume that capacity from merchant NGCC units will be available for re

- dispatch. Commenter s stated that forcing PPAs to be dishonored would run afoul of the Contrac ts Clause and, where compliance would require PPA abandonment, credit markets would tighten causing economic impacts that EPA has not analyzed

.

Commenter s stated that NGCC ownership diversity may reduce the potential for re

- dispatch. Commenter s stated that virtually all of the Intermountain Power Agency (IPP) generation has been delivered to the California Purchasers who, along with the other Purchasers, have entitlement rights to all of IPP's generation. Commenter s stated the availability of potential NGCC generation for re

- dispatch, including transmission, is individual and specific to each Purchaser. Commenter s stated the California Purchasers may determine that procuring underutilized NGCC in Utah may not serve their economic interest or may simply be

un available. Commenter s stated that any NGCC re

- dispatch by a California Purchaser from sources outside of Utah would not factor into the rate calculation for Utah unless Utah were to join in a regional plan inclusive of such NGCC re

- dispatch. Commenter s stated the realization of NGCC re

- dispatch as contemplated by building block 2 would be left to the EGUs in Utah exclusive of IPP. Commenter s stated that, since IPP is a major source of generation in Utah, it may be difficult for the remaining EGUs to mee t the re

- dispatch goal. Commenter s stated the EPA should allow adjustments for the effects of NGCC 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 calculati on.

Commenter s 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 reformulate Idaho's goal with a 70% capacity factor at the two affected units. Commenter s stated that Id aho has two plants with the EPA

- designated affected units, both of which are NGCC plants: (1) Idaho Power's Langley Gulch and (2) the Rathdrum LLC plant, which sells generation 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 generating units.

Response 12: The EPA disagrees that we have mischaracterized or failed to consider the complexities to the cu rrent 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 proposal . 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 star t 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 proposal and RIA

– the establis hment of CO2 emission reduction standards 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 ancillary 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 TSD 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

Commenter s stated Block 2 ignores the manner in which the utility industry, Regional Transmission Organizations (RTOs) and Independent System Operators (ISOs) make dispatch decisions. Commenter s noted that, in many parts of the country, dispatch decisions are not un der the authority of state agencies or utilities but are made by RTOs or ISOs. Commenter s stated that, in the utility industry, the dispatch decisions are made based on two factors: reliability and cost. Commenter s indicated that coal units required for re liability should not be assumed to be able to back down when NGCCs increase their capacity factor. Commenter s noted that many coal units provide voltage support to enable the transmission system to deliver electricity; other coal units must operate to enab le the system to meet 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 Commenter s stated that building block 2 would create 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 reli ability. Commenter s noted that as a result, RTOs implement what is known as economic dispatch, but under the proposal RTOs will be forced to implement environmental dispatch of generating units (i.e., RTOs will be required to consider the environmental eff ects of operating generating units before the economic benefits of operating those same units). Commenter s asserted that this is contrary to the purpose for which RTOs were formed and also violates those regional entities' obligations under the Federal Pow er Act to dispatch generation economically.

Commenter s stated that, given RTOs and ISOs currently make their dispatch decisions on the current cost of generating kilowatts at that particular moment, it drives the grid towards producing the most cost

- effect ive electricity. Commenter s stated Building Block 2 would drive dispatch decisions towards utilizing 70% of the NGCC capacity, seemingly at the expense of lower cost generation. Commenter s stated that shifting our generation preferences from low cost metho d to the 4th most preferred method in terms of cost will do nothing other than significantly raise electricity rates.

Commenter s stated the concept of operating all NGCC units at a 70% capacity factor is unrealistic for Texas due to the design of the ERCOT market. Commenter s stated that any dispatch method that preferentially selects resources based on emissions rates, without rega rd for underlying fuel cost structure, will lead to market uncertainty and severe price increases. Commenter s stated that, when the grid is strained, ERCOT may need to require coal units to run outside of emissions constraints for reliability. Commenter s s tated 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, thanks to CPS Energy's zero

- emissions base load nuclear resource.

Dispatch Decisi ons -- Managed by Independent Agencies

Commenter s stated that the Ameren Corporation does not own an existing NGCC generating unit. Commenter s stated that certain generating units of this type may have permit limitations, warranty, and/or other contractual arrangements that preclude their operation as assumed in the proposed rule. Commenter s also noted that in RTO markets, the FERC and not the s tates regulate the RTOs; therefore, the proposed rule imposes a requirement on states that they do not have the authority to implement.

Commenter s stated that Building Block 2 is incompatible with the current system for electricity dispatch, which is manag ed by independent agencies, not state governments and which is based on cost, not a regulatory preference for natural gas. Commenter s 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. Commenter s stated that many of these organizations serve multiple states, and their jurisdictions do not always follow state borders. Commenter s stated that, since state governments have limited authority to dictate these organizations dispatch decisions, 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 decisio ns.

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

Commenter s stated that, while the EPA has suggested that the Northern Tier Transmission Group (NTTG) could manage the regional re

- dispatch of power 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 methodolog y because the redispatch of generating assets is outside the scope of EPA's authority under the CAA and intrudes upon the authority of both the states and the FERC.

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

Commenter s stated that, while the EPA suggests that a state could effectuate re

- dispatch of the generation within a state by requiring units to factor the costs of compliance into their electricity market bids, the EPA's suggestion will not work absent the coordination of all generating units within the SPP region. Commenter s stated that, because compliance obligations and costs differ greatly among states, it would be impossible for a unit in one state to determ ine the bid price necessary to ensure that it would or would not be dispatched before generating units in other states within the SPP region. Commenter s stated this is further complicated in states that fall within multiple regions, such as New Mexico and Texas. Commenter s stated that, in Oklahoma, the electricity market is managed by SPP, an independent system operator that dispatches all generation within its region and SPP, like all system operators, dispatches electricity on a priority basis of (1) reli ability and (2) least

- cost.

Commenter s stated that the EPA's Building Block 2 is based on what commenters considers to be a faulty premise that generation from any NGCC unit 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 generation from EGUs within its system such that the lowest co st generating sources are dispatched first. Commenter s also noted that the areas covered by RTO and ISO systems typically do not coincide with state borders

- in most cases, an ISO's footprint includes generating units in several states, and some states ar e divided between multiple ISOs. Commenters maintained that 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 they are located . Commenters added that there may be limited44 interconnection between the different dispatch systems 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.

Commenter s s tated that the EPA has assumed that a utility will be able to alter the dispatch patterns of its NGCC capacity without taking into account the dispatch mechanisms within Regional Transmission Organizations (RTOs) and Independent System Operators (ISOs). Co mmenter s indicated that an RTO's control over the dispatch of generation will affect a state's ability to adopt measures that achieve EPA's proposed section 111(d) requirements and a utility's ability to control emissions from its overall fleet and comply with state plan requirements. Commenter s noted that under Building Block 2 the state, and ultimately the utility, will need to achieve EPA's post re

- dispatch capacity factor on NGCC units, but dispatch of the units is not controlled by either the state or, generally, the utility, 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 certain state at EPA's post re

- dispatch capacity f

actor for that state. Commenter s stated that RTOs currently make dispatch decisions based upon economics

- i.e., the lowest cost generating sources are dispatched first. Commenter s gave the following example of this "economic dispatch" mechanism, which is based on a presentation by the Electric Reliability Council of Texas (ERCOT) at a Texas Public Service Commission workshop on the Proposed Guidelines:

Every five minutes, ERCOT sends a signal to each online generator that is participating in the ERCOT mar ket (through the generator's Qualified Scheduling Entity) telling each generator how much power to produce; In general, this set of generator 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 set 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 set of output levels that is the lowest cost set that does not overload any transmission constraints; and, This process is called a security

- constrained economic dispatch (SCED).

Commenter s stated the EPA presumes that utilities will be able to rely on the in terconnected nature of the electricity sector to accomplish Building Block 2 (79 FR 34837). Commenter s 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 r equirements on its own. Commenter s stated that FERC and NERC require certain reliability measures such as maintaining spinning reserves at all times and, because PowerSouth is not part of an RTO or ISO, it cannot rely on other resources to satisfy such requirements like many other utilitie s. Commenter s stated the EPA's proposal essentially prohibits PowerSouth from maintaining its business model by making it so uneconomical that PowerSouth must coordinate with other utilities to satisfy reliability requirements. Commenter s stated it is well beyond EPA's authority to regulate certain business models out of existence and require those utilities to join an RTO or ISO.

Commenter s stated the EPA proposal ignored the interstate nature of ownership, contracting, and supply for municipal and electri cal loads. Commenter s 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 municipali ties who have no ability to redirect their power supply along environmental lines. Commenter s 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 dispatched 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 sources. Co mmenter s 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).

C ommenter s urged the EPA to work with states and regional transmission organizations to adopt a more realistic view of the potential for re

- dispatch that considers stranded costs and the reliability of the grid and to adopt a more reasonable phase

- in time t able for re

- dispatch that does not threaten the reliability of the regional grid nor impose undue stranded costs on states' electric ratepayers. Commenter s stated the Western Electricity Coordinating Council (WECC) began a phased study process to provide a n analysis of potential impacts of the Proposed Rule to the Western electric generation and transmission industry. Commenter s stated preliminary WECC results indicate that a state's decisions made regarding compliance with the Proposed Rule can "drasticall y impact grid operations, system resiliency, and potentially, compliance opportunities for a neighboring state."

Commenter s suggested that the EPA may need to revisit their understanding of dispatching, as well as a review of availability using local, exi sting system constraints to define an appropriate target for NGCC dispatching, which may not be different than what was already demonstrated in 2012 when NGCC were the least cost option. Commenter s stated that the EPA knows that available electric generati ng 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 commenter s disagreed with EPA that these data suggest that, since the indust ry already shifted 20% capacity, they can also shift an additional 20% due to a rule because this conclusion ignores EPA's initial statements on how available units are dispatched by cost. Commenter s noted the EPA describes that Regional System Operators ( RSOs) and Independent System Operators (ISOs) dispatch according to economics first and the EPA then observes the huge increase in capacity factor in 2011 and 2012 of NGCC, and relates this to the historic low natural gas prices. Commenter s stated that, if EPA requires re

- dispatching 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

Commenter s stated that EGU owners can replace fossil fuel

- fired gen eration with renewable generation through bilateral contract. Commenter s stated that, whether an EGU owner is located in a state that is operating under traditional utility regulation or in a restructured market, that owner may enter bilateral contracts fo r the sale of power. [FERC Primer at 60

- 61.] Commenter s stated that such contracts require the EGU to supply a certain amount of power to a customer such as a distribution utility. Commenter s stated a large volume of renewable energy used by vertically int egrated utilities

-- including IOUs, municipal utilities, and co

- ops

-- is procured through PPAs with independent renewable developers. Commenter s stated those utilities that46 own fossil fuel

- fired EGUs are free to reduce the utilization of their EGUs and repla ce it with the procurement of renewable energy from renewable projects owned and operated by third party developers. Commenter s stated that, even in organized 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. Commenter s stated a good example of this is Invenergy:

• Invenergy, an IPP that owns generation capacity from various resources including 56 wind projects (5,473 MW), 5 solar projects (49 MW), 8 natural gas combustion turbines (4,529 MW), and 4 storage projects (65 MW). Invenergy enters into bilateral contracts with utilities, electric cooperatives, and commercial power users in many states throughout all regions of the country. As the owner of natural gas an d renewable EGUs, Invenergy can manage, through traditional business decision making, the resource mix of its generation assets in order to reduce the CO2 emissions of its fossil fuel

- fired EGUs while meeting contract obligations to its customers. Moreover , IPPs such as Invenergy can help utilities that own EGUs or other EGU owners by signing bilateral contracts for their own low

- or zero

- carbon emission generation so that those purchasers can meet their obligations to distribute electricity, yet reduce uti lization of their higher emitting EGUs.

Commenter s stated that IPPs that own only fossil generation can also sign bilateral contracts with IPPs that own renewable energy. Commenter s stated that bilateral contracts between merchant fossil fuel

- fired EGU owners and their customers often do not specify the particular generation resource that must be used. According to c ommenter s , merchant fossil

- fuel fired EGU owners that do not own suf ficient renewable generation or do not own it in the right location can instead act as a power marketer by signing a separate bilateral 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 would be satisfied with a mix of renewable power from the third party and fossil

- fired power from the merchant fossil fuel

- fired EGU

owner.

Commenter s stated the bilateral market for renew able energy is well developed. Commenter s 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 of energy from a renewable generation facility. Commenter s stated th e ability of non

- utility entities to sign contracts for the delivery of renewable generation is sufficient proof that such contracts are adequately demonstrated. Commenter s 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 its 50 MW Alexander Wind Farm in Kansas to Yahoo.

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

Area

- Specific Concerns47 New Mexico

Commenter s stated that the final rule should evaluate and adjust Building Block 2 where necessary to account for dispatch decision

- making capabilities. Commenter s stated that re

dispatch considerations in goal setting should consider whether out

- of

- state utilities and balancing authorities make dispatch decisions that affect states' ability to accomplish full re

dispatch. Commenter s explained that many of New Mexico's dispatch decisions are not controlle d by in

- state authorities. Commenter s stated that New Mexico is connected to two different grids and exports between 30 and 40% of its power annually, making it dependent on other states' dispatch authorities to make appropriate dispatch decisions. Comment er s also noted that many of the state's rural electric cooperatives purchase power from the Southwest Power Pool, for which dispatch decisions are made in their Corporate Center in Little Rock, Arkansas.

Commenter s stated that the final rule should evaluat e and adjust Building Block 2 where necessary to account for dispatch decision

- making capabilities. Commenter s 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 between 30 and 40% of its power annually, making it dependent on other states' dispatch authorities to make appropriate dispatch decisions. Commenter s added that many of the state's rural electric cooperatives purchase power from the Southwest Power Pool, for which dispatch decisions are made in their Corporate Center in Little Rock, Arkansas. Commenter s stated, nevertheless, partial re

- dispatch is possible in New Mexico; it may, therefore, become an important option to include in the New Mexico State Plan

.
South Dakota

Commenter s stated that, because the economics of unit dispatch vary dramatically from utility system to utility system, Block 2 would impose arbitrarily different cost of compliance on the different states. Commenter s stated that analysis of the different state targets shows the arbitrary impact of Block 2 and provided the following example.

Consider two similar, adjacent states: North and South Dakota. Despite the fact that they are in the same region of the country, North Dakota and South Dakota have very different targets. North Dakota is required to achieve an 11% reduction 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 decisi on to use the arbitrary re

- dispatch methodology 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 in targets of more than 1,000 lb/MW h, the two states will face completely different compliance economics.

Commenter s stated that another issue the EPA fails to consider is the potential implications on how states/RTOs could dispatch units where there are multiple RTOs operating in a single state. Commenter s gave the example that in South Dakota there 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 tha t year. Commenter s 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 lone coal

- fired unit

- Big Stone (co

- owned by Otter Tail Power, Montana

- Dakota Utili ties and NorthWestern Corporation)

- to reduce48 operations to an annual capacity factor of 23 percent. Commenter s asserted that the EPA fails to consider that the Deer Creek and Big Stone plants have different owners and are located in different RTOs and se rve different loads.

Commenter s stated that an issue EPA fails to consider in its simplified approach on NGCC re

dispatch is its potential implications on how states/RTOs could dispatch units where there are multiple RTOs operating in a single state. Comme nter s 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 unit, Big Stone, but the EPA failed to consider that the Deer Creek and Big Stone plants have different owners and are located in different RTOs and serve different loads. Commenters stated the flawed assumption of Building Block 2 is that Deer Creek Station will be dispatched to meet the needs of the Big S t one Plant

co

- ow ners' loads presently served by Big Stone Plant.

Commenter s 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

- based plant, Big Stone, therefore its power cannot be used to replace Big Stone's load, as EPA's rule assumes. Commenter s stated that, while the EPA assumed that the Deer Creek Station will increase 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 not consistent with the facts in South Dakota. Commenter s stated the EPA should reevaluate the role 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.

Commenter s stated that re

- dispatch of energy from one 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. Commenter s stated that where the coal

- fired unit and the NGCC unit are owned by completely different entities serving separate loads, as is the case in South Dakota, any transfer of ene rgy between those entities would require a willing buyer and a willing seller. Commenter s stated Big Stone Plant and Deer Creek Station are not merchant units with unsubscribed capacity and energy available for sale. Commenter s stated that, since Basin Ele ctric 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 loa d. Big Stone Plant's co

- owners have no right to the energy output of Deer Creek Station, making re

- dispatch infeasible.

Commenter s stated that detailed engineering studies and modeling are needed to ensure that energy can be transferred effectively from ea ch generator to the load it is intended to serve. Commenter s stated that, while adequate transmission capability and infrastructure supports delivery of Big Stone Plant generation to its retail 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. Commenter s concluded that the EPA should not require implementation of Building Block 2 in South Dakota because it would be contrary to the contractual, planning, operational, and reliability realities facing the separate owners of Big Stone Plant and Deer Creek Station. Commenter s 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

- setting calculation for South Dakota. Commenter s stated they supported the comments filed by Commenter s regarding Building Block 2 and the Big Stone Plant.

Other States/Areas

Commenter s stated that Michigan's IOUs are market participants 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 prov ide supply to their customers. Commenter s indicated that based on this existing market

- based approach, jurisdictional issues would arise between the state regulators overseeing implementation of Section 111(d) and the RTOs managing the economic

- based dispa tch of all generation, including NGCC units. Commenter s asserted that a fundamental change in this system would be necessary in order to account for re

- dispatch of NGCC units, such as the implementation of a carbon price.

Commenter s stated that EPA's re

- di spatch approach consequently conflicts with the responsibilities assigned to RTOs by FERC, and the nature of electricity markets today. Commenter s added the Southwest Power Pool (SPP) responded to a question from the Missouri Public Service Commission on w hether an RTO's control 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 unless well

- designed market system changes are made. Commenter s stated that close coordination between SPP, members, regulators and the applicable state agencies will be needed to ensure that SPP's SCED system app ropriately accounts for emission goals, which will not be a simple matter and will take considerable time to develop the appropriate protocols and potential market system changes.

Commenter s stated that, while fossil fuel

- fired generation sources located w ithin Nevada are subject to Nevada's air quality control measures and permit limits, a number of them are not subject to Nevada jurisdiction from a public utility planning perspective. Commenter s stated those resources are owned and controlled by utilities in other states. Commenter s stated Building Block 2 creates conflict between states that share a common generating station. Commenter s stated that Nevada cannot utilize non

- jurisdictional NGCC and coal

- fired EGUs to assist in meeting its emission reductio ns targets until the jurisdictional issue has been addressed. Commenter s stated that, while the USEPA suggests that states should be left to negotiate such situations among themselves, there is very little time to do so before a state plan is required to b e submitted under the proposed deadlines. Commenter s stated the Nevada Agencies request that the USEPA provide a more streamlined approach.

Commenter s added that SWEPCO's comments to the Texas Public Utility Commission identified concerns over Building Blo ck 2 in Texas

- SWEPCO noted that the Proposed Guidelines' re

dispatch approach is inconsistent with the current dispatch algorithms used by balancing authorities, and that noneconomic dispatch will lead to increased costs for customers.

Commenter s stated that power simply cannot flow across the east/west systems without constraint, as EPA assumes. Commenter s explained that Basin Electric has several DC Ties that bridge the national electric system, but only has a limited amount of available capacity across50 those ties. Commenter s stated that Basin Electric therefore developed its generating assets on either side of the grid without regard to environmental dispatch: coal primarily on the west, where coal resources can be cheaply and dependably obtained, and n atural gas and wind largely on the east, where good wind resources exist. Commenter s stated that, because environmental dispatch has never before been proposed or mandated, Basin Electric has not developed its generating capacity to transfer across the eas t and west grids. Commenter s stated that Basin Electric only has ownership or capacity rights to transfer 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. Commenter s sta ted 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 generation from a west

- side EGU with eas t side renewables.

Commenter s stated that the EPA's misunderstanding of 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 implementing the rule as proposed becau se the Proposal relies on these fundamental errors. Commenter s noted that the Proposal states that Northern Tier Transmission Group (NTTG) as a regional transmission organization will be able to facilitate/implement the Proposal by ensuring: the re

- dispatc h of coal with NGCC units as described under Block 2, grid reliability, and transmission upgrades. Commenter s stated that this assumption is completely false and illustrates how EPA has stepped outside of its expertise in this rulemaking. Commenter s 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 markets, scheduling/dispatch decisions or transmission upgrades . Commenter s stated that NTTG is a planning organization that is designed to provide a forum for State, industry and public stakeholders to study transmission scenarios that may be ultimately implemented by NTTG members.

Commenter s stated that even where electricity dispatch is governed by individual utilities and not by an ISO or RTO, similar limitations on in

- state re

- dispatch arise where a state is served by multiple utilities or where a utility spans multiple states. As an example, Commenter s noted tha t TVA generates power from fossil fuels in 4 states and distributes power to Tennessee and portions of 6 other states, and it also buys and sells some power from neighboring systems and optimizes the dispatch of generating assets and operation of transmiss ion infrastructure as a system (not necessarily within individual states) to maintain reliability and minimize cost. Commenter s indicated that three of TVA's five NGCC units are located in Mississippi, but all of its coal

- fired units are located outside of Mississippi (TVA does purchase power through a power purchase agreement from the Red Hills coal

- fired unit in Mississippi). Commenter s concluded that increasing the capacity factor of TVA's Mississippi NGCC plants would have minimal effect on coal

- fired g eneration 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 efficie nt and reliable electricity to consumers in its "primer," a document accessible to all, including EPA. Commenters said that it is most important to recognize that the grid uses market mechanisms to dispatch 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 consisting of generating plants, high voltage transmission lines, local distribution facilities, commun ication, and other facilities that must operate as a contemporaneous network in real

- time or 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 responsibility 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. Aut hority for those transactions has been preapproved under interconnection agreements signed by all the electric utilities physically interconnected or with coordination agreements among utilities that are not connected.

[R]egional transmission organizations and independent 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 pla nning and coordination of the interconnected power systems are the responsibility of the North American Electric Reliability Corporation (NERC).... NERC's eight regional entities cover the 48 contiguous States and portions of Canada and Mexico. The regiona l entities are responsible for overall coordination 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 member utilities.

The ele ctric 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 responsibility for overseeing oper ations, developing procedures, and enforcing mandatory reliability standards in the electric power industry to a new electricity reliability organization (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 forma Delegation Agreement between NERC and Regional Entities under which Regional E ntities would have the authority to recommend reliability standards to the ERO and enforce them. In Order Nos. 693 and 693

- A, the FERC approved 83 of 107 proposed Reliability Standards for which the ERO assumed enforcement responsibilities in June 2007. Un der this new authority FERC may undertake enforcement actions independent of the ERO, including the imposition of penalties. The FERC, under its new general oversight responsibilities, continues to examine, provide input, and approve new mandatory standard s as proposed by the ERO."

Comment 13: Commenters expressed concerns regarding the lack authority by states or other entities to implement the generation shifting in the CPP.52 Response 13: The E PA disagrees with commenters

. CAA section 111(d)(1) requires the EPA to promulgate regulations under which states submit state plans regulating “any existing source” of certain pollutants “to which a standard of performance would apply if such existing source were a new source” and “pr ovides for the implementation and enforcement of such standards of performance.” Affected EGUs, including municipalities and electric cooperatives, are subject to air quality requirements, including meeting such standards of performance that a state may

es tablish to meet emissions performance levels that the EPA determines are achievable under CAA 111(d). We give states and affected EGUs flexibility determining how they meet these requirements. No state or affected EGU must implement the precise measures in cluded in the building blocks in order to do so. For a more comprehensive discussion of these issues, please

s ee section V.D of the final rule preamble of the CPP for EPA’s response to this comment.
The following are summaries of the specific public comme nts under this comment:

Commenters stated the Proposal seems to work under the assumption that a state (or the load

serving entities within a state) have full legal authority and operational capability to dispatch any generating and transmission resources within the state 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 natural gas

- fired generation without any consideration of the ownership of those units, existing legal commitments of various units, financial consequences related to the shift from currently owned generation, and without adequate consideration of natural gas pipeline capacity and electric transmission constraint s.
Commenters stated that using new data, there is an incorrect EPA assumption that commenters have authority to provide services for generation dispatch, transmission upgrades and system reliability. Commenters' explanation follows. I. BACKGROUND In the p roposed rule the EPA specifically references the commenter's organization and suggests that for areas of the country that are not covered by an ISO/RTO, there are regional groups, such as commenters and Columbia Grid, that can control dispatch and seek sol utions 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 correct this apparent misunderstanding of the nature of the organization, comme nters submitted these comments to brief the EPA on commenters' roles and functions in relation to transmission planning and system operations, and in particular to draw a clear distinction between the responsibilities 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 stat proposal for increasi ng the dispatch e regulatory utility commissioner appointed by each state's respective regulatory utility commission 3 in the NTTG Footprint, (2) one representative from each of the Funding Members 4, and (3) one representative appointed from each state cu stomer advocacy agency 5 within the commenter's organization Footprint (the commenter's organization Members). commenter's organization Members, together with other stakeholders, carry out an open, transparent, coordinated transmission planning process for service and facilities involving the combined systems within commenter's organization and ultimately, interregional coordination through participation by the commenter's organization in the Western Electricity Coordinating Council processes. Commenters st ated the commenter's organization Members are committed to53 initiatives that will increase the efficiency and use of the transmission grid for the benefit of customers, the furtherance of markets, regional transmission tariffs, and other transmission produc ts, services or structures that are economically justified. Commenters stated the proposed rule suggests that commenter's organization exercises a dispatch function, may authorize transmission upgrades, and could implement a capacity market. Commenters sai d these functions are not performed by commenters' organization and outside 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 th e commenters' organizations' footprints, it is not a market operator, nor has any role in the scheduling, commitment and/or dispatch of any generating units. Commenters said further, transmission plans that result from commenters' organizations' processes are implemented by other entities, 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 term reliability authority for the transmission within its footprint. Commenters said this responsibility, along with tariff administration and design, congestion management, parallel path flow, ancillary services, OASIS total transmission capability and available transmission capability, and market mo nitoring functions remain with other entities (e.g., individual Transmission Owners). III. CONCLUSION Commenters stated commenters' organizations do not have the authority, nor the responsibility, to provide services for generation dispatch, transmission u pgrades and system reliability that EPA has assumed as a basis for implementation of its proposed rule.

Commenters pointed out that state utility regulatory commissions lack the authority to implement several building blocks with respect to public power u tilities. Commenters state that in some instances, state utility commission approval is required for new generation units or for generation dispatch. Commenters noted that state utility commissions do not otherwise regulate public power utilities in their states.

Grid Operators

Commenter s stated that, in designing its state

- by

- state best systems, EPA wrongly assumes that states can control the dispatch of in

- state resources so that, for instance, an in

- state NGCC unit can be ramped up and an in

- state coal unit can be ramped down to meet EP A's goal. Commenter s stated that states themselves do not control the dispatch of units, as units are instead dispatched by regional grid operators based on regional power needs. Commenter s concluded that the grid operator might be forced to call on the st ate's coal and gas plant to meet regional supply needs, depending on the state of the regional market at any one time and, thus, EPA's state

- by

- state best systems could not exist in the real world.

Commenter s stated the proposed rule fails to recognize sch eduling and dispatch are controlled by regional transmission organizations (RTOs) and independent system operators (ISOs). Commenter s stated Montana cannot unilaterally implement Building Block 2 without intruding upon the jurisdiction of these organizatio ns and the Federal Energy Regulatory Commission (FERC). Commenter s stated FERC has exclusive jurisdiction over the transmission of electricity in interstate commerce and the sale of such energy at wholesale in interstate commerce and states retain jurisdic tion only over retail sales of electricity, generating facilities, facilities used for54 local distribution, and facilities used for transmission of energy wholly consumed by the transmitter.

Commenter s stated that, although EPA considers each state's best s ystem to be one in which all NGCC generators operate at a 70 percent capacity factor, the EPA fails to provide any information as to how a state would go about obtaining that result. Commenter s stated that neither the EPA, the states, nor FERC has the auth ority to order natural gas generators to operate at that or any other capacity factor. Commenter s stated 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 capac ity factor will depend on market conditions, including natural gas prices. Commenter s stated that the EPA's best system therefore depends on a factual impossibility: the notion that NGCC units should operate at a 70 percent capacity factor when that level of operation is beyond the power of the state to command.

Commenter s indicated that the EPA has recognized that EGU owners and grid operators are subject to various reliability and operational constraints, and dispatch decisions are based on electricity d emand at a given point, the variable costs, and system constraints; commenter s quoted the proposal as saying that it is this "security

- constrained economic dispatch [that] assures reliable and affordable electricity" (79 FR 34862). Commenter s asserted that state agencies responsible for environmental protection are not charged with, nor should they be, dispatch of electricity within their own state much less outside of state borders. Commenter s added that the CAA does not give states the authority to regula te the dispatch of power plants on the interstate grid, which commenter s characterized as a fatal flaw in this building block. Commenter s 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 market changes require FERC approval and must be permissible under the Federal Power Act (FPA)

- rates must be "just and reasonable" and "not unduly discriminatory or preferential."

Commenter s noted that the EPA cites the ability for states to control dispatch by example of the Title IV program (79 FR 34862), but commenter s found this comparison unpersuasive. Commenter s stated that most importantly, Title IV was approved by Congress under the CAA and this proposal has not been. Commenter s ad ded that 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. Commenter s indicated that under Title IV, an individual EGU that installs an environmental control device can actually operate more frequently than one that does not; the decision is made based on what is necessary to reduce emissions insid e

- the

- fence based on allocations received. Commenter s asserted that the EPA is not comparing apples to apples in comparing Title IV and the intricacies of this system

- wide proposal.

Commenter s stated that EPA's assumption that a state 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. Commenter s stated that State environmental agencies do not have authority to require such re

- dispatch, and, in fact, some states do not have such legal authority at all. Commenter s stated that setting emission rate goals based on such an assumption exceeds EPA's
aut hority under Section 111(d). Commenter s suggested the states are in the best position to determine whether existing NGCC capacity can, in fact, supplant existing coal fired EGUs taking55 into account transmission constraints, gas supply limitations, remainin g 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) and market limitations.

Commenter s stated, because the current generation market is controlled and regulated by many agencies (FERC, NERC, the Commodities Futures Trading Commission (CFTC), RTOs/ISOs), the EPA and state environmental agencies cannot order the market. Commenter s 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. Commenter s stated 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 Building Block 2 is trying to force, the EPA, however, cannot incorporate this carbon proxy cost into the market price of electricity.

Commenter s stated that neither EPA, FERC, nor the s tates' as they have currently configured their institutions have the authority to decree a 70% capacity factor for gas plants. Commenter s stated the "unadministrability" of building block 2 provides furthe r evidence that the Proposed Plan will not survive judicial review under the principles stated in UARG.

Commenter s stated the EPA and state environmental agencies cannot order the market to become uneconomical or unreliable. Commenter s stated this market is controlled and regulated by many agencies (FERC, NERC, the Commodities Futures Trading Commission (CFTC), RTOs/ISOs). Commenter s 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. Commenter s 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 to result in the market shift that Building Block 2 is trying to f orce. Commenter s stated the EPA cannot incorporate this carbon proxy cost into the market price of electricity. Commenter s stated that, due to this, all of the volatility and instability that entities managing the market work to avoid will occur. Commenter s stated capacity factor is a function of unit availability and cost. Commenter s stated that, in MISO, plant efficiency, demand, cost of fuel, and transmission constraints all play a role in determining which plants run and when. Commenter s stated supersed ing current market design with a requirement to run certain units regardless of traditional dispatch factors counters the long term resource planning used by RTOs.

Commenter s asserted that states operating in competitive energy markets cannot increase uti lization without supporting market mechanisms and signals. Commenter s stated that, if the EPA left the standard

- setting approach up to each state, and allowed time for market mechanisms to be developed and implemented, it is possible that Building Block 2 principles could be captured in state plans.

Commenter s stated the EPA does not have primacy on regulation of the nation's electric grid and natural gas transmission and distribution infrastructure. Commenter s 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 those affected facilities. Commenter s stated that dispatching lower carbon sources to displace existing coal

- fired generation is not a system of emission reduction, and dispatch priority is outside the purview of the CAA. Commenter s stated56 they cannot see how a congressionally authorized 111(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 completely new basis.

Long

- Term Contracts

Commenter s asserted that states have no authority to require that NGCC units abrogate existing bilateral contracts (such as Power Purchase Agreements) between NGCC units and those who purchase electricity from them. Commenter s stated the FPA perm its utilities to set rates with individual electricity purchasers through bilateral contracts, though contract rates must be filed with FERC before going into effect. Commenter s indicated that under the filed

- rate doctrine, "interstate power rates filed wi th FERC or fixed by FERC must be given binding effect by state utility commissions determining intrastate rates." Commenter s went on to note that when the filed

- rate doctrine applies to state regulators, it does so as a matter of federal pre

- emption throug h the Supremacy Clause, and that the filed

- rate 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 [se rvice] as well as quantity and price terms." Commenter s concluded that as a result, states have no authority to require that NGCC units abrogate existing bilateral contracts (such as Power Purchase Agreements) between NGCC units and those who purchase elec tricity from them. Commenter s 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. Commenter s noted that the American Public Power Association estimated that in 2013, two

thirds of new capacity in the U.S. was built with Power Purchase Agreements for the sale of power. Commenter s added that while 64 percent of these agreements were with a utility, the EP A 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

- term contractual commitments. According to

c ommenter s , these contractual commitments commonly span 10 to 25 years in the Southeast and the West, and project finance contracts in organized markets have similar timetables. Commenter s indicated that plants with 10

- to 15

- year out

- of

- state PPAs would not be available for in

- state re

- dispatch as EPA presumes, giving the e xample 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. Commenter s added that this generation cannot be presumed available for re

dispatch in New Mexico. Commenter s s tated that the EPA also assumes, under Building Block 2, that any increases in capacity at NGCCs will be eligible for re

- dispatch, again ignoring the potential impacts of long

- term agreements. According to the commenter s , if a facility has committed the en tirety 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 markets. Commenter s also stated that a Power Purchase Agreement may also contain a provision requiring the buyer's consent before modifications may be made to the subject facility. Commenter s concluded that as a result of these omissions, the EPA overestimates the amount of electricity eligible for re

- dispatch under Building Block 2.

Regional Markets57 Commenter s also stated that EPA ignores the fact that a number of states are located in more than one regional market. Commenter s stated that portions of Arkansas and South Dakota are in the SPP and other portions are in MISO; SPP, PJM, and MISO cover some of all states and only parts of others; and the Electric Reliability Council of Texas (ERCOT) covers only part of Texas. Comment er s 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 an d therefore they are not seamlessly integrated. Commenter s stated that Deer 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. Commenter s stated IS /SPP and MISO do not share a dispatch signal that would allow one plant's increased operations to result in the lower dispatch of a plant operating in a different market, nor would there be any economic or logical reason to dispatch the units in a coordina ted fashion given that they serve different markets. Commenter s 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 e ach of the owners of these plants possesses firm transmission rights to ensure that the generation reaches load.

Commenter s stated the proposal does not take into account how the organized markets of an RTO like PJM function. Commenter s asserted that stat es that have restructured their electric markets have effectively relinquished both jurisdiction over EGUs in their states and operational control over EGU dispatch and the transmission systems that deliver the energy from the EGUs to the RTOs. Commenter s stated that, in the restructured states, the EGUs rely on RTO market signals sent by FERC jurisdictional wholesale markets to set the price at which they will offer their energy, capacity and other products into the market. Commenter s stated those federal, wholesale market signals also serve as indicators for whether the EGUs should continue to invest in ongoing operation and maintenance expenses. Commenter s asserted that States no longer have the ability to intervene to direct which resources are operated, constructed, or maintained. Commenter s stated that, while states that have retained or returned to traditional regulation have some control over EGUs and how they are dispatched, restructured states have little to none.

Commenter s stated the EPA's analysi s of Building Block 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. Commenter s stated that Pennsylvania, for example, has turn ed over these operations to PJM and, as a result, Pennsylvania cannot directly regulate which facilities under its jurisdiction are called up to deliver electricity at any given time. Commenter s stated that, unless and until EPA addresses this issue, any f inal rule relying on

re

- dispatch would be unsupported by the record.

Commenter s stated that the EPA cannot assume s tates have jurisdictional control over the dispatch of electricity. Commenter s stated the EPA should not assume that all of the NGCC plants are owned and operated by the same entity that 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 ability of a single market reg ulator or system operator. Commenter s stated that utilities that are members of the Midcontinent Independent System Operator (MISO) regional transmission organization rely on MISO's dispatch process and have no authority to override, force, or modify this process. Commenter s stated that the state also has no authority over this dispatch process and no mechanism to force or modify dispatch of58 these plants. Commenter s 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. Commenter s stated the EPA assumed a 70 percent utilization rate of all NGCC in the state without regard to how these units are dispatched by the utilities and Regional Transmissi on Organizations (RTO) and the USEPA has not identified any tools to do this and has not addressed federal regulatory barriers. Commenter s stated that, in Michigan, the majority of the NGCC capacity is dispatched by the RTO and the state has no authority o ver this dispatch process and no mechanism to force or modify dispatch of these plants. Commenter s stated that, in Michigan, one NGCC plant that is owned and operated by an Independent Power Producer will soon be dispatched via a proposed direct transmissi on line that leads out of the state; in this case, even a Michigan CO2 price

- forcing dispatch within MISO for electricity sold in Michigan would have no effect on this plant's generation since it is being bid, sold, and supplied into another RTO.

Commenter s stated there are limits on states' authority to mandate re

- dispatch. Commenter s stated that MISO, like all system operators, dispatches electricity on a priority basis of (1) reliability and (2) least costs. Commenter s stated that, because compliance obl igations 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 dispatched before generating units in other states within the MISO region. Commenter s stated this is further complicated in states that fall within multiple regions, such as South Dakota. Commenter s stated the EPA assumed that generation from Deer Creek could be increased and, as a result, generation from Big Stone decreased; however, bec ause Big Stone and Deer Creek participate in different markets, the presumed increase in generation from Deer Creek could not displace load requirements for Big Stone.

State

- Specific Concerns

Commenter s stated the EPA has simply ignored the fact that states like Indiana do not have authority over the market dispatch of electric generating units located in its state; that authority is held by regional transmission organizations, in this case MISO, and to a lesser extent PJM. Commenter s stated that the Indiana Department of Environmental Management (IDEM) does not have dispatch authority as referenced in building block 2 that MISO and PJM have. Commenter s asserted Indiana does not have regulatory authority to control the dispatch of electricity within its own borders, let alone on a regional basis, and thus lacks the authority to implement Building Block 2. Commenter s stated that, even if the state were to establish the authority to mandate dispatch of elect ricity from NGCCs at a certain level of capacity, implementation would have to be conducted by an RTO, not the state. In that case, commenter s stated Indiana would not be in a position to properly oversee and enforce implementation, or ensure adequate reco rdkeeping.

Commenter s stated the EPA's simplistic appraisal and approach to the process of dispatch does not reflect the underlying wholesale market dynamics of a state's power sector. Commenter s stated the EPA must revise how it applies building block 2 i n goal setting because it must reflect realistic and reasonable outcomes. Commenter s stated 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 gener ation in New Jersey, which, according to Commenter s is not a realistic or reasonable outcome. Commenter s stated that in deregulated markets, such as in59 New Jersey, the dispatch of units is determined by economic merit. Commenter s offered that states can in fluence dispatch, as New Jersey has done, through environmental regulations and energy policy; however, there is no direct and automatic correlation between a decrease in operation of in

- state affected coal and oil

- fired units and the increase in operation of an in

- state affected NGCC. Commenter s stated the EPA's approach is merely an academic exercise that assumes the affected in

- state NGCC will only displace affected in

- state coal and oil

- fired generation. Commenter s 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 th roughout the PJM region.

Commenter s 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 Pennsylva nia, commenter s 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 regulator and must dispatch units based on its tariff. Commenter s said that B uilding Block 2 should not be included in the determination of BSER because re

- dispatching from one stationary source category to another category is not consistent with BSER as prescribed in the CAA.

Commenter s also stated that in Ohio it is the EGU owne rs who decide in what manner to bid into the electricity market and for how much time, and it is PJM, under the authority of FERC, who determines dispatch order based on utilizing the least expensive resource first to meet energy demand. Commenter s asserte d that it is not within Ohio EPA's authority to require NGCC sources increase dispatch to a certain percentage under 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. Commenter s indicated that this creates unanswered questions: What 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 violation if 70% utilization is not achieved? Commenter s contended that the proposal could lead to the situation where a NGCC unit must operate to achieve the 70% utilization value even if the electricity is not needed. Commenter s stated that this element of the pro posal must be dropped from further consideration.

Title V Permit

Commenter s noted that the EPA suggested that states could implement increased re

- dispatch of NGCC by limiting the operation of coal

- fired EGUs through permits (79 FR 34862). Commenter s stated that to restrict operation in a Title V permit, such limitations would need to be included in a federally approvable plan but still could not override other federal laws outside of the CAA. Commenter s asserted that placing a specific limit on the number of hours a base

load 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 ability 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, 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 many comments, we have modified the proposal and RIA

– the establishment of CO2 emission reduction standards 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 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:

Commenter s said that the EPA's assumption that "affected sources may themselves implement the measures included in building blocks 2, 3, and 4, so that those measures are wi thin their control" (79 FR 34889) is faulty and unsupported assumption. Commenter s said that a utility company whose fleet of affected EGUs is entirely comprised of NGCC units cannot simply decide to re

- dispatch their units at a 70% capacity. Commenter s st ated that facilities may be ordered to either increase or decrease generation by the regional authority to ensure the integrity of the electrical grid. Commenter s added that there are aspects of Block 2 that are clearly outside the authority of the affecte d sources, e.g., utility companies with fossil fuel

- fired EGUs do not necessarily have authority over the transmission system which may be operated and controlled by an entirely separate entity. Commenter s said that 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.

Commenter s stated that new legislation would be required if, as the EPA' s IPM model indicates, the State of Louisiana will likely f ind its best compliance option to be to direct the retirement of RPS

- 2. Commenter s stated that Lafayette Utilities System (LUS) would be required to replace more than 50% of its generating capacity and more than 63% of its energy requirements with other ge neration alternatives. Commenter s stated this 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.

Commenter s stated that the responsibility to achieve the emission performance level may be assigned solely to EGUs, but it leads to some questionable scenarios. Commenter s stated that one scenario is when a regulated unit is subject to a System Support Resource Agre ement (SSR) that requires a unit to operate to maintain system reliability. According to commenter s , 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 White Pine No. 1. Commenter s asked, if a unit cannot run because of a CO2 limit, how would this interact with a SSR ordered by FERC? Commenter s said that the state has no control over dispatch or SSRs, and the EPA should explain how the interrelationship b etween 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 additiona l 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 substantial flexibility as to how they structur e 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. EPA believes that the preamble of the final rule describes mechanisms that a state may use to develop and implement and approvable plan. See s ections V.D, VIII.A, VII I.C and VIII.G of the fin al rule preamble of the CPP

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

Commenter s stated that the EPA has failed to describe the mechanisms states can use to develop

an d implement a plan that will reliably demonstrate compliance. Commenter s explained that Building block 2 cannot require states to interfere with the economic dispatch or reliable operation of the grid because states cannot interfere with the existing regul atory authority and enforcement responsibility of the federally authorized agencies that control unit dispatch decisions and plan for the reliable operation of the electricity grid. Commenter s stated that it is unclear how EPA would envision a regulatory r equirement be structured and enforced to achieve the types of redispatch assumptions that were used to derive the state goals. Commenter s indicated that a review of recent permits for NGCC units and other fossil units and found no examples of facilities th at have an enforceable minimum capacity factor limit. Commenter s stated it is unclear how EPA's assumed capacity factor could be effectively implemented and enforced because of various uncertainties related to whether the design, support infrastructure,

an d current permits and regulatory requirements for the existing NGCC fleet are sufficient for all units to sustainably achieve a 70% capacity factor. Commenter s stated the EPA's own modeled outputs indicate that the targeted 70 percent capacity factor used to create the state goals would not in fact be achieved by the proposed CPP. Commenter s asserted that the EPA must explain how states could develop a plan that produces results its own model refutes, or recognize that the proposal does not accurately refle ct the operation of the electricity grid

.

Commenter s stated it is unclear based on the text of the proposed rule whether the power plant operator or MISO would be responsible for establishing compliance with Building Block 2 for the purposes of enforcement . Commenter s stated it is 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
p ercent in any given year. Commenter s stated that the notion that a pricing or permitting scheme can be reliably correlated with a specific operating threshold at EGUs lacks empirical support and accomplishing such a task would require accurate long

- term fo recasts about the future trajectory of electricity use decades into the future, something even the federal government admits is beyond its capabilities

.62 Commenter s stated that the EPA's Building Block 2 is based on the faulty premise that generation from any NGCC unit 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. Commenter s stated that, in most states, electric generation is dispatched by an RTO or ISO, which calls up generation from EGUs within its system such that the lowest cost generating sources are dispatched first; thus, as an initial matter, neither a utility nor any state agency controls the relative dispatch of coal

- fired EGUs and NGCC units in most states. Commenter s stated that the areas covered by RTO and ISO systems typically do not coincide with state borders; rather, an ISO's footprint includes generating units in several states, and some states are divided between multiple ISOs. Commenter s stated that, 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 they are located. Commenter s added that there may be limited interconnection between the different dispatch systems in a state, and EGUs in one part of a state may lack the cross

- state transmission rights neede d to serve load in a different part of the state.

Commenter s stated that it must be recognized that natural gas pipelines are not subject to the proposed rule, and thus are under no regulatory obligation to undertake the necessary expansion. Commenter s sta ted that, even if they were to initiate 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.

Commenter s noted the EPA requested comment on whether it s hould use MWh from the increased utilization of NGCC units in Building Block 2 to decrease generation from a state's coal

- fired EGUs before decreasing generation from the state's oil/gas

- fired steam units (79 FR 64545). Commenter s stated the EPA neglects t o provide 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. Commenter s stated that the EPA has no authori ty to dictate which units are dispatched first, last, or otherwise and the EPA should not attempt to force state environmental agencies to usurp the authority for dispatch decisions which are made by utilities and independent system operators with oversigh t by state utility commissions and the Federal Energy Regulatory Commission. Commenter s 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 generation or o il/gas generation is based on a number of factors and clearly does not belong to EPA and therefore should not be considered.

Commenter s referred to comments made by Nevada DEP et al

. ("Agencies"), who question whether EPA has jurisdiction to authorize re

- d ispatch 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: Commenter s stated that Alaska should be exempted from 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 in the state. In the alternative, commenter s 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 time.

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

Commenter s stated that under building block 2 for Alaska, 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. (Commenter s noted that the calculation does not account for Heal y Unit 2.) Commenter s asserted that the EPA's assumption that all generation at the Healy Power Plant could be displaced by NGCC generation is false, both 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. Commenter s explained 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 and has a gross capacity of 27 MW. Healy Unit 2, or the Healy Clean Coal Project, has a nameplate capacity of 52.5 MW an d, like Healy Unit 1, uses the locally produced coal. GVEA is investing significant resources to reconstruct Healy Unit 2. This includes $190 million in investments 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 two transmission lines owned and operated by GVEA.

Commenter s stated that the NGCC EGUs that EPA's goal computation assumes can repl ace Healy's 80MW of coal generation are located more than 200 miles south of Healy, beyond the other end of the Alaska Intertie. According to the commenter s , this 80 MW transmission line is already generally operated at capacity to deliver hydroelectric an d natural gas generation to GVEA's customers in the Fairbanks load area, and there are no NGCC EGUs connected to the Fairbanks load center other than those connected through the south end of the Alaska Intertie. Commenter s added that the Healy units provid e voltage support to the Intertie, so that if the Healy units were not operating, the loss of the Healy SVC would result in a reduction of transfer capacity of approximately 1l MW. Given the current generating and transmission resources,
commenter s asserte d that Alaska cannot execute the second building block. Commenter s stated that, hypothetically, GVEA could have two options to replace Healy power: (1) upgrading the Alaska Intertie to allow more power north or (2) generating power locally from other fossi l

- fuel fired units. Commenter s asserted that both scenarios would substantially increase the cost of power in Fairbanks (already among the most expensive regions in the country for power), raise serious resource availability and reliability concerns, and c ompromise the state's ability to address the PM2.5 non

- attainment finding for Fairbanks. Commenter s believe d that these options are not realistic.

Commenter s went on to state that if the rule is applied to Alaska, the goal calculation should not include an y provision for re

- dispatch from coal units to NGCC units because, as discussed above, the coal and NGCC units in Alaska are separated 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. Commenter s concluded that Alaska cannot re

- dispatch coal generation at a reasonable cost.64 Comment 17: Commenter s stated building block 2 does not provide compliance options in certain cases.

Response 17: The EPA disagrees. We are providing states with substantial flexibility as to how they structure th eir plans to achieve the 111(d) requirements. The flexibility inc ludes, 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 period s. The Building Blocks are not 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.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:

Commenter s 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. Commenter s stated that, at the time of the issuance of th e proposed rules and as of December 1, 2014 there were no operating natural gas combined cycle units in Kentucky and, while Cane Run 716, the first CCGT in Kentucky is under construction and there are other units planned by TVA at the Paradise Steam Plant1 7, OMU and other LGE/KU transmission system participants have no access to such units. Commenter s stated that OMU, like all but 13 original TVA interconnected utilities, is prohibited from buying from TVA and thus, these future CCGTs provide no compliance option to OMU. Commenter s 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. Commenter s stated such a mandated power purchase agreement as a co ndition of OMU's compliance plan is most likely a violation of the Federal Power Act.

Commenter s stated that bringing CCGT power into the LGE/KU control area to serve OMU load from MISO or PJM entails increased transmission cost and would be subject to re call during Maximum Generation Events. Commenter s stated that, in Kentucky there is a lack of natural gas infrastructure: there are no existing NGCC plants in Kentucky and the natural gas supply and delivery infrastructure does not exist to sustain a force d conversion to a significant percentage natural gas based generation in a state where 93% of electric generation is from coal. Commenter s stated that, even if this were the most cost effective option for Kentucky's EGUs in a final rule, sufficient time to site, permit, engineer, procure and construct the required pipeline and natural gas storage capacity is impossible by the interim compliance date. Commenter s stated that, for a FERC regulated pipeline company to build new natural gas pipeline, they would first require a firm commitment from shippers on the proposed pipe before FERC would authorize the project. Commenter s stated the proposed rule and the RIA did not adequately account for the time of the construction of the necessary natural gas pipelines o r the cost to complete.65 Comment 18: Commenters asserted Florida’s import transmission capability is limited

. Response 18: The EPA disagrees. EPA is fully aware of transmission constraints for imports and exports to FRCC. We assume this is what the commenters mean, since FRCC is only the peninsular part of Florida, and transmission into coastal 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://www.epa.gov/airmarkets/powersectormodeling.html http://epa.gov/powersectormodeling

. 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 emission s tandards 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 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 reliability, fuel diversity, other regulatory requirements and infrastructure. The rule provides Flori da with the flexibility to meet the requirements in many different ways. 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:

Commenter s stated that, while the Proposed GHG Rule limits re

- dispatching to within a region's existing fleet (79 FR 34865), Florida's import transmission capability is limited to approximately 3,800 MW, or 6.6% of total capacity. Commenter s stated that Florida's ge ographical location and corresponding energy import limitations should minimize reliance on regional dispatch hypotheticals and confine Florida's re

- dispatch increases (for Final Goal computation) to those within the State going from 61 to 70 percent.

Com ment 19: Commenters expressed concern that the implementation of Building Block 1 and Building Block 2 will work against each other.

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

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

Impacts on Heat Rate66 Commenter s stated the EPA's goal of shifting coal generation to natural gas would result in increased heat rate for coal plants. Commenters provided the following additional information:

• Commenter s stated that implementation of Building Block 2, including the re

dispatch from coal to NGCC, would undermine Building Block 1 because, if Plant Lowman is forced to provide load following and ancillary services due to the increased dispatch of NG CC, Plant Lowman's heat rate is likely to increase because operational stability is the single largest factor in heat rate.

• Commenter s stated Building Blocks 1 and 2 are economically inconsistent, since on the one hand, Building Block 1 assumes emission re ductions from heat rate improvement projects at existing coal

- fired boilers, while on the other hand, Building Block 2 assumes increased utilization of NGCC units at the expense of coal

- fired units. Commenter s stated the EPA fails to acknowledge this incon sistency.

• Commenter s stated Building Block #2 will negate some if not all of the heat rate improvements from Building Block #1. Commenter s stated heat rate is increased when plants operate at lower loads, and the benefit of a heat rate improvement strategy is reduced at lower loads. Commenter s stated 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 red uction strategy (or strategies) implemented will not lower the annual average heat rate as much when compared to base

- load operation. Commenter s stated that, in some cases, any HRI improvements achieved by undertaking the relevant options described in Buil ding Block #1 could be negated by load

- cycling. Commenter s referred to section 5 of the S&L report performed for the NRECA and stated the following:

S&L evaluates the impacts on cycling load on HRI methods. 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 affect 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 be seen by the average operating capacity factors (AOCF)

- 96%, 95% and 87% respectively and graphi cally 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 increase over 1,500 Btu/kWh from high load to low load. This is a greater than 13% increase in heat rate. S&L stated, "as the AOCF decreases in 2014, the annual average net unit heat rate increased 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 B lock #2.

• Commenter s stated that, while the goal of the building block 2 is to reduce the operation of the coal

- fired EGUs and reduce CO2 emissions, analysis shows that the efficiency of the Wisconsin coal

- fired EGU fleet could fall as much as 5% due to heat rate increases br ought on as a result of applying building block 2 as67 proposed by EPA. Commenter s stated that, given their 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 reductio ns achieved by building block 1 are more than offset by the inefficiencies caused by building block 2; specifically, the result is a net loss of over 3% efficiency for Wisconsin's coal

fired fleet. Commenter s stated this result is contrary to the intent of BSER and further supports the conclusion that Wisconsin's maximum NGCC capacity factor should not exceed 37%.

• Commenter s stated that, under the Proposed Rule, coal

- fired EGUs would shift from providing baseload generation to cycling and/or increased load

- following operation and, as a result, coal

- fired EGUs would be operating at lower capacities with intermittent increases to meet peak demand. Commenter s stated that coal

fired EGUs are not designed for load

- following and cycling, which reduces their efficiency, thereby increasing heat rates. Commenter s 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. Commenter s stated that extra energy is required to shift a unit from low to higher loads to overcome inertia in the system. Commenter s stated the more frequently a unit must move up and down the load curve, the more excess energy will be required to produce the desired load and, thus, the unit will be less efficient on average.

• Commenter s stated that, under the Proposal, coal units would be operated more as peak demand units even though coal uni ts operate more efficiently as base load units. Commenter s stated that, if coal units are required to constantly change energy output then the units will be operating at less than peak efficiency and will not be able to obtain measurable heat rate improvem ents.

• Commenter s stated that cycling solid fuel units increases maintenance costs and shortens the unit's useful life as well as increasing emissions during the prolonged
start

- up and shutdown periods.

• Commenter s stated that decreased utilization of coal plants under Building Block 2 would result in greater costs and lower efficiency associated with running these plants at reduced capacity. According to the commenter s , when fossil

- fueled generators cycle on and off or ramp down to minimum generation, the thermal cycling of the components can lead to fatigue, creep, and fatigue

- creep interaction, resulting in increased maintenance and repair. Commenter s added that load

- following operation also creates more opportunities 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 cap acity factors.

• Commenter s 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 undertaken in conjunction with anoth er68 alternative, purchase or construction of another generation asset, or market power purchases. Commenter s noted that reduced utilization also adversely affects the heat rate of the EGU compared to full utilization.

• Commenter s stated that, as NGCCs become baseload resources under the proposed rule's dispatch assumptions, coal units operating at reduced loads and simple cycle peaking units operating at increased capacity factors will likely replace NGCCs as intermediate, load

- following units in many parts o f the country. Commenter s stated this type of operation reduces coal unit efficiency and would tend to worsen their emissions rates and could result in higher emissions than was assumed by EPA as a result of the re

- dispatch step. Commenter s stated that, in analyzing the proposed rule, EPA failed to consider the effect of increased coal unit ramping and simple cycle peaking unit utilization when determining the level of emission reduction achievable by NGCC re

- dispatch. EPA should also analyze the need for i ncreased load

- following generation that will likely occur as renewable generation increases.

• Commenter s stated that cycling coal

- fired units on and off could lead to increased pollution from unit startup and shutdown.

• Commenter s stated the re

- dispatch of coal

- fired generation to NGCC generation will necessarily reduce base

- load coal

- fired EGUs to load

- following EGUs, resulting in significant degradation of heat rate at the coal

- fired units which will offset all or part of the lower CO2 emission rate of the NGCC unit. Commenter s stated the degradation of heat rate caused by requiring a coal

- fired EGU that is designed to operate as a base

- load unit to continually scale generation up and down as re

- dispatch to NGCC units occurs will necessarily decrease therma l efficiency and increase the CO2 emission rate of the formerly base

- loaded EGU. Commenter s 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.

Commenter s stated that implementation of Block 2 affects other building b locks 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. Commenter s stated that increasing the capacity factor of NGCCs and subsequently reducing the capacity fa ctor of coal units under Block 2 will adversely affect the heat rate performance of the coal units from Block 1 because coal units will generally cycle on and off more frequently and swing load more often when they are used less, decreasing the efficiency of these units. Commenter s stated these building blocks are not additive for this reason.

Commenter s stated that EPA must establish a floor for 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%. Commenter s stated that, as a result, the EPA should not allow the capacity factor of Wisconsin coal

- fired EGUs to fall below 50% when determining bu ilding block 2. Commenter s stated that,69 in applying this criterion, the EPA must also maintain operation of all of the coal

- fired EGUs. Commenter s noted that significant investments have recently been made in these EGUs to continue their efficient operatio n into the foreseeable future.

Discourage Investment

Commenter s stated that implementation of Building Block 2, including the re

- dispatch from coal to NGCC, would undermine Building Block 1 because re

- dispatching from Plant Lowman to an NGCC would discour age continued investment at Lowman, which would make heat rate improvements unlikely. Commenter s stated the EPA fails to address why EGUs would make heat rate improvements if their utilization is undercut by increased NGCC utilization.

Comment 20: Commen ters expressed concern that the re

- dispatching of baseload units from coal

- fired EGUs to natural gas units could have unintended consequences that could increase the net output rate of CO2 emissions.

Response 20: The EPA disagrees. We do not expect the rule to result in over construction of new generation capacity or substantial increases in natural gas demand. We expect substantial reductions in greenhouse gas emissions from the utility power sector. 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

s ubstantial 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 per iod (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 reliab ility, 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 for the CPP Final Rule supporting the final CPP, a nd the Regulatory Impact Analysis of the CPP final rule.

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

Fossil Fuels

Commenter s 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 standards do not phase out one fossil fuel, coal, just to replace i t with another fossil fuel, natural gas, for power gen eration. Commenter s 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 designed. Commenter s suggested that goal achievements would be canceled out if states increas ed CO2 equivalent during the duration of the plan as a result of increased natural gas

- fired power plants.70 Commenter s expressed concern that the CPP will lead to an over

- build of new gas plants, with commercial lives of 30 or more years. Commenter s stated that, while some new gas resources are a necessary part of a clean energy transition, the best scientific consensus is that the entire globe, including the US, has to achieve near complete independence from carbon emissions to avoid the worst risk of clima te change by 2050; it is critical to avoid inducing too much new gas technology in 2020. Commenter s stated that an oversupply effectively removes the incentive to deploy additional technology; thus locking in a large amount of new gas resources will have t he side effect of locking out renewables and other new clean technologies, in both competitive market and regulated utility regimes, for an extended period. Commenter s stated this lock

- out will occur even if renewables become cheaper than traditional power technologies since it doesn't matter how cheap something is if no one needs it at all.

Commenter s expressed concern that the CPP could accelerate the lock

- in of large amounts of new natural gas generation, particularly in some regions, while generally del aying the deployment of tomorrow's cleaner and cheaper renewable energy and emerging competitive distributed energy resources. Commenter s stated the NRG warns that this could result in the overbuilding of new natural gas plants, which would reduce the ince ntive to add new renewable generation capacity to the grid, locking out energy resources that are truly clean

.

Commenter s stated the Proposed Rule's drive to increase natural gas consumption would have a negative effect on the expansion of renewable energy. Commenter s noted the EPA finds that, in light of low natural gas prices, market forces alone 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 BSER, the increased utilization of natural forces to favor natural gas power generation. Commente r s stated 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. Commenter s stated the EPA must revise the Proposed Rule so that it incentivizes RE and EE, not natural gas.

Hydro, Nuclear, Solar and Wind

Commenter s stated that achieving a set capacity factor for a specific fleet of units in states who have instituted deregulated electricity markets will be challenging. Commenter s stated that, while RGGI

- like programs do affect generator bid prices 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 co uld result in unintended outcomes, such as higher energy prices and the underutilization 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.

Commenter s stated that requiring a 70% NGCC capacity factor will alter market design, result in less utilization of zero emission resources, and make the attainment of Building Block 3 more costly.

Commenter s stated that forcing states to re

- dispatch 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. Commenter s stated that, because CO271 emissions are lower when NGCCs dispatch in concert with ren ewable energy resources rather than alone, the Proposed Rule would increase, rather than decrease, emissions in areas with a high integration of variable energy resources.

Commenter s stated that, while the Smith units and Buck were dispatched significantly above 70% in what are considered peak months, in the remaining months of October, November, April, and May, nuclear generation supplies the majority of the utilities' baseload needs. Commenter s stated that, in order to achieve the NGCC dispatch target, No rth Carolina would be required to cycle down nuclear units and dispatch NGCC units in their stead. Commenter s stated that, due to their operational characteristics, nuclear units are not capable of cycling to allow for NGCC generation during these off

- peak months. Even if technically feasible, commenter s stated that cycling of nuclear generation would be counterintuitive because nuclear generation produces zero CO2 emissions while NGCC does not. Commenter s stated that it is inconceivable that EPA intended s uch an illogical result when propounding this building block. Commenter s stated that any building block based on increased natural gas dispatch should be directly based on the ability of a state to increase its NGCC units' dispatch consistent with sound en vironmental and economic principles. Commenter s 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 feasible in North Carolina.

Commenter s expressed concern that Arkansas receives almost zero credit for nuclear and hydroelectric power plants that produce no greenhouse gas emissions.

New York

Commenter s stated that the EPA's re

- dispatch approach fails to account for two important considerations relevant to New York. Commenter s stated 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) given the location of NGCC units within New York, the extent of t he re

- dispatch assumed would require not using available generation from non

emitting resources to "make room" for the NGCC output, undermining the intended impact on overall CO2 emissions. Commenter s stated that the flaws with the Clean Power Plan that wo uld compromise reliability in New York stem from key assumptions within the Building Blocks that are not technically sound and result in CO2 emissions reduction targets for New York that are unreasonable and unworkable within the timeframes provided. Comme nter s stated that no amount of flexibility afforded in the manner in which New York State may seek to comply with the Clean Power Plan can make up for requirements that are inherently unreasonable because they are based on flawed assumptions in the Buildin g Blocks.

Commenter s 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 generati on resources. Commenter s 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 prod uce more electricity than the combined total of the demand in that portion of the state and the transmission transfer capacity to72 the areas of greater demand to the southeast. Commenter s stated it is not possible to run NGCC resources at the levels assumed by the EPA without reducing the use of generation from non

emitting wind, hydropower, and nuclear units that are also located in the western portion of the state. Commenter s stated it would be illogical and counterproductive to pursue such a re

dispatch, as it has the perverse effect of substituting NGCC generation for non

- emitting renewable generation in the name of reducing CO2 emissions.

Comment 21: Commenter s stated that, despite concerns regarding methane leakage, expanded dispatch of NGCC can provid e 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:

Commenter s stated the much lower GHG footprint of gas

- fired generation (as compared to coal

based power) has been confirmed by almost all independent observers despite concerns regarding methane leakage (sometimes termed fugitive emissions) associated with shale gas production.

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

Response 22: The EPA disagrees with the apparent presumption that methane emissions from natural gas systems rises between the baseline scenario and a modeled Clean Power Plan scenario. See section V.D. of the final rule preamble of the CPP and the Regulatory Impact Analysis of the final CPP or the EPA’s response to this comment . Discussion of “fugitive methane,” howe ver is outside the scope of the final rule.

Natural Gas

-- Climate Change

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

Commenter s stated that, although natural gas is currently a cheap form of electric generation, it is not a long

- term solution. Commenter s stated that emerging technologies like wind and solar are rapidly decreasing in price and already employing thousands of Missou rians. Commenter s stated that, with strategic investments to reach new economies of scale, wind and solar will soon become the cheapest form of electric generation available. Commenter s stated that, as a nation we should not waste this regulatory opportuni ty on technologies that will always be based on finite resources that emit large amounts of carbon into our atmosphere.73 Commenter s stated natural gas is not clean energy. Commenter s 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.

Commenter s stated that the proposed rule should be improved so that it ensures that states are pursuing renewable energy and energy effi ciency as the first priority. Commenter s stated that the EPA should not approve compliance measures that would incentivize the construction or utilization of new fossil fuel generation. Commenter s also stated that the EPA should not undersell what states c an do with RE and EE, which commenter s stated will help states reach their targets more effectively. Commenter s stated that the proposed rule will increase gas generation with a potential increase of 180 percent by 2020. Commenter s stated that no CPP shoul d incentivize the expansion of fracked gas in the electricity sector.

Commenter s referred to a Stanford University study titled, "Changing the Game: Emissions and Market Implications of New Natural Gas Supplies" and stated that the study shows that the sh ale gas boom produced only modest benefits long

- term for greenhouse reduction, in part because the increase in natural gas use might discourage efforts to conserve energy and boost efficiency. Commenter s noted the Stanford study did not address some of the debate about methane leaks from hydraulic fracturing drillings and other production supply chains steps.

Commenter s objected to the Clean Power Plan as written because it drives much of the electrical utility generation market to natural gas power over c lean energy solutions. Commenter s stated that the NGCC units are energy assets with 30 or more years of life that take investment away from clean energy solutions and creates a new greenhouse gas carbon lock

- in cycle with natural gas generation plants for the U.S. energy market place. Commenter s stated that a 2014 University of California

- Irving study makes the case that with higher natural gas supplies in various scenarios the renewable energy generation demand decreases and the potential for greenhouse ga s reduction diminishes. Commenter s stated that the authors of the report argue that only greenhouse gas reduction policy, such as a carbon tax or carbon emission caps will result in significant reductions. Commenter s 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 stora ge, and development of existing as well as future renewable energy generation alternatives. Commenter s 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 generation grid does not exist today in the U.S.

Commenter s asserted the Clean Po wer Plan should promote a rapid transition away from fossil fuels towards renewable sources of power, such as wind and solar. Commenter s stated that academic studies question whether natural gas has any significant climate benefit over coal because of the leakage of methane, which is 86 times more potent than carbon dioxide over a 20 year span. Commenter s stated that, even without taking into account methane leakage, however, natural gas is a fossil fuel that emits greenhouse gas pollution when burned and t hus cannot be part of a common

- sense solution to climate disruption. Commenter s stated the Clean Power Plan's promotion of natural gas as an alternative to coal would continue our reliance on fossil fuels for many decades and incentivizes more investment i n dirty energy infrastructure.74 Commenter s stated that instead of promoting the increased use of gas, we must transition rapidly to truly sustainable energy sources. Commenter s stated that increased reliance on fracked gas at best significantly delays an d at worst may altogether displace the development of solutions such as wind, solar, and energy efficiency.

Commenter s stated the promotion of greater dispatch of gas

- fired power plants as a substitute for coal should be removed from the description of bu ilding block #2. Commenter s 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 pursuant to building blocks #2 or #3. Commenter s stated the EPA should set much more aggressive goals for zero

- emission renewables. Commenter s stated avoiding climate catastrophe will require that the U.S. swiftly and dramatically reduce its consumption of both coal and gas. Commenter s stated that, because natural gas does n ot present a clear climate benefit 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.

Commenter s objected to the proposed regulations because natural gas electric ity generation would be 18

- 19 percent higher by 2030 under the EPA's plan than it would be without the plan. Commenter s 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 s tated 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 years. Commenter s 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 the middle of this century.

Commenter s stated the trajectory of increasing use of natural gas is incompatible with the far deeper reductions in CO2 emissions that will be required in the decades following 2030. Commenter s stated the CPP has given no consideration to this issue. Commenter s stat ed there is also the potential issue of the cost of stranded natural gas assets in the context of the decreases of natural gas use that are going to be necessary. Commenter s stated this should factor into the EPA's analysis of the potential problems associ ated with increasing natural gas production for use in the electricity sector. Commenter s stated that, because of the venting and leakage rates from the natural gas industry, it is important that the best system of emission reduction not significantly incr ease natural gas use in electricity production, until a more definitive assessment in its favor is demonstrated. Commenter s stated that, 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.

Commenter s suggested the trajectory of short

- and medium

- 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. Commenter s stated this report estimates that a trajectory limiting global average temperature rise to 2 o C would have to reduce global greenhouse gas emissions between 78 and 118%. Commenter s stated the former value implies an essentially total elimination of fossil fuels in the U.S. if the differential responsibilities of developed countries under the UNFCCC are taken into account, and the latter figure means ne t CO 2 removal from the atmosphere. Commenter s stated the EPA's natural gas use trajectory is even more intensive than that in the 2014 AEO of the EIA, which projects that 30.6% of electricity generation in 203075 would use natural gas. Commenter s 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. Commenter s stated the EIA reference case for natural gas in EIA AEO 2014 projects total natural gas supply for U.S. use of 29.56 trillion cubic feet in 2030. Commenter s stated that, using a 2.5% venting rate, 20

- year warming potential of 86, and assuming that 80% of natural gas is burned as fuel, the total emissions from the natural gas fuel system would be about 2.3 b illion metric tons of CO 2 eq in the year 2030. This amounts to about 38% of 2010 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.

• Commenter s stated tha t natural gas development leads to global warming. Commenter s stated that natural gas may emit half as much CO2 as coal when burned, but it contributes methane, a greenhouse gas with 300 times more global warming potential than CO2. Commenter s also stated that natural gas development leads to global warming through massive deforestation for the purpose of constructing injection wells and infrastructure. Commenter s used Pennsylvania, which has lost hundreds of thousands of acres of old

- growth forest
to natur al gas development, as an example. Commenter s stated that this deprives the plants of the natural process of transpiration.

• Commenter s stated that regulatory agencies should cease granting fracking permits and should cease saying that natural gas is the a nswer to atmospheric pollution and climate change. Commenter s stated that natural gas development will only deepen the nation's reliance on fossil fuels and accelerate climate change when there should be a focus on renewable sustainable energy.

• Commenter s 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. Commenter s stated that natural gas contributes to greenhouse gases; it does emit only about half as much carbon as coal when burned for power, but it emits methane over its life cycle. Commenter s stated that starting at extraction through processing and transportation, natural gas emits methane from leakage, the amount of which is about one half to thre e times as much methane as estimated. Commenter s pointed out that methane is a much more potent gas than CO2. Commenter s cited extraction as a problem with natural gas; all of the easy natural gas has been depleted, and fracking is the only economical opti on left. Commenter s attributed a lot of the methane to fracking and expressed support for the EPA's support to control leakage.

• Commenter s stated that the proposed rule is deficient in its reliance on a building block of replacing coal generation with natu ral gas plants, which the rule assumes will be less carbon intensive. Commenter s stated that the proposed rule fails to increase efficiency standards for natural gas plants. Commenter s stated that there is scientific evidence that the proposed rule underst ates the climate harms of natural gas generation by failing to use reasonable means to account for methane76 leakage and the intense and short

- term greenhouse gas effects of atmospheric methane. Commenter s stated that encouraging natural gas development woul d impose substantial externalities on the communities directly affected by drilling infrastructure and fracking.

• Commenter s expressed concern that a switch to natural gas is not the solution we need if we are serious about protecting the environment from a ll effects of power generation, not simply carbon emissions. Commenter s stated various components of natural gas process leak methane, which is a greenhouse gas 86 times as potent as carbon dioxide over a 20 year scale according to the intergovernmental pa nel on climate change, and leakage above three percent is enough to negate the climate benefits of natural gas over coal.

• Commenter s stated that replacing coal with carbon cannot get us to the 80% reductions needed by 2050.

• Commenter s stated that the promotion of greater dispatch of gas

- fired power plants as a substitute for coal should be removed from the description of building block #2. Commenter s explained that, because natural gas does not present a clear climate benefit over coal when full lifecycle impacts are considered, it is unsound climate policy to craft a rule that favors one fossil fuel over the other. Commenter s stated the rule should not accept the greater dispatch of gas

- fired power plants or replacement of coal

- fired p ower plants with gas as measures of compliance pursuant to building blocks #2 or #3. Commenter s stated that avoiding climate catastrophe will require that the U.S. swiftly and dramatically reduce its consumption of both coal and gas.

• Commenter s stated the proposed regulations encourage 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. Commenter s stated replacing CO2 with methane is not a " clean power plan." Commenter s stated several independent studies indicate 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 transport, a leakage rate that w ould make natural gas just as bad, or worse than, coal as an overall driver of climate change. Commenter s stated a series of scientific studies clearly demonstrate that methane is not an environmentally acceptable alternative to coal. Commenter s stated the political pragmatism of the CPP's encouragement of natural gas cannot be justified by real scientific or economic analysis. Commenter s stated methane is not a "bridge fuel"; it will lock us into a fossil

- fuel dependent future, and is therefore a road to c limate chaos. Commenter s stated methane is not a clean alternative to coal and fracking, the process by which most natural gas is now produced, is environmentally destructive and produces fugitive methane emissions that contribute much more to climate chan ge than a commensurate amount of carbon dioxide. Commenter s stated our aging methane infrastructure leaks, and should be gradually decommissioned, not expanded. Commenter s stated the economic and ecological damages resulting from coal and oil users77 switchi ng to methane will plague us for several decades to come, as those who have invested in new infrastructure will be loath to abandon it for more climate

friendly equipment such as is needed to support geothermal, solar, and wind.

• Commenter s expressed conce rn 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. Commenter s stated the energy prices will remain volatile due to global factors beyond our co ntrol

- so long as we are paying for carbon

- based fuels, as opposed to utilizing "free fuel" solar

- , wind

- , and geothermal

- based technologies. Commenter s stated that self

- sufficiency should begin with energy efficiency, rather than building yet another car bon bubble.

• Commenter s stated the EPA should be cautious in promoting 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 than good from a climate change per spective. Commenter s suggested that the leakage of methane during the extraction, processing and transportation of natural gas needs to be evaluated. Commenter s stated recent studies suggest that a leakage rate higher than 2.4

- 3.2% will mean that natural g as is more of a global warming threat than coal is.

• Commenter s stated that the EPA should re

- visit the definition of re

- dispatch and its usefulness to achieve the goal of reduced emissions. Commenter s stated that there is no legally binding language in th e proposed 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. Commenter s stated that zero

- emissions standards sh ould mean zero emissions and have no permitted allowable releases or venting of permissible levels of toxic air contaminants or radioactive releases.

• Commenter s stated that federal action is also needed to ensure that decreased electricity sector demand fo r coal leads to corresponding decreases in coal production, rather than a shift to coal exports, which would undermine EPA's conclusion regarding a net decrease in methane emissions.

• Commenters expressed concern over the fugitive emissions that are assoc iated with natural gas. Methane is greenhouse gas much more potent that CO2, and the commenters feared that more leakage occurs in the transportation and use of natural gas than is reported. Commenters stated that switching to natural gas will not represen t true progress in the fight against global 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 impacts.78 • Commenter s expressed concern that fracking threatens water supplies and releases pollutants into the air including benzene, formaldehyde, and particulate
matter.

• Commenter s expressed concern that the proposed Clean Power Plan BSER encourages unsustainable practices that neither reduce climate change nor best protect environment and human health. Commenter s expressed 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 no t all, natural gas will soon come from unconventional sources including shale gas retrieved by hydraulic fracturing. Commenter s stated that the science on fracked gas is controversial, and it is unclear if the lifecycle of fracked gas causes fewer greenhou se gas emissions than other carbon based sources. Commenter s also stated concern with possible ground water and surface water contamination from fracking practices. Commenter s also stated that it is unclear the extent to which fracked gas depletes

scarce w ater resources.

• Commenter s stated that the adverse impacts of fracking are greater than coal.

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

• Commenter s stated that the CPP promotes fracking, and fracking contributes to climate change and threatens Americans' air and water quality. Commenter s cited a 2 010 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 whic h accompanies fracking. Commenter s cited a University of Texas at Arlington study in Parker County, TX, which found an unacceptable level of methane (83 with 10 being the acceptable value) in the groundwater which the study contributed to nearby fracking. Commenter s also mentioned the link between the disposal of toxic fracking waste in injection wells and earthquake activity in many states.

• Commenter s stated that unconventional gas wells emit toxins including benzene and radon as well as emitting methane; the toxins are then sent through compressor stations and pipelines. Commenter s noted that the overall methane emissions are considerably higher than the official inventories report.79 • Commenter s suggested that the EPA consider water quality and quantity issues related to fracking before encouraging additional fracking. Commenter s 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 disclosure rules under the Toxic Substance Control Act (TSCA).

• Commenter s stated the EPA's modeling assumptions do not take into account outside

- the

- fence limitations such as water withdrawal and thermal restrictions.

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

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

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

• Commenter s stated that increased d ependency 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. Commenter s stated methane is a dangerous substitute for c oal: fracking destroys landscapes, contaminates air and groundwater, and dredges up hazardous chemicals and radioactivity,11 some of which are piped directly into customers' homes, and all of which is leading to a public health crisis. Commenters stated

m e thane pipelines fragment ecosystems, permanently scarring the countryside and threatening the safety of our communities with explosive failures. None of these terrible effects are factored into the CPP. Commenter s stated the EPA must factor in the cost of the 72 trillion gallons of water used to operate the current 500,000 fracking wells. Commenter s stated the huge amount of water used for fracking, which becomes toxic waste in the process, will seriously drain the country's fresh water supply, causing loss of safe wells and loss of water available for agriculture. Commenter s stated that water shortages and even drought are common results of climate change, and water systems play a crucial role in the balance of the planet's ecosystems; by removing trillions of gallons of fresh water from the finite world water supply, fracking is exacerbating both climate change and the results of climate change.80 • Commenter s expressed concern about several adverse impacts related to natural gas. Commenter s stated that natura l gas obtained by hydraulic fracturing is not clean from a public health or climate perspective. Commenter s stated that fracking is associated with local and regional air pollution, adverse birth outcomes and contamination of drinking water. Commenter s que stioned the metrics used by the EPA to predict the effectiveness of this strategy and stated that emission estimates should encompass the entire life cycle instead of just carbon emissions from the smokestack. Commenter s stated that it may also be necessary to differentiate between fracking and conventional drilling, since these extraction methods have different carbon intensities.

• Commenters also expressed concern with potential negative impacts from the process of hydra ulic fracturing or "fracking" to extract natural gas. Commenter s stated that whether the life cycle of fracked gas in fact causes less greenhouse gas emissions than those from other carbon based sources is unclear that the extent to which fracked gas cause s contamination of ground water and surface waters is unclear and that the extent to which fracked gas causes depletion of scarce water resources is unclear. Commenter s asserted that both the health effects and environmental impacts of fracked gas are stil l very unclear.

• Commenter s expressed concern that the process of fracking will be with us for a very long time. Commenter s stated that currently about 30% of our national power plants rely on natural gas to generate electricity and, if the 38% of coal

fir ed power plants are converted under the re

- dispatch program, then 68% of our power plants will rely on fracked gas. Commenter s concluded that, if 68% of the nation's power is dependent on natural gas, then the process of fracking will be with us for a very long time and natural gas will not be a bridge fuel.

Commenter s stated that the Proposed Rule fails to account for the fact that increased use of natural gas will cause a further increase in hydraulic fracturing and associated methods, and their attendant environmental damage. Commenter s stated that hydraulic fracturing and associated methods have significant negative health and environmental impacts that the agency must evaluate in determining whether its decision to increase those activities does in fact constitute BSER as defined in section 111(a)(1), which requires 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. Comme nter s requested that EPA re

- visit many of the assumptions underlying its conclusion that switching 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 for hydraulic fracturing to mitigate associated adverse impacts. Commenter s recommended encouraging best practices related to (i) having a systematic approach to assessing and managing human rights and health impacts, (ii) ensuring adequa te community consultation to minimize impacts, (iii) requiring disclosure of the chemicals used in the fracking process, (iv) using best practices 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 Dioxide81 Several commenters were concerned that the global warming potential of methane be accurately portrayed.

• Commenter s stated that methane is 34 to 86 times more harmful than CO2. Commenter s 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 reductions can be achieved by simply running ( dispatching) gas

- fired power plants more and coal

- fired plants less

- the primary emphasis for building block #2 of the rule. Commenter s stated that, since

re

- dispatch relies on excess capacity, this is an inherently temporary measure in the face of growin g demand; unless fossil fuel alternatives become a much greater portion of the nation's energy portfolio, greater dispatch of existing gas

- fired facilities will simply hasten the eventual need for additional new gas

- fired capacity or the need to resume the increased dispatch of coal.

• Commenter s stated that the rule also misstates methane's 100

- year Global Warming Potential (GWP), which was upgraded by the IPCC in 2013 from 25 to 34. Commenter s stated that, given the need for rapid GHG reductions to protect health and the plan's goal to lower emissions by 2030, the 20

- year GWP, at 84, is more relevant. Commenter s stated that, regardless of which GWP is used, measurements of methane over gas fields suggest that leaks are large enough to eliminate any advantag e over coal even without inclusion of leaks in pipelines and storage facilities. Commenter s stated that they understand that the EPA intends to address methane emissions from oil and gas development in the future, but they are pessimistic that discrepancie s in measurement can be resolved and adequate reductions achieved during the time frame of the Clean Power Plan. Commenter s stated that economic analyses predict that increased exploitation of natural gas will not result in lower greenhouse gas emissions in the absence of carbon pricing because low cost will increase demand and discourage investment in clean
energy.

• Commenter s stated that, in discussing the proposed rule, the EPA and advocates for the gas industry often refer to emissions of "carbon" instead of "carbon dioxide." Commenter s stated this is misleading because the rule regulates only CO2; however methane is 34 tim es 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. Commenter s stated climate scientists agr ee that rising levels of greenhouse gas in the atmosphere are causing the Earth 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 per mafrost 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. Commenter s stated the EPA discounts these effects by using an outdated GWP f or methane, and by focusing its analysis on the hundred year timeframe.82 • Commenter s stated 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 reductions can be achieved by simply running (dispatching) gas

- fired power plants more and coal

- fired plants less, the primary emphasis for building block #2 of the rule. Commenter s 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 alternatives become a much greater portion of the nation's energy portfolio, greater dispatch of existing gas

fired facilities will simply hasten the eventual ne ed for additional new gas

- fired capacity or the eventual need to resume the increased dispatch of coal. Commenter s stated that, while the rule does not specifically rely on the construction of new gas

- fired facilities in the development of targets for buil ding block #3, the construction of new gas

- fired power plants are nevertheless contemplated as a means of achieving compliance and intrinsically incentivized because success is measured only by reduced emissions of carbon dioxide. Commenter s stated these a re fundamental problems with the rule as presently structured. Commenter s stated the most comprehensive approach to regulating greenhouse gas emissions would involve setting targets that account for not only carbon dioxide, but the full

- cycle of total gree nhouse gas emissions, including methane lost to the atmosphere prior to and during combustion.

Time Dependent Impacts

Commenter s stated that potentially higher upstream methane emissions and their time dependent impacts, as well as the costs of addition al climate change mitigation efforts, should be taken into account by the EPA. Commenter s stated the effectiveness of the EPA's policy formulation regarding upstream methane emission is dependent on two important assumptions: 1) an expectation of the conti nuation of historical emissions reductions, achieved by voluntary emissions reductions on the part of natural gas suppliers, 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 methane emissions to CO2

- equivalent quantities. Commenter s stated it is because of these assumptions that, despite the growth of natural gas production, the agency expects a net reduction of upstream methane emissio ns. Commenter s stated the EPA's calculations simulate a constant level of effort toward voluntary reductions into the future, as noted in the Regulatory Impact Analysis published along with 111d, but no corrective measures are detailed in case voluntary re ductions do not occur. Commenter s 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 accordingly. Commenter s stated that significant additional upstream emissions reductions are required when the time

- dependent emissions impacts of methane are recognized.

Commenter s stated that a simple scaling analysis illustrates the risk of underestimating the resulting methane impacts: if upstream methane emissions from natural gas increase proportionally to the projected gas production increase

- and upstream coal emissions decr ease by the same mechanism

- 2030 emissions in CO2

- equivalent terms would be between 22% and 27.5% lower, instead of 30% lower, than 2005 emissions; while a mean reduction of 25% is still significant, it demonstrates the high sensitivity of reductions to a ssumptions about upstream83 emissions reductions; and a trajectory of 2% reductions per year between 2011 and 2030, both for coal and gas upstream emissions, would be required to allow the 30% target (compared to 2005 levels) to be reached in 2030.

Commente r s stated that CO2 and methane emissions outcomes are interrelated through the choice of energy sources, because both gases are emitted in differing proportions in the life cycle of various fuels. Commenter s stated that, even if different greenhouse gases are regulated by separate policies, coupled effects can be understood and addressed by comparing gases on a single scale, which requires a conversion of impacts into carbon dioxide equivalent units. Commenter s stated the most widely used equivalency metric , the global warming potential (GWP (100)), assigns values to each gas depending on the ratio of its cumulative radiative forcing contribution, over a time period of 100 years, to that of carbon dioxide; however, the associated conversion factors and the r esultant emissions impact remain constant over time, which does not reflect the time

- dependent effects of short

- versus long

- lived greenhouse gases. Commenter s stated a new set of dynamic metrics captures the impact of emissions timing relative to an inten ded radiative forcing stabilization year, based on a target of stabilizing radiative forcing at 3 W m

- 2, a level that is consistent with commonly

- cited climate policy goals. Commenter s stated these dynamic metrics assign a higher conversion factor to each unit mass of methane the closer in time that the gas is emitted to the stabilization target. Commenter s stated that, using the instantaneous climate impact metric (ICI) to assess the CO2

- equivalent value of methane in the years 2020, 2025 and 2030, estimat ed emission reductions do not reach the target 30% reduction of power sector CO2

- equivalent emissions by the year 2030 (compared to 2005 levels). Commenter s stated that, based on the ICI, emissions reductions range between 22% and 18.2% in the near term (2 020), compared to the anticipated 27% (2020 compared to 2005), and between 20.6% and 7.9% in the long term (2030), compared to the anticipated 30%. Commenter s stated the wide range of estimated emission reductions required is a result of uncertainty estima tes for methane emissions from natural gas systems and coal mining, published in the 2013 US GHG Inventory. Commenter s stated that higher percentages of emission reductions are generated assuming a continuation of historical 2% per year methane emissions r eductions from natural gas production overall between 2005 and 2012 until the year 2030; and lower percentages result from upper bound EPA estimates. Commenter s stated these results demonstrate that even using lower bound estimates for upstream coal and ga s emissions, the projected emissions reductions (

- 16.4%) are roughly half the expected percentage for 2030 (30%), when climate stabilization goals are taken into account.

Commenter s stated the plausibility of EPA's expectations regarding upstream emissions reductions can be assessed by looking at past achievements. Commenter s stated that, between 2005 and 2012, methane emissions from natural gas systems decreased by 14.5%, which corresponds to a roughly 2% reduction per year. Commenter s stated that, during the same period of time, the coal and gas industry together achieved a 1.4% annual reduction in coal and gas upstream emissions. Commenter s stated that, despite these accomplishments, addressing the time

- dependent effects of GHG emissions will require sign ificantly larger efforts: the closer methane is emitted to a target stabilization year, the higher its impact may be. Commenter s stated that, as a consequence, the margin for allowed methane emissions becomes smaller and smaller over time, requiring tighte r constraints on emissions despite rising production levels. Commenter s stated that, as an example, a 30% reduction of overall GHG emissions (in carbon dioxide equivalent units) would require annual upstream emissions reductions in the range84 between 4% and 12%; percentages that are between twice and six times as large as what has been achieved by the industry in the past. Commenter s stated that, even in a scenario with 2% annual emissions reductions starting in 2011 (the base year of EPA's calculations), em issions reductions based on time

- dependent metrics would only be in the order of 20% in 2030, compared to 2005 levels (instead of the projected 30%).

Commenter s stated that, while this calculation leads to quantitative targets for reducing upstream methan e emissions, it is also important to highlight the opportunities to meet these targets. Commenter s stated that a number of recent studies indicate that not all devices in natural gas production and processing contribute equally to upstream emissions, sugge sting that knowledge of the distribution of upstream emissions across devices and sites can create opportunities for regulators to take action. Commenter s stated that well

- designed regulation might allow for significant reductions with limited cost increas es. Commenter s 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 2014 study of well pads in Pennsylvania identifies several hi gh

- emitting pads responsible for a 4

- 30% range of regional methane flux. Commenter s stated that, in a projection of 2018 oil and gas methane emissions by source category, a recent ICF International study attributes roughly 40% of methane emissions to only five device types. Commenter s stated that, comparing direct measurements in different locations Allen et al. find significant variability. Commenter s 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 should target geographical and device

- specific
super

- emitters. Commenter s stated that more data on high

- emitting devices is needed

- heavy tail distributions in current samp les indicate that super

- 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.

• Com menter s stated that if methane leakage is between 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. Commenter s stated that private testing shows that there are places where it is 20 percent, and L.A.'s is 17 percent. Commenter s stated that leakage from distribution is a problem in cities like Atlanta, and Atlanta is not closely monitoring it.

• Commenter s stated th at natural gas powered generation would result in a 40 percent emission reduction, but this could result in methane leakage at any point in the process. Commenter s noted that the leakage rate is higher than what the EPA uses in its formulas. Commenter s sta ted that leaked methane is 100 time more harmful than CO2 emissions, and natural gas usage would lead to an increase in fracking that endangers the public and freshwater resources. Commenter s stated that the technology forcing requirements of the CAA shoul d be enforced by requiring increases in efficiency at existing natural gas plants.85 • Commenter s expressed concern that the phasing out of older coal

- fired power plants by increasing electricity generation at natural gas

- fired power plants may result in grea ter emissions of fugitive methane from the natural gas distribution network.

• Commenter s expressed concern that pollution is created at several stages in the production and use of natural gas, including removal from the earth, transport, compression, and u se to create electric power. Commenter s noted that natural gas extraction is subject to leakage and loss of methane 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 pe riod. According to the commenter s , studies indicate that methane leakage at levels above 3% is enough to negate the climate benefits of natural gas over coal. Commenter s believe d that the EPA may be proposing in the near future a rule that addresses methan e emissions from EGUs and other sources, which commenter s welcome. Commenter s recommended that the 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 cleaning up methane pollution from its natural gas sector, and Ohio, which requires natural gas drillers to conduct quarterly inspections to detect and fix leaks in their systems. Commenter s also stated that concerns have been raised about the effects of natural gas extraction on drinking water supplies due to the use of fracking. Commenter s recommended that the Proposed Rule acknowledge the potential dangers of fracking and that states take all precautions necessary to protect drinking water supplies f rom the effects of fracking.

• Commenter s stated the EPA's failure to use independently

- produced and peer

reviewed data and analyses about natural gas venting and leaks may hide critical errors that would preclude designation of natural gas as BSER. Comment er s stated that, if natural gas venting and leak rates are significantly higher than the EPA estimates

-- and published estimates indicate that they may well be

-- the positive impacts of displacing coal by natural gas generation, could be largely or completel y negated, especially if the 20

- year warming potential of methane is used. Commenter s stated it is essential to consider effects on this shorter time frame since greenhouse gas accumulations are now creating impacts faster than previously estimated. Commen ter s stated that it is now estimated that essentially complete summer Arctic ice melting ' a potential 'tipping point' ' may happen on a ten to thirty year time frame.

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

• Commenter s stated methane leaks associated with natural gas us ed in the combustion processes for thermal electric power production should be included in the accounting for electricity production. Commenter s stated that substituting natural gas for coal lowers carbon dioxide during combustion, but the leakage rate86 of natural gas during production and transport can far exceed the reduction in carbon dioxide equivalents. Commenter s stated that natural gas that is supplied with certified zero leaks should get the full credit, but all other sources would count only the dif ference between the avoided emissions from not burning coal and the actual global warming from burning natural gas including the warming due to leaks. Commenter s stated that, while the leakage of natural gas is a carbon intensity continuum, one may think o f natural gas with few or no leaks as "low carbon natural gas,'' and natural gas produced with large leaks as "high carbon natural gas." Commenter s stated that, in some cases, the global warming associated with "high carbon natural gas" will exceed that of coal combustion. Commenter s stated that, perhaps coal bed methane leaks associated with coal mining should be counted as well in determining the baseline for coal consumption. Commenter s stated that often the shorter lifetime of methane is cited as a factor to consider, but for several hundred years, it traps more heat than carbon dioxide, and when it disappears it is converted into ultra

- long lasting carbon dioxide.

• Commenter s stated the best science shows that the systemic venting and leakage of methane which occurs during extraction, processing, and transport, along with carbon dioxide released during its combustion, negates any meaningful benefit that gas may have over coal with respec t to climate change. Commenter s stated that real

- world measurements by the National Oceanic and Atmospheric Administration and several other independent "top

- down" analyses indicate that at least 3% and potentially more than 7% of methane from natural gas is lost to the atmosphere prior to burning, far exceeding EPA estimates, which have been increasingly criticized by the scientific community as wishful thinking. Commenter s stated that, based on the most recent IPCC 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. Commenter s stated that, when the full life

- cycle emissions of methane are considered, it becomes clear that switching from coal to gas has little cli mate benefit and could in fact make matters worse. Commenter s stated that, depending on the extent to which states try to comply with the rule's meager targets by switching from coal to gas instead of taking useful action like improving the efficiency of e xisting power plants or renewables, carbon dioxide reductions could be substantially masked by the climate driving impacts of methane.

• Commenter s stated that natural gas is not a satisfactory "bridge" fuel. Commenter s stated that methane emissions from th e production, processing, and transportation of natural gas need to be dramatically reduced. Commenter s stated that investors should be put on notice now as to when the end of the bridge will be reduced. Commenter s stated that natural gas may burn more cle anly than coal (it emits about half as much CO2 as coal), but it is not "low carbon" in any realistic sense since it results in methane leaks from production and distribution. Commenter s stated that the methane leaks offset any apparent advantage of using natural gas since methane is an extremely potent greenhouse gas; methane emissions may be 9 to 10 percent of production. Commenter s stated that the end87 of "bridge" should be defined, and investors need to be given a definite date as to when new natural gas plants would need to be replaced with zero

- emissions power, which would probably be before 2040

- 2050. Commenter s stated that investors would otherwise invest more in natural gas plants and will face more stranded costs than is reasonable. Commenter s state d that the sooner we move to

zero

- carbon generation, the better.

• Commenter s 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 is from conventional drilling. Commenter s stated methane is the main component of natural gas, and it is leaking into the atmosphere at approximately one and one half times the rate estimated by the EPA. Commenter s stated that, while methane degrades more quickly in the atmosphere than carbon dioxide, pound

- for

- pound it is more efficient at trapping heat. Commenter s stated the IPCC now estimates that a pound of methane traps 87 times as much heat as a pound of carbon dioxide in the 20 years after being emitted, and 36 times as much heat as a pound of carbon dioxi de over a 100

- year time frame. Commenters stated t hese 20

- year and 100

- year methane global warming potentials (GWPs) are significantly larger than previous IPCC estimates, with the 20

- year GWP reflecting about a 20 percent increase.

• Commenter s noted that, with the recent advances in natural gas extraction technologies, environmental concerns have been raised that could erode or negate the EPA objectives. Commenter s stated natural gas can leak from wellheads, valves, tanks, pipes, processing plants, and oth er parts of the energy supply chain. Commenter s stated that a recent study utilizing satellite measurements of methane found leakage rates in certain gas producing regions in the 2 to 17 percent range, much higher than the 1.2 percent leakage rate calculat ed by EPA. Commenter s stated that scientists have found that a methane leakage rate above 3.2 percent may negate the fuel's climate benefits in the power plant.

• Commenter s expressed concerned that, although natural gas power plants have lower carbon emiss ions than coal, they are not emissions

- free. Commenter s stated that methane leakages across the natural gas supply chain, potential health impacts from poorer air quality, and potential groundwater contamination in shale gas plays, are all of significant c oncern. Commenter s 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 overall system) is addressed. Commenter s expressed concerned that the proposal put s too much stock in natural gas as a compliance strategy and should instead shift more focus toward renewable generation and energy efficiency measures.

• Commenter s expressed concern about the climate and public health impacts of fugitive methane emissions from natural gas production and transport. Commenter s stated methane is a powerful climate warming pollutant, 87 times more powerful than carbon over a 20

- year tim e span. Commenter s stated the EPA88 estimates that gas leaks from the oil and gas sector are responsible for 29 percent of U.S. methane emissions. Commenter s stated the EPA's estimate may be too low and fugitive emissions from this sector will significantly increase because of the Clean Power Plan. Commenter s stated that, if methane leaks are not controlled, the climate gains of moving away from coal

- fired power may be completely cancelled out. Commenter s stated it is not enough to reduce carbon emissions; in stead greenhouse gas pollution (including methane) must be considered as a whole, and targeted accordingly. Commenter s 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 President's Climate Action Plan.

• Commenter s expressed concern that a significant body of evidence indicates that methane leaks associated with nonconventional production of natural gas (such as shale or tight gas extraction), as well as with the pr ocessing, transmission, and distribution phases of the industry, may cause climate change impacts on a par with those of coal combustion. Commenter s stated that Building Block 2 has the favorable attributes of being objectively determined using current dat a, being demonstrably feasible, and setting target emission rates that are likely to meet or exceed the reductions that would flow from "business as usual" retirements and curtailments. Commenter s stated that, while they support the use of a limitation

on coal

- fired EGU dispatch under Building Block 2 for target setting, they intend to work with our state partners to ensure that compliance under state plans does not lead to increased use of natural gas. Commenter s stated that displaced coal should be replac ed with renewable energy and energy efficiency (as opposed to natural gas) to the greatest extent possible. Commenter s stated the agency underestimated the impact of recent RE cost reductions and the growth in momentum in that sector and suggested that the EPA set a more aggressive set of EE/RE targets.

• Commenter s stated a growing body of published, peer

- reviewed research indicates that methane emissions from natural gas production are significantly higher than estimated by EPA's 2013 Greenhouse Gas Invent ory. Commenter s stated that certainty in source attribution has increased in recent years as scientists are better able to distinguish methane sources based on detected levels of co

occurring compounds such as ethane or isotopic composition of atmospheric methane. Commenter s referred to the following studies:

• An early top

- down study, Xiao et al. (2008), estimates that nationwide emissions of methane from fossil fuel sources in 2004 were 50 to 100 percent higher than bottom

- up inventories estimate. More rece ntly, Miller et al. (2013), uses atmospheric measurements of methane in 2007 and 2008 to estimate that methane emissions from all U.S. sources were 50 percent higher than estimated for that year by the 2012 U.S. GHG Inventory. The study shows that oil and gas emissions constitute a significant portion of the observed emissions not accounted for in EPA's Inventory. Atmospheric studies examining individual regions have found even higher methane emissions in the regions studied. Two studies of Colorado's Denve r

- Julesberg Basin have concluded that during gas production89 alone (not including emissions from downstream segments of the industry

- transmission and distribution), the gas leak rate was about 4 percent. The same team of researchers found even higher meth ane leak rates in Utah's Uinta Basin. Brandt et al. (2014) systematically reviews eleven top

- down and a number of bottom

- up studies, including the studies discussed above (with the exception of Petron et al (2014), which was not published at the time of Br andt et al's review). Brandt et al. demonstrates that for many years top

- down studies have very consistently shown higher emissions from oil and gas than do bottom

- up studies. The authors estimate that total U.S. methane emissions from all sources were 25 to 75 percent higher than the U.S. GHG Inventory estimated for 2011, and find that oil and gas are important contributors to these unreported emissions. These top down studies provide compelling evidence that the aggregate methane emission estimates based on "bottom up" studies, such as the estimates used by the RIA as a starting point here, underestimate oil and gas sector methane emissions by a significant margin.

• Commenter s stated the EPA has not shown that increased natural gas use by using NGCC genera tion to displace coal and oil and gas boilers can be part of a best system of emission reduction or even that an increase in natural gas use in the power sector can be used for compliance with the CPP. Commenter s stated that a more careful examination of l eakage data using both 20

- year and 100

- year warming potentials is needed to make such a conclusion 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 reduct ion. Commenter s stated that, in the worst case, it may not reduce CO2 equivalent emissions at all or could even exacerbate them somewhat. Commenter s suggested that a constraint on compliance plans should be that there should be no net increase in natural g as use in the power sector; changes in the use of natural gas can be allowed within that overall constraint.

• Commenter s stated the EPA's estimates of methane emissions from natural gas production, processing, transportation, storage and distribution are

un derestimated, which has resulted in a skewed representation of the climate benefits of switching from coal to natural gas. Commenter s stated there is compelling evidence that leakage rates from natural gas operations are far higher than EPA emission factor s suggest. Commenter s stated the EPA currently assumes that natural gas systems have a combined upstream and downstream leakage rate of 1.8 percent. Commenter s stated this was recently reduced from 2.5% for conventional gas and 3.9% for fracked natural gas (the revision occurred after the publication of an industry study that was not subject to peer review). Commenter s stated that, since that time, the Office of the Inspector General has issued a report indicating that EPA must improve its emission factors to better reflect direct measurements of methane leakage from natural gas production. Commenter s stated that, for instance, a recent study using atmospheric measurements estimated fossil fuel methane emissions at more than two times higher than EPA's emiss ions factors would indicate. Commenter s stated that observations from oil and gas operations in Colorado indicate that inventories90 underestimate methane emissions by at least a factor of two. Commenter s stated that leakage rates over a Utah gas field were recently estimated at 6.2 to 11.7%, well above the rates assumed by national inventories. Commenter s stated that a
recent meta

- analysis of studies conducted over the last 20 years suggests that EPA's estimate of 1.8% is far too low, with actual leakage rat es between 3.6 and 7.1%.

• Commenter s stated there are multiple aspects of natural gas production that may result in significant undercounted fugitive methane emissions. Commenter s stated that one study surveyed methane plumes over Marcellus shale operations in Pennsylvania. Commenter s stated that the authors found 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%. Commenter s stated that this is a production stage not typically considered to cause large methane leakage in national inventories, and thus is excluded from consideration by EPA. Commenter s stated that this study provides another indication that current leakage rates are significant ly underestimated. Commenter s stated that new work also suggests that both plugged and unplugged abandoned wells in Pennsylvania leaked at much higher rates than reflected by current emission factors. Commenter s stated that the EPA must revisit its assumpt ions regarding cradle to grave leakage to create a sound scientific basis for the Proposed Rule.

• Commenter s stated that another major source of methane emissions from the natural gas sector is leaks from pneumatic devices. Commenter s 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. Commenter s stated that recent reports have also substan tiated an alarming rate of leaks from decaying gas pipeline systems across the country, creating the need for systematic, on

- the

- ground data collection to obtain an accurate quantification of emissions from this source. Commenter s stated that, for example, according to a recent study, 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 distributors nationwide reported an average of 12 leaks per 100 miles of the 1.2 million miles of gas main pipes across the country. Commenter s stated that more than 5,800 leaks were detected from aging gas pipelines underneath the streets of Washington, D.C. Commenter s stated the Office of the Inspector General issued a report this y ear indicating that the EPA should work with other agencies to track emissions from distribution pipelines, consider future regulation, and update its emissions factors.

• Commenter s stated the EPA must use accurate estimates of methane leakage from natural gas systems. Commenter s stated that vented, fugitive and other methane emissions from natural gas undercut the climate benefits of using natural gas to produce electricity. Commenter s 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. Commenter s stated that employing an accurate leakage rate is another crucial component in the analysis of91 the climate impacts of switching from coa l to natural gas. Commenter s expressed concern that, while many of these studies are peer

- reviewed and directly on point, the EPA does not include them in its references. Commenter s stated that the EPA cannot cherry

- pick the data on which it relies but mus t take these scientific studies into account. At a minimum, EPA must explain why it dismisses this information. Commenter s stated that the observational data indicate that much more methane is reaching the atmosphere from natural gas production than EPA cu rrently estimates. Commenter s stated that whether from super

- emitters or indicative of higher average methane emissions per site, or both, there is a clear under

representation of methane from natural gas production in EPA's analysis of the climate impacts from natural gas.

Fugitive Methane Rules

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

• Commenter s stated that, for the clean power plan to achieve its full potential, rules must be adopted for capturing f ugitive methane and other volatile organic compounds from oil and gas operations.

• Commenter s 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 de aling with the extraordinary methane emissions from production, storage transmission and distribution. Commenter s stated that commitments have been made by the Administration and EPA to control methane and they are looking for that commitment to be realize d.

• Commenter s stated that, while greater reliance on gas

- fired power under the Proposed Rule will place a heightened responsibility on natural gas producers and pipeline operators to mitigate fugitive emissions of methane across the supply chain, there is significant evidence that American industry can meet the challenge

• Commenter s urged the EPA to use the Clean Air Act to address fugitive emissions of methane resulting from natural gas development. Commenter s stated that a clean energy plan under which s tates meet their carbon reduction requirements simply, or even mostly, by switching wholesale to natural gas will not represent true progress in the fight against global warming; rather, states must make substantial investments in energy efficiency measure s and renewable energy sources, and reduce America's use of all fossil fuels.

• Commenter s stated that, even if the EPA eventually considers separate efforts to limit methane loss, the rule is deficient because it would lead states to make decisions about el ectricity generation based on combustion emissions only. Commenter s stated this will lead to poor choices regarding energy production, as seen in the rule's own Regulatory Impact Analysis (RIA). Commenter s stated that, compared to baseline forecasts, the r ule would boost the amount of additional92 electricity generation from natural gas by nearly ten times the meager gain projected for renewables before 2020. Commenter s stated that, by accelerating gas investments in the near

- term, the plan could tip the scales toward fossil fuels for decades to come; once gas

- fired plants are in operation, there will be less incentive for utilities to reinvest in renewables because the massive capital outlay for gas infrastructure will have already occurred.

• Commenter s stated the EPA's projections include extremely optimistic forecasted results of voluntary emission reduction programs. Commenter s stated that, while the EPA assumes that voluntary reduction efforts will continue at a constant historic percentage level over the entire rulemaking period, the explosion in natural gas production over the last several years renders this assessment dubious at best, and EPA itself admits its unce rtainty. Commenter s stated that nothing indicates voluntary reduction efforts have kept pace with the recent tempo of extraction; instead, the recent observational studies indicate the opposite.

Lifecycle Analysis

Several commenters suggested the EPA shoul d use a lifecycle analysis to determine the net emissions of methane associated with the CPP.

• Commenter s stated that CO2 and methane are lost during the production, processing, and transmission of natural gas. Commenter s stated that this coupled with a con sideration of natural gas's lifecycle emissions shows that natural gas is not any better than coal from a climate change standpoint. Commenter s stated that the effect and intent of the proposed rule was to accelerate the use of fracked gas and to facilitat e the development of gas

- fired power plants, which is a problem. Commenter s stated that the proposed rule is defective since states and utilities would make decisions about electricity based on carbon dioxide emissions from combustion only, and that will l ead to bad decisions.

• Commenter s stated that, if one considers the fugitive gas from mining to transport to storage, natural gas is not any better than coal. Commenter s asserted that the proposed rule would be improved by less emphasis on natural gas, whi ch is a fossil fuel that "emits 50 percent carbon dioxide into the atmosphere" when it is burned. Commenter s recommended putting more emphasis on energy efficiency and green renewable energies to make the rule stronger and provide us with less health threa ts in the future.

• Commenters stated that natural gas from shale has an 8 to 11 percent larger greenhouse gas footprint than conventional gas over its lifecycle which could be changed with improved practices. Commenter s emphasized that the rule not incentiv ize shifting from natural gas to coal and calling it an emission reduction. Commenter s said that the rule must not allow states to let polluters buy pollution offsets to meet emissions requirements. Commenter s cited current cap

- and

- trade programs that allo w polluters to pay farmers, foresters, et cetera to reduce their emissions and then claim those cuts for themselves.93 • Commenter s stated that the proposed rule would accelerate the conversion from coal to natural gas by only quantifying the smoke stack emiss ions at generating plants and by disregarding the release of methane in the natural gas lifecycle. Commenter s said the president's address to natural gas is wrong in many ways, and that the president's approach is poisoning us. Commenter s stated that there is scientific evidence that shows that carbon

- based fuel is no better than and sometimes worse than the coal industry. Commenter s stated that France has banned fracking, Germany reinstituted their moratorium on the practice, and mentioned that communities across the nation continue to fight or ban fracking. Commenter s stated that EPA studies have underestimated the impacts of methane and natural gas drilling on the climate; drilling and fracking expanded the use of natural gas, which threatens to exacerbat ed climate change and to stifle investments and the expansion of renewable and sustainable energy.

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

• Commenter s stated that enhancing the amount of natural gas that is produced, transported, and burned for baseload power generation will inevitably lead to greater emissions of this dangerous methane. Commenter s noted four independent studies which show that lifecycle methane emissions have a global warming potential as bad, or worse, than coal. Commenter s asserted the United States must: 1) craft mandatory methane capture and mitigation 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 polluting coal plants without transitioning to other, potentially worse, greenhouse gas producing fossil fuels.

• Commenters stated that increasing bodies of research show that the complete life cycle of natural gas produces more carbon emissions than coal

- fired generation.

• Commenter s objected to the proposed regulations because recent scientific studies suggest that current estimates of methane emissions from natural gas extraction are too low, Commenter s stated the Office of the Inspector General reported that "[t]he EPA's existing m ethane emissions data for distribution pipelines may not be valid." Commenter s stated the EPA estimates emissions using a bottom

- up approach, beginning with an inventory of all of the different industry activities94 undertaken in a given year and then uses l argely dated estimates of average emissions of each activity to arrive at an estimate of total emissions from the oil and natural gas systems. Commenter s stated this approach relies heavily on voluntary self

- reporting from the industry. Commenter s stated t hat data on the actual levels of various hydrocarbons in the atmosphere, taken from aircraft flights and/or from surface monitoring locations, make possible an alternative, top

- down approach to estimating industry emissions. Commenter s stated that scientis ts using this aircraft measurement approach in Utah, Colorado and Pennsylvania suggest that much more methane and other air pollutants are flowing from oil and gas sites than bottom

- up estimates based on dated emission factors and industry self

- reporting. Commenter s stated Karion et al. measured very large levels of methane, the equivalent of between 6.2 percent and 11.7 percent of natural gas production. Commenter s stated Caulton et al. published a study of methane emissions during the drilling stage at we ll sites in Pennsylvania and found several super

- emitters, each releasing 100 to 1,000 times the EPA's estimate of emissions during the drilling phase, as utilized in its bottom

- up, inventory estimates. Commenter s stated P'tron et al. published a study lo oking at methane emissions in the Denver

- Julesberg basin in Colorado over a two

- day stretch in 2012 using monitoring equipment on towers 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 estimate based on EPA's Greenhouse Gas Reporting Program data for 2012."

Commenter s stated the EPA needs to conduct a more comprehensive assessment of upstream GHG emissions and an examination of emissions from potential ch anges in upstream emissions generated by changes in natural gas and coal production, processing, and transportation activities outside of the US. Commenter s stated these exclusions 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 exports of coal and gas outside of the US. Commenter s stated that the EPA's analysis of the upstream methane emissions changes (reductions in total net upstream methane reductions of between 7.4 and 10.6%) due to increased use of natural gas is incorrect for at least three reasons. Commenter s stated (1) the E PA uses an outdated 100

- year global warming potential measurement for methane of 25 and does not consider the 20

- year methane GWP at all, which is crucially relevant to evaluating compliance between now and 2030; (2) the EPA assumes methane leakage rates f rom 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 associated with natural gas extraction through fracking and similar unconventio nal methods. Commenter s stated that, using corrected values will show that the Proposed Plan as currently structured will not achieve the emission reductions EPA projects; indeed, studies have concluded that natural gas

- fired power generation may approach, equal or even exceed the lifecycle greenhouse gas footprint of coal

- powered plants. 62 Commenter s stated the EPA must revise its lifecycle greenhouse gas analysis of coal

- and natural
gas

- based power generation to arrive at accurate projections of the rule making's effect, and adjust the building block targets and their interrelationship according.95 Commenters stated they identified six significant technical deficiencies in EPA's analysis of methane emissions. Commenter s agreed with the IEER comments that EPA has not properly reviewed the impacts of methane releases in the fuel cycle and stated six points from IEER are of particular concern:

• The EPA relies mainly on industry

- supplied data for estimating natural

- gas

related methane emissions, especially for em issions 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 emiss ions 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 document failed even to refer to, much less to evaluate or use, recent independent measurements, including measurements made from aircraft that indicate that leaks from production may be far higher than the values used by the EPA. For example the EPA document did

n ot refer to or use Howarth et al. 2011, which estimated venting rates from conventional and hydro

- fractured natural gas production 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 E PA used leak rates averaged over all natural gas production. However, the increase in production that will be required to supply the fuel for the increase in Natural Gas Combined Cycle (NGCC) generation envisaged by the CPP is projected to come from tight gas and shale gas formations. There is a significant difference between the two.

• The EPA entirely ignored the 20

- year value of the global warming potential of methane, which is critical to examine whether serious excursions in CO2eq concentrations might o ccur 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 course of greatly expanded natural gas use in electricity generation up to the year 2030 beyond that year. Specifically, the EPA did not examine whether its trajectory of increasing natural gas use is compatible with longer

- term goals for much greater reduction in g reenhouse gas emissions.

Clarification

Commenter s requested clarification of an issue related 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 gas production. Commenter s stated that, under Option 1 of the Proposed Rulemaking, coal production is predicted to decrease by between 2296 and 24% in 2020, while natural gas production for the same time frame and option is predicted to incr ease by only 3 or 4%. Commenter s stated the preamble to the Proposed Rule, however, states that coal production is predicted to decrease by roughly 25% (an amount at least within the range of the RIA prediction), while natural gas production will increase much more dramatically than stated in the RIA, by between 12

- 14% (four building block approach) or between 19 and 22% (the two building block approach). Commenter s stated that, as to the key question of how much additional gas will be produced, the preambl e and the 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. Commenter s stated this point is critical because the RIA's comparison of methane emissions from coal versus natural gas ass umes a relatively small (3

- 4%) increase in natural gas production, which in turn crucially informs the Proposed Rule's assumptions about the amount of methane leakage and the basic rationale that replacing coal

- fired power plants with natural gas

- fired uni ts significantly decrease greenhouse gas emission reductions. Commenter s asked that the EPA clarify which values are actually correct.

Oil and Gas NSPS

Commenter s stated that, in its analysis, the EPA relied on the newly promulgated oil and gas NSPS which set standards for non

- greenhouse pollutant emissions from the production stage of natural gas extraction through green completions and other methods and its impact on methane emissions in 2015 and beyond. Commenter s stated the EPA's assumption that compli ance with that rulemaking will result in methane emission reductions between 60 to 96% from the targeted leakage areas is overly optimistic. Commenter s stated that these values are much below those established by the direct

- observation studies cited by c om menter s . Commenter s stated that the EPA assumes no leakage during drilling operations, which is clearly incorrect. Commenter s stated that, although it is not clear from the RIA, fugitive methane emissions from coproducing wells presumably are not included even though a number of studies have found significant methane leakage from hydraulically fractured, co

- producing wells

. Commenter s stated the current NSPS for the oil and gas sector does not require these wells to perform green completions. Commenter s stated the NSPS also does not address methane escaping during periods of flowback, which, for extraction of gas from shale, can involve millions of gallons of fluid and last for weeks. Commenter s stated the EPA also does not account for leakage from newly drilled or reworked wells that will be abandoned during the rulemaking period, for fugitive emissions from the de

- pressurization of various well components, and for the acute shortages in the new equipment the NSPS assumes will be installed. Commenter s co ncluded 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 increase in emissions caused by the increased use of natural gas under the Proposed Rule, incl uding impacts on ozone. Commenter s stated that an increase in natural gas usage from re

- dispatch may increase NOx, VOC and methane emissions from upstream oil and gas operations in areas that are at risk for ozone nonattainment, and that should these areas become designated as nonattainment, new constraints would be necessary regarding production. Commenter s added that all of New Mexico's NGCC facilities are located in areas at risk for ozone nonattainment, and increased usage of both oil and gas facilities and NGCC facilities will increase emissions, leading to additional permitting97 requirements. According to the commenter s , this could lead to additional economic burdens and additional costs for controls. Commenter s stated that the timing for this rulemakin g will be inappropriate for integrated planning regarding ozone, as discussed further elsewhere in this document.

Commenter s urged the EPA to address emissions of methane, a potent climate pollutant, Commenter s stated that President Obama committed to tak ing 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 emissions of dangerous climate and public health harming pollutants from new and e xisting sources in this sector.

Commenter s stated an increase in natural gas usage from re

- dispatch may increase NOx, VOC and methane emissions from upstream oil and gas operations in areas that are at risk for ozone nonattainment. Commenter s stated that, if these areas become designated as nonattainment, new constraints would be necessary regarding production. Commenter s stated that all of New Mexico's NGCC facilities are located in areas at risk for ozone nonattainment. Commenter s stated that increased us age of both oil and gas facilities and NGCC facilities will increase emissions, leading to additional permitting requirements, which could lead to additional economic burdens and additional costs for controls. Commenter s stated the timing for this rulemaki ng will be inappropriate for integrated planning regarding ozone.

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

Response 23: The EPA has analyzed the contribution of methane and determined that no adjustments need to be made for it. See Chapter 3 of the R egulatory 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:

Commenter s stated the EPA must fully account for emissions from unconventional gas extraction methods such as hydraulic fracturing, or fracking, which cause much higher methane emissions than conventional method s. Commenter s stated that unconventional gas currently accounts for about 60% of gas production, and is predicted to increase to 75% by 2035. Commenter s stated that, although large methane emissions are associated with flowback and drill

- out of hydraulica lly fractured wells, particularly for gas extraction from shale, the EPA does not currently distinguish between conventional and unconventional sources of fugitive and vented methane. Commenter s stated that, in 2011, when EPA updated its emission factors f or natural gas production, it did differentiate between conventional and unconventional (shale) gas, with values of 1.6% and 3.0%, respectively. Commenter s stated that the EPA action in 2013, to reduce these emission factors and remove the distinction betw een wells drilled with conventional and unconventional sources, was directly contrary to scientific evidence demonstrating higher methane emissions than believed, especially for unconventional compared with conventional natural gas extraction. Commenter s s tated that, as detailed in 2011, during the development98 phase, fracked natural gas likely results in 1.9% higher methane emissions as compared to conventional natural gas, resulting in average methane emissions from fracked wells of 3.3% as opposed to 1.4% for conventional gas. Commenter s stated these estimates have since been corroborated by other studies. Commenter s stated, for example, a new study has provided evidence that another potential difference between conventional and unconventional gas is the i ncidence of impairment and consequent leakage from cement and/or casings of fracked wells; the study, which examined public records to construct a database and model of impaired structural integrity of wells in Pennsylvania, showed that unconventional well s were two times more likely to experience a loss of integrity and increased methane leakage than conventional wells. Commenter s stated that another study that found methane emissions during the drilling phase to be two to three times higher than EPA's emi ssions factor was conducted at wells subject to hydraulic fracturing. Commenter s stated the EPA must determine whether a difference in methane emissions between conventional and unconventional gas wells exists and, if so, account for it.

Comment 24: Commenters urged the EPA to propose fugitive methane 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:

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

Commenter s expressed concern that natural gas extraction is subject to leakage and loss of methane during transportation. Commenter s stated that 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. Commenter s stated that studies indicate that methane leakag e at levels above 3 percent is enough to negate the climate benefits of natural gas over coal. Commenter s stated the TEPC understands that EPA may be proposing in the near future a rule that addresses methane emissions from EGUs and other sources. Commente r s stated welcomed such a rule and recommended 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 cleaning up methane pollution from its natu ral gas sector, and Ohio, which requires natural gas drillers to conduct quarterly inspections to detect and fix leaks in their systems.

Commenter s urged the EPA to take action to reduce fugitive methane emissions released during the natural gas extractio n, transportation and delivery process. Commenter s 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. Commenter s stated the EPA should assign99 responsibility for reducing fugitive discharges to firms across the supply chain. Commenter s stated that failure to control these emissions may seriously undermine the EPA's national climate pollution reduction efforts.

Commenter s noted that the EPA is co nsidering fugitive methane regulations for the oil and gas sector, and that draft rules may be published soon. Commenter s encouraged the EPA to pursue strong standards with this rule, and to treat the upcoming proposal as a critical component of the Clean Power Plan strategy. Commenter s stated the knowledge and technology needed to reduce methane leakages is well known and available, and in many cases preventing leaks has financial benefits. Commenter s stated the Natural Resources Defense Council estimates that enhanced standards to cost

- effectively address the issue could cut methane leakage in half, the rough equivalent of removing 150 million metric tons of carbon over five years. Commenter s stated that some industry leaders are beginning to take action t o 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. Commenter s stated that, if the EPA fails to take stro ng 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.

Commenter s suggested that the EPA undergo rulemaking in a timely manner in order to address th e potential dangers from fracking, such as contamination of ground water supplies, stress on the availability of water supplies, and management of wastewater. Commenter s also expressed concerned with air emissions from flares operated at some fracking inst allations. Commenter s stated that, according to a Natural Geographic article published on May 22, 2014, an estimated 5 million cubic feet of natural gas was flared without permits on public land in 2013, which is enough to meet the annual needs of about 50 ,000 American homes. Commenter s urged the EPA to pursue rule

- making to address this waste and unnecessary pollution in a timely manner. Commenter s expressed concern with any potential addition/expansion of pipelines due to the increased use and production of natural gas. Commenter s 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 swiftly and adequately addressed when they

occur

.

Commenter s recommended the EPA set standards to directly curb methane emissions from the oil and gas sector, the second largest industrial contributor to greenhouse gas emissions.

Comment 25: Commenter s 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 CP P and Chapter 3 of the GHG Mitigation Measures TSD for the 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:100 Commenter s noted that, as part of the Regulatory Impact Analysis ("RIA") for the proposed rule, EPA analyzed potential upstream net methane emissions impacts associated with increased use of natural gas in the power sector. Commenter s stated that the EPA's considera tion of these impacts was appropriately limited to an appendix to the chapter of the RIA considering economic and energy impacts. Commenter s stated that CAA section 111(d) provides for state plans to regulate "any existing source", thus, the EPA cannot inc lude "upstream" emissions in its determination of guidelines for state determination of BSER. Commenter s stated the affected sources in this proposed rule are fossil fuel

- fired boilers, IGCC units, and stationary gas

- fired combustion turbines. Commenter s a dded 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 opposed to the more recent 2014 GHG Emissions Inventory. Comment er s encouraged the EPA to rely on the most recent inventory, given the significant changes to the inventory over the past five years. Commenter s added that they do not support the use of the inventory for regulatory purposes and we look forward to continui ng to work with EPA to update the inventory to more accurately reflect emissions.

3.2.2 Magnitude of generation shift s among existing EGUs

This section discusses specific issues related to the EPA’s b uilding b lock 2

— Generation Shifts Among Affected EGUs. Issues are largely related to NGCC units and include historical capacity, nameplate capacity, baseline capacity, permit constraints, individual unit limitations and abilities, annual average availability, and p eak demand.

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

Comment 1 : The EPA should adjust the 2012 baseline NGCC capacity factors using a 50% displacement factor in states with high wind penetration

. Response 1 : The EPA disagrees. The EPA believes that the annual capacity factor in the final rule is sound and can be me t in states with high wind 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 and RIA

– the establishment of CO2 emission re duction 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 11 1(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 reliability, fuel diversity, other regulatory requirements and infrastructure. See sections V.D, VIII.A, VIII.C and VIII.G of the final rule preamble of the CPP101 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 argued that EPA needs to consider the impact 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 NGCCs means th at wind power sources tend to displace NGCC generation; from 32.6% in the MISO region up to 83% in the West and 87% in ERCOT. The commenters stated t hese wind/NGCC "displacement factors" demonstrate that NGCCs in states with high wind penetration have a lower capacity factor due to the operation of wind generation in those states and their utility systems. Therefore, the commenters added, the 2012 base line NGCC capacity factors used in EPA's Block 2 methodology are lower in states with significant renewable energy than they would have been absent these pre

- 2012 RE investments and resulted in more stringent Block 2 calculations and emission targets in st ates with higher renewables. The commenters suggested that 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 factor (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 recalculate the emission rate goals by applying a 50 % displacement factor to existing combined cycle capacity for states with high integration of renewable resources.

Comment 2 Commenters suggested the EPA’s analysis did not account for p ermit restriction s on NGCC units that limit ramping up operatio ns

. Response 2 For the EPA’s response to this comment, s ee 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 permit limits on NGCC units that limit ramping up operations. If the EPA corrects this error, the c ommenters 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 support ed the EPA's proposal for Building Block 2 with respect to a 70 percent capacity factor

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

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 Propos ed Rule has appropriately determined that it is feasible and cost

- effective for states to take advantage of existing NGCC fleets and low natural gas prices. Commenters noted that the CPP supports, through IPM modeling, that 70 percent utilization of existi ng and under construction NGCC is technically feasible. Commenters added that IPM also was able to successfully simulate 75 percent NGCC utilization nationally.

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

Commenters expressed the belief that most NGCC facilities 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 base load needs while the NGCC units operate primarily in a load

- follo wing mode with capacity factors ranging from 50 percent to 70 percent. However, according to the commenters, the NGCC units are designed for and capable of operating in base load, which would include a 70 percent capacity factor.

Commenters said that the c apacity to operate NGCC plants at a 70 percent capacity factor is well established, as more than ten percent of existing NGCC plants have operated at a 70 percent capacity factors in recent years. (Greenhouse Gas Abatement TSD) Commenters added that IPM

mo deling demonstrates that operating each state's NGCC 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 whether a regional or state

- specific approach was taken. Commenters agreed with the EPA's conclusion that these costs are reasonable even without considering the additional public health and c limate benefits that such a shift in dispatch would create.

Commenters stated that the proposal rightly recognized that due to the interconnected nature of the power grid and interoperability of different generation resources, reduced use of high carbon

i ntensity EGUs would result in increased utilization of other generation resources, such as efficient NGCC plants.

Comment 4 : Some commenters supported the position that a 70 percent utilization rate is technically and economically feasible.103 Response 4 : The EPA disagrees with the establishment of a CO2 emission reduction standard calculation using less than a 75 percent capacity factor for NGCC units. . For the EPA’s response to this comment, see section V.D of the final rule preamble of the CPP and chapte r 3 of the GHG Mitigation Measures TSD for the CPP Final Rule.

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

Operating e xperienc e supports the Proposal.

Commenters stated that the proposed 70% NGCC utilization 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 facilities. Commenters supported several statements in the Proposed Rule (79 FR 34830, 34864):

The primary re

- dispatch opportunities among existing units available to EGU owners and grid operators generally consist of opportunities to shift generation among various fossil fuel

- fired units, in particular between coal

- fired EGUs and NGCC 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 significan t number of NGCC units have achieved utilization rates between 50 and 80 percent. In modeling the impact of a 70% NGCC utilization rate, EPA found that projected wholesale electricity price increases over the period were less than seven percent in both ca ses, which is well within the range of historical electric price variability.

Commenters supported the EPA's goal of significantly 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 experience, 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 reliance on these units represents some of the lowest hanging fruit available to bring about GHG reductions (NODA at p. 19). Commenters reported that they are confident that well

- mainta ined units can reliably achieve the 70 percent utilization rates described by EPA in its proposal.

Commenters stated the EPA's proposed rule underestimates expanding unit

- level utilization capabilities throughout the NGCC fleet since high utilization (gr eater than 70 percent) of NGCC power plants is technically feasible and has been demonstrated in operation. Commenters stated gas turbine manufacturers can supply gas turbines with a mechanical availability of greater than 90 percent. The commenters furthe r stated the gas turbine'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 gas turbine, and planned maintenance is simultaneous for the GTG: the HRSG is a piece of fixed 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 NGCC units physically operating a t a 70% capacity factor, commenters noted that there is little long

- term operating experience with widespread and sustained operation of a majority of NGCC units at 70% capacity factor.104 NGCC units are more efficient running at a higher capacity.

Commen ters 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 units are quite capable of oper ating at or near a 90 percent capacity factor and increased utilization 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 capac ity factors 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 utilization rate target is achievable with a sufficient phase

- in, and based on GE's experience it 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 issu es listed below will need to be addressed with careful modeling and planning. The commenters asserted that, assuming states follow EPA's suggestion of tilting the market to an environmental dispatch, it would seem likely this will cause some increase in th e 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 markets based on bidding into competitive markets. EPA proposes that states will fix this situati on by forcibly adjusting dispatch order.

2. Over

- capacity in certain regions of the Federal Energy Regulatory Commission, particularly regulated states: In many regions, there still exists excess capacity, largely owing to the fact that electricity demand has not fully recovered to pre

- recession levels. With much of the NGCC capacity comprised of independent power producers or merchant plants, we see preferential dispatch for the regulated resources, thus leaving merchant plants as peak suppliers.

3. Available fu el resources: Distribution infrastructure 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 down, reducing capacity factors.

4. Consideration of p lant locations and grid requirements for geographical area power demand: A few units may be located in areas where the demand is insufficient to reach these proposed capacity factors.

Average annual approach is appropriate.

Commenters recommended that, i n evaluating feasibility on a unit by unit capacity utilization, the EPA should continue to use an average annual approach, consistent with the rule's compliance requirements. Commenters stated that some public commentary misconstrues EPA's 70 percent targ et utilization as an assumption that every plant is capable of running at 70 percent105 every day of the year, concluding that limits on natural gas supply for power generation during peak demand makes it impossible to meet the standard. Commenters stated thi s conclusion is inappropriate and inconsistent with EPA's analysis. The commenters recommended that, in evaluating feasibility on a unit by unit capacity utilization, the EPA should continue to use an average annual approach, consistent with the rule's com pliance requirements. The commenters stated that such an approach allows for varying levels of capacity utilization as market conditions dictate, the utilization of all types of power plants is an economic decision based on market demand, fuel cost, power price and available generation 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.

Da ta support the 70% capacity factor.

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

Commenters stated that historical data ana lyses suggest the 64 percent average NGCC utilization factor and 70 percent maximum NGCC utilization factor 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 historically has achieved utilization factors equal or close to the 64 percent average utilization factor and 70 percent maximum utilization factor assumed in EPA's Building Block 2. Commenters stated that the U.S. NGCC fleet has oper ated at a 60 percent utilization factor on a week

- long basis, just four percentage points shy of the average utilization factor in EPA's methodology; similarly, it has operated at 58 percent utilization on a month

- long basis, just six percentage points low er than the 64 percent utilization factor EPA assumes. Commenters presented a figure illustrating 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. Commenters included another figure showing that the NGCC fleets in 25 of 41 states with NGCC capacity have operated at a weekly utilization factor o f 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 the 64 percent average NGCC utilization factor and 70 percent maximum NGCC utilization factor relied 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 and energy system infrastructure. According to the commenters, the MIT Futur e of Gas study reported 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 approximately 420 million metric tons of CO2 coul d be reduced, by displacing 700 TWh of coal generation 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 results show that EPA's propos ed 70 percent utilization factor for natural gas fired units is reasonable. Commenters compared the Power Switch results to the EPA CPP modeling, and found that the amount of coal generation (and, therefore CO2 emissions) displaced by higher utilization of natural gas in the policy modeled in106 Power Switch is close to the re

- dispatch effect modeled 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 an d Emission Standards for Modified and Reconstructed Power Plants" Table ES

- 2 (371 MMT CO2 reduction from base case in 2020) with Power Switch at 6 (308 MMT CO2 reduction from base case in 2020).)

Commenters indicated that because the Power Switch approach and EPA's building block 2 include comparable assumptions, the NorthBridge economic 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")) for coal units would fall from 67 percent to 58 percent, while t he utilization factor for natural gas combined cycle units would increase from 48 percent to 65 percent. Commenters noted that this increase in gas unit utilization factor is almost identical to the 64 percent national average natural gas utilization facto r 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 would exceed the 70 percent utilization factor level, some by a substantial amount (up to 85 percent) and that, thus, the NorthBridge analysis provides evidence that EPA's proposed 70 percent utilization ceiling is reasonable, if not conservative, and provides support for EPA raising the natural gas unit utilization ceiling to at least 75 pe rcent.

Commenters confirmed that a 70% average NGCC utilization rate is technically and economically feasible. The commenters stated that Calpine recently analyzed the Generating Availability Data System ("GADS") data from Calpine's NGCC facilities and th e GADS data indicate that Calpine's NGCC facilities have operated at a 70% or greater capacity factor dozens of times in many different states and climatic conditions. Commenters stated that, between 2001 and 2013, 25 different Calpine plants (including b oth cogeneration facilities and standalone (i.e., "merchant") power generation facilities) have operated at greater than 70% annual capacity factor 97 times. Commenters stated this has occurred in eight different states (Arkansas, California, Louisiana, Ma ine, New York, Oregon, Pennsylvania and Texas), in all climatic conditions from the desert southwest to the northeast. The commenters stated that the GADS data demonstrate that even higher annual capacity factors are achievable: individual power blocks hav e operated at greater than 75% capacity factor 57 times and greater than 80% capacity factor 27 times.

Commenters stated that running NGCCs at high utilization rates (>70 percent) is technically feasible and will be done in practice when power generation e conomics support it. Commenters stated that it is clear that a target utilization rate at or above 70 percent is adequately supported by gas turbine manufacturers and available data. The commenters reported that, based on their review of EPA's CEMS hourly operating data, 40 percent of currently operating NGCCs in the U.S. (211 units) have achieved at least one year since 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 achieved at least one month since 2000 where their monthly capacity factor was greater than 70 percent. The commenters concluded this data supports EPA's conclusion that NGCC units are able to achieve or exceed a 70 percent capacity factor.107 Commenters suggested that, because cogeneration units 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 a t high utilizations. Commenters stated that, because cogeneration units are similar to NGCC units and likewise include a GTG and HRSG, EPA should review the experience of cogeneration units. The commenters stated that, because of the steam linkage between the power generation and the steam generation for the industrial process, cogeneration units typically run as base

- load generators to support the steam needs of the facility, often at a utilization rate of above 85 percent, as demonstrated by EPA CEMS hour ly operating data.

Historically low dispatch not due to technical ability.

Commenters asserted that currently, many combined cycle units may not run at a high capacity factor because of factors related to economic dispatch, not technical ability. The comm enters stated the demand profile throughout the day, as well 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. coal fleet has had an average capacity factor less than 70 percent). Comment ers concluded that, given their technical reliability, with the right economic conditions, NGCC plants can compete for base load operations with coal plants, as already demonstrated in 2012.

Commenters stated that NGCC plants are technically able to operat e at much higher capacity factors than they have historically operated. The commenters stated that historical operation is more dictated by generation demand and economical dispatch, not technical availability. The commenters further stated that turbines i n GE's installed fleet have demonstrated availabilities (the hours the turbine is available to operate while considering necessary downtime for maintenance or repairs) in excess of 90 percent. The commenters reported that GE's 7F is the most common gas tur bine within the 60 Hz fleet, there 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 percent. The commenters further repo rted that a 7F NGCC plant

- level availability

-- which includes any necessary downtime for steam turbines, generators, or other balance of plant components

-- consistently exceeds 85 percent. The commenters concluded that, based on this fleet, the EPA's estimat e 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% utilization rate.

Commenters stated that a 70% utilization rate is consistent 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 renewable generation sources. Commenters stated that Building Block 2's assumed 70% utilization rate is f ully consonant with the role NGCC facilities are increasingly being called upon to play in assuring reliability of the electric grid and providing both power and the other ancillary services needed to support the rapid integration of intermittent RE source s. Commenters stated the existing fleet of highly efficient, flexible and fast

- ramping NGCC facilities can deliver electricity at the assumed 70% utilization rate, while108 operating as load following units, which are often controlled directly by the relevant independent system operator ("ISO") and have their output ramped 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 fast

- r amping capabilities of the existing NGCC fleet, commenters stated there is no inconsistency between the assumed 70% utilization rate and the role NGCC facilities will increasingly play in enabling the integration of intermittent renewable generating source s and ensuring the reliability of a more dynamic electric grid.

Commenters stated that, with careful modeling and planning, even at a 70 percent capacity factor, there can be adequate head room for NGCCs to still provide significant backup to renewables, d epending on demand. The commenters stated 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 ex empt from regulation. Commenters stated this may put further strain on the natural gas delivery system. Commenters added that it will be logical that backup power will come from a portion of the existing coal fleet that has been reduced in capacity 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 specific states to meet a 70% capacity.

Response 5 : The EPA agrees to the extent that data support an capacity factor for NGCC units of 75 percent . 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 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 setting gas re

- dispatch targets (see below) would help alleviate concerns that some stakeholders have raised about the infrastructure needed to provide higher volumes of natural gas to these plants.

Commenters state d Alabama has sufficient natural gas capacity and sufficient natural gas supplies for re

- dispatch to a 70 percent capacity factor. Commenters stated that, although in 2012 Alabama's primary energy source was natural gas, only six years prior, Alabama's ene rgy picture was much different: coal generation was dominant, exceeding 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 s ignificant shift over just the last several years, almost tripling its gas generation 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 company to Alabama's largest utility, Alabama Power Company. Commenters stated that Alabama has significant amounts of natural gas combined cycle (NGCC) capacity

- more than 10,000 MW and the EPA's analysis shows this capacity was utili zed 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.109 Commenters stated that a key related consideration is whether Alabama has sufficien t natural gas supply. Commenters stated the EPA's analysis assumes that Alabama's NGCC units are fully unconstrained in terms of pipeline capacity. Commenters stated it is important to test this assumption because states requiring pipeline expansion to all ow their NGCC units to achieve 70 percent capacity factors will have higher costs of compliance associated with Building Block 2, and may therefore elect to pursue other more cost

- effective compliance strategies. Commenters stated that Synapse Energy Econo mics, Inc. (Synapse) analyzed the amount of increased gas consumption that would occur as a result of increasing 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 increase by approximately 140 MMcf per day. Commenters stated this estimated increase in peak month gas use represents a 7

- percent increase in consumption, but is less than 1 percent of the available supply. Commenters st ated that Synapse determined that additional gas infrastructure would not be needed as a result of re

dispatching existing combined cycle generating plants in Alabama. Commenters stated Synapse also performed an analysis to determine whether there would be sufficient natural gas capacity to meet demand during peak hours and determined that in both of Alabama's two eGrid subregions there is sufficient natural gas capacity to meet peak loads.

Commenters stated that, because Alabama has both sufficient existi ng 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

- dispatc h 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 measures at even just 80 percent of the levels assumed by EPA, and those measures are allowed to displace fossil generation, Alabama can achieve its target with re

- dispatch to a capacity factor of just 64 percent

- and thereby avoid undue risk of fuel price volatility.

Commenters reported that the best system for emission redu ction 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.

Com menters stated that Georgia has both sufficient existing NGCC capacity and sufficient natural gas supplies for re

- dispatch to a 70 percent capacity factor. Commenters stated that, under Building Block 2, EPA assumes that Georgia can reasonably and cost eff ectively 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 Southern Company, the parent company to Georgia's largest utility, Georgia Power Company. Commenters 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

- dispatch 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 g as consumption that would occur as a result of increasing Georgia's NGCC utilization to 70 percent. Commenters stated that Synapse determined that with gas re

- dispatch, the total gas110 delivered to consumers during the peak winter month would increase by app roximately 350 MMcf per day. Commenters stated this estimated increase in peak month gas use represents an 18

- percent increase in consumption, but is less than 5 percent of the total pipeline capacity into the state. Commenters stated that Synapse determin ed that, while some amount of additional pipeline capacity may be required to facilitate this 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 perfo rmed an analysis to determine whether there would be sufficient natural gas capacity to meet demand during peak hours. Commenters stated Synapse examined hourly markets data for Georgia's two eGrid subregions

- SERC South and SERC Tennessee Valley

- and de termined that in both there is sufficient natural gas capacity to meet peak loads. Commenters stated that the Synapse analysis indicated 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 under

construction NGCC units in NC (if EPA assumes that these under construction NGCCs could increase to a 70% capacity factor), an additional 15% of their ultimate output is assumed to be available for re

- dispatch. The commenters reported that, in 2012, there were 2,249 MW of under

construction NGCC capacity in North Carolina and that the three million MWh of re

- dispatch to under

- c onstruction NGCCs would lower North Carolina's target emission rate by an increment of 126 lbs/MWh. The commenters further asserted that North Carolina could achieve even greater generation from NGCC plants. According to the commenters, a study by Synapse that analyzed the potential for NGCC plants to displace coal

- fired power plants, NGCC plants in North Carolina can achieve capacity factors of 80%.

Commenters stated that 70 percent utilization for natural gas generation is achievable for Ohio, although th is will depend on a number of policy and technical prerequisites. Commenters stated the national average natural gas power plant utilization increased 10% between 2005 and 2010 and there is a surplus of underutilized baseload natural gas generators in the United States, including in Ohio, so there is opportunity to use these ratepayer

- funded plants to the fullest capacity possible. Commenters stated the availability of adequate natural gas supply, storage and pipeline capacity will be a factor in achieving greater natural gas generation. Commenters noted that natural gas pipelines prefer to operate as close to capacity as possible to maximize revenue, which means adequate supply could easily be achieved to support the increased firing of these plants.

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

• First, EPA as sumed that a state's generation can only 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 all ow for re

- dispatch of the state's NGCCs up to the 70 percent maximum.111 • Second, the 70 percent natural gas capacity assumption is reasonable in light of existing pipeline capacity. According to the U.S. Energy Information Administration ("EIA"), the total c apacity of the gas pipelines delivering into Tennessee is 14,685 MMcf per day. The 70 percent capacity assumption would increase the level of total gas delivered to customers during the peak month from 1,046 MMcf per day to 1,156 MMcf per day. After subtra cting the 5,460 MMcf per day that flows out of Tennessee to other markets, the average daily amount of pipeline capacity available to supply Tennessee markets 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 pipeline capacity should be able to accommodate the additional capacity at existing natural gas EGUs.

• Finally, Synapse Energy Economics analyzed the 2012 U.S. electric dispatch system and evaluated the a vailable, 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

- d ispatch target of 70 percent and, under the assumptions modeled, reach an 80 percent capacity factor.

Commenters supported the assumption that the existing pipeline capacity is adequate to achieve the 70 percent natural gas capacity assumption in Virginia . 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 day of pipeline capacity entering Vi rginia from the Cove Point LNG terminal. The 70 percent capacity assumption would increase the level of total gas delivered to customers during the peak month from 1,485 MMcf per day to 1,583 MMcf per day. Even subtracting the 1,800 MMcf per day of gas inf low 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 two and a half times the peak month gas

us e (~4,000 MMcf per day of capacity vs. ~1,600 MMcf per day of consumption). Thus, existing pipeline capacity should be able to accommodate the additional capacity at existing natural gas EGUs. In addition, Synapse Energy Economics analyzed the 2012 U.S. el ectric dispatch system and evaluated the available, 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 analys is indicated that each of these three regions could exceed EPA's natural gas re

dispatch 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 reasonablen ess of the assumption as applied to Virginia, they included the 70 percent assumption in our calculations. Commenters stated that, as with EPA's calculation, the increased capacity from existing NGCC units were assumed to operate at the average historical emissions 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.112 Commenters stated that Clean Wisconsin's own analysis of NGCC EGUs in Wisconsin provides evidence both that t hose units could operate at higher capacity factors, and that there is significant room for increases in operation. Commenters stated they found that half of the fleet was operating at capacity factors between 45% and 55% in 2012, with an overall system av erage of just under 40%. Commenters stated these capacity factors are significantly higher than those of so

- called "peaking plants," which have an average capacity factor of less than 10% in the Midwest Reliability Organization's territory, according to th e 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. Commenters noted this 70 percent assumption reflects plans that Virginia's utilities already have in place and stated that, excluding the units for which generation contracts with Dominion will expire in the next few years (Hopewell and Doswel l), the average capacity factor for existing natural gas EGUs in Virginia was already 71.6 percent in 2012. Commenters also noted that, in Virginia, there is enough historical fossil generation to be displaced to achieve a 70 percent capacity factor in 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%. Commenters referred to a report by the Massachusetts Institute of Technology which indicated that NGCC generators are able t o operate at capacities as high as 85%. Commenters stated that, while there are a variety of factors that determine dispatch, there is no technical limitation for NGCC to ramp up their capacity to factor to at least 70%, as assumed by the EPA. Commenters r eferred 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 generation from NGCC to 54 TWh assuming an 80% capacity factor. Commenters state d that nationwide potential is far greater. Commenters stated that this report also concludes that there is "ample, existing, unused potential that would require no additional plant construction costs to displace the generation from existing coal capacity. "

Comment 6 : Commenter s suggested revising the capacity factor for NGCC facilities under construction under Building Block 2.

Response 6 : The EPA agrees to the extent that under construction NGCC unit s 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 used 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 capacity factors of NGCC plants to achievable factors, based on the characteristics of specific energy markets such as the Electric Reliability Council of Texas (ERGOT). Comm enters stated that operating NGCC units at an average 70% capacity factor is not realistic for Texas, even with low natural gas prices resulting from shale. Commenters noted that NGCC capacity factors in Texas are typically in the 40% range and113 adjusting t he capacity factor from 70% to 50

- 55% provides opportunity for carbon reduction to be achieved while maintaining reliability and affordability for CPS Energy customers.

Commenters questioned EPA's assumption regarding allocation of capacity for "under

cons truction" NGCCs. Commenters asked EPA to explain its basis for assuming that NGCC units which are "under construction" can allocate 15% of their capacity to displace coal generation.

Commenters recommended that EPA increase the amount of generation from un der construction NGCC units incorporated in the BSER re

- dispatch calculation by allocating a capacity factor of 55 percent as available for re

- dispatch purposes (and a capacity factor of 15 percent as unavailable), instead of the 15 percent available (vers us 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 many under construction NGCC plants are being built to replace reti ring coal generation deemed uneconomic due to age, lack of pollution controls, and cheaper alternatives. Commenters noted that of the nine states with under construction NGCC units incorporated into the Building Block 2 target methodology, all except for C alifornia have significant planned coal generator retirements scheduled between 2012 and 2018, and that the total capacity of planned coal retirements in these states outweighs the capacity of under construction NGCC plants by nearly 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 operates, 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 Building 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 cha racteristics of specific energy markets such as the Electric Reliability Council of Texas (ERCOT). Commenters stated that operating all NGCC units at a 70% capacity factor is unrealistic for Texas. Commenters stated that any dispatch method that preferenti ally selects resources 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 ou tside of emissions constraints for reliability.

Comment 7 : Commenters recommended the EPA use a less stringent 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 emission reduction standard calculation using less than a 75 percent capacity factor for NGCC units.

. 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 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 period114 (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 states may consider local circumstances as they develop their plans, including system reliability, fuel diversity, and other regulatory requirements

. Peak l oad 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

- dispatch that make 60 percent a more reasonable estimate of an achievable annual average NGCC utilization rate for states with a high penetration of natural gas and zero

- emissions resources. Commenters stated that, even though the nationwide NGCC utilization rate is over 60 percent in some peak 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 realities on the system will sustain a dispatch schedule in the future that could be increased to 60 percent but not higher.

Commenters stated that, in states with a high penetration 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 resources during certain times of the year and

r eliability impacts during others. Commenters stated that, while unit capability is a relevant consideration, system capability must also be considered. Commenters stated that, in ignoring system capability considerations, EPA fails to account for the seaso nal variability of electricity demand. Commenters stated that, while capacity factor 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 hou rs of the year, in reality, all plants cannot operate during all hours of the year as, in the power sector, supply must always equal demand for the system to operate within its reliability limits. Commenters stated that during the spring and fall shoulder months, electricity demand typically falls to a fraction of its summer and winter levels, which in the New York system means demand can dip below 12,000 MW. Commenters stated that, with more than 11,000 MW of zero emissions resources typically available du ring those hours, operating NGCC plants in the manner needed to produce a 70 percent annual capacity factor would displace those zero

- emissions resources in favor of a relatively high

- emissions fossil

- fuel

fired 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. Commenters 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 transmission constraints d o not allow NGCC capacity to be transferred from certain portions of the state to 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 concerns the use of oil in these dual

- fuel units and recommended that adjustments to the emissions should 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 peak summer t ime load period or winter periods when natural gas deliveries are constrained and preferentially routed to residential customers, NYISO rules require generators in the NYMA to combust oil in dual fuel units to ensure the reliable provision of electricity i n the event of an 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 EPA, particularly in its Cross State Air Pollution Rul e (CSAPR). Commenters stated that in its October 14, 2011 revision to the final rule, EPA noted, in a Technical Support document, that it was revising the emission budget for New York because of very specific electric system constraints:

EPA is proposing to increase the New York state annual 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. These revisions are based on three types of local operati ng 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 conditions.

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

EPA is increasing New York's 2012 and 2014 annual SO2, annual NOx, and ozone

season NOx budgets based on c omments received on the revisions rule demonstrating that the East River plant is in an out

- of

- merit

- order dispatch area with conditions likely to necessitate what would otherwise be non

- economic generation. EPA re

- calculated the emissions from this facil ity with out

- of

- merit order dispatch to reflect the input assumption changes. These calculations yield increases 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 : Comm enters supported consideration of options between 65

- 70%.

Response 8 : The EPA disagrees with the establishment of a CO2 emission reduction standard calculation using less than a 75 percent capacity factor for NGCC units. 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 standa rds 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 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 states may con sider local116 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 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 price 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 BSER and related Greenhouse Gas measure.

Commenters stated that Emera Energy's NGCC assets will support EPA's targeted NGCC utilization rate of 65 to 75 percent. Commenters cautioned that the ability of their assets to increase NGCC utilization rates is strongly affected by infrastructure, system, and economic considerations, such as limits on the ab ility of the 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 proposed Clean Power Plan along with other federa l regulations requiring emission reductions from fossil fuel

- fired power plants will increase investment in the United States natural gas infrastructure allowing for increased utilization of our NGCC assets and enhanced geographic parity in natural gas pri ces 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 flexibility and infrastructure transition.

Comme nt 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 emission reduction standard calculation using less than a 75 percent capacity factor for NGCC units. Implementing authorities may encourage more stringent capacity factors.

. In response to additional analy sis 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 p roviding 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 i nterim 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, i ncluding system reliability, fuel diversity, 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 Mitigation Measures TSD for the CPP Final Rule support ing the final CPP.117 The following are summaries of the specific public comments under this comment:

Commenters advocated that the EPA consider re

- dispatching affected NGCC units to a higher fleet

- wide capacity factor than currently contemplated by the prop osal, but basing that higher capacity on the average annual capacity instead of nameplate capacity.

Commenters noted that per the EPA, roughly 6 percent of NGCC units operated at a 75 percent capacity factor or higher in 2012, and this analysis 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 achi evement 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 for the peaking power, while still averaging a f leet

- wide capacity factor of 75 percent. Commenters stated that overall, most of the RGGI states are able to re

- dispatch to lower

- emitting EGUs, serving as a region to depict the achievability and reasonableness of the Building Block Two methodology. Comme nters indicated that in the RGGI region, there are over 70 affected NGCC plants representing 25,559 MW of nameplate capacity.

Comment 10 : Commenter s requested that states be required to explore even greater dispatch targets if they seek lowered complianc e targets due to the infeasibility of other building blocks.

Response 10 : The EPA disagrees. 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 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 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 reliability, fuel diversity, other regulator y requirements and infrastructure. States may choose to encourage more stringent capacity factor requirements at their discretion. 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:

Specifically, commenters recommended that, if a state suggests that BSER should be weakened for a state due to some part icular concern with a Building 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 state.118 Comment 11 : Commenter s recommended the EPA select a 75% NGCC target utilization rate, as this will cut GHG the most, and fastest.

Response 11 : The EPA agrees that an average annual capacity factor of 75 percent for NGCC units is appropriate for the calculation of CO2 emission p erformance rates

. 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 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 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 reliability, fuel diversity, other regulator y 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 Mitigation Measures TSD for the CPP Final Rule supporting the final CPP.

Comment 1 2 : Commenters stated that Pu erto Rico will not be able to benefit from Building Block 2.

Response 1 2 : The E PA has decided not to include this provision in the final CPP because we are not finalizing the Rule for Puerto Rico at this time.

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

In comments on the Tribal & Territorial supplemental proposal, commenters stated that, while the EPA believes that existing and planned LNG import capacity in Puerto Rico supports 70 percent dispatch at the territory's e xisting NGCC facility, this assumption is only true for the existing EGUs in Puerto Rico, and not for any future NGCC facility development. Commenters stated that, based on the historical performance of the EcoElectrica EGUs, PREPA found that these units' current annual generation capacity exceeds 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 1 3 : Commenter s stated that, for consistency, the same calculation regarding the first 55 percent of the generation should be applied to units that were operating in 2012 as well as units under construction.

Response 1 3 : EPA thanks the commenter s . The final calculations include provisions to improve consistency. Please see sections V.A, and V.D of the 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 that only 15 percent (the difference between the 70 percent ceiling factor and the assumed 55 percent generation) is available for re

dispatch from natural gas

- fired, combined

- cycle combustion turbines that are under construction because the first 55 perce nt of the generation is reserved for the generation potential needed to meet the other system needs that prompted construction 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 methodology allows for re

- dispatch from a baseline of 55 percent generation up to a maximum of 100 percent generation, which is inconsistent.

Commenters stated, as the proposed emission guidelines reco gnize, there are many available options for reducing carbon dioxide emissions from existing power plants through modifications or upgrades at these plants. Commenters said, an analysis focused on these "onsite" measures would by necessity be expansive in s cope

- including not only significant improvements to the efficiency or "heat rate" of the plant, but also other emission reduction measures such as co

firing or re

- powering with lower

- carbon fuels; utilizing renewable energy sources to provide supplementa l steam heating; using available waste heat to remove moisture from coal or switching to higher

- rank coal, and implementing combined heat and power (CHP) systems at plants near industrial facilities or district heating systems, among other solutions. Comme nters said, for example, engineering firms have estimated that with modest modifications, coal

- fired power plants can derive as much as 50% of their heat input from natural gas. Commenters said,

co

- firing at this level could yield emission reductions of 20 %, and could be combined with heat rate and other improvements to achieve even deeper reductions at a specific plant.

Comment 1 4 : Commenters stated that the EPA has not demonstrated that a 65 percent utilization rate for NGCCs is achievable.

Response 1 4 : The EPA disagrees. 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 establ ish 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, trading, time to develo p 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 analyses are prescriptive, and states may consider local circumstances as they develop their plans. See 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 indicated that in support of the 65 percent 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 r easonable basis for its determination that a 65 percent utilization rate is achievable. The commenters stated that while the EPA recognizes that there are constraints on increasing NGCC utilization rates, the EPA does not appear to have adequately consider ed these 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 provided sufficient time within which to address any necessary ex pansion of infrastructure (79 Fed. Reg. at 34,837 and 34,862

- 64). Commenters also asserted that the EPA stated that the level of potential coal

- to

- gas switching associated with assuming that existing NGCC units could run at a utilization rate up to 70
perc ent will not impact natural gas or electric system 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 conclusions, shoul d be amended to account for a broader set of potential system constraints and their cumulative impacts.

Commenters stated that the EPA has not provided a reasonable basis for its determination that a 65 percent utilization rate is achievable. Commenters st ated 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 1 5 : For Utah, c ommenter s provided analysis of two different capacity factor assumptions, 50% and 60%, and suggested the EPA's 70% capacity factor assumption is unrealistic.

Response 1 5 : The EPA disagrees that the analysis would accurately reflect the provisions of the 111(d) final rule

. 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. Th e commenter s ’ calculations reflect the provisions of the proposal, and EPA believes that Utah can meet the final rule requirements. The 111(d) final rule requires that states develop plans that establish emission standards for affected EGUs. We are providi ng 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 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, includi ng system reliability, fuel diversity, 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 Mitigation Measures TSD for the CPP Final Rule supporting th e final CPP.

The following are summaries of the specific public comments under this comment:121 Commenters stated the analysis was developed to evaluate 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 described the results of their analysis: the 2030 emissions rate goal increases under each of these scenarios 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 sh rink from 391 lbs/MWH to 344 lbs/MWH; and with a 50% capacity factor the EPA 2030 emissions rate 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 Strategies to evaluate four d ifferent capacity factor scenarios to determine how changes in the operation of affected existing fossil plants impact the "compliance gap

. " Commenters stated that, assuming affected fossil units operate at their minimum reported capacity factors, the emis sions rate increases by 28 lbs per MWH to 1,741 lbs/MWH and the compliance gap increases to 419 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 stated 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 l argest contribution towards compliance; Utah's emission rate would decrease to 1,671 lbs/MWH reducing the compliance gap by 42 lbs/MWH to 349 lbs/MWH.

Comment 1 6 : Commenter s questioned whether the EPA's assumption that Washington's NGCC capacity factor can go from 23% to 40% is reasonable.

Response 1 6 : The EPA disagrees. 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 substantial flexibility as to how they structure those plans to achieve the 111(d) requirements. The flexibility includes, for exampl e, 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 B locks are not prescriptive, and states may consider local circumstances as they develop 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 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 NGCC facilities in Washington are used for purposes other than base

load generation, including: 1) meeting peak loads, 2) real

- time integration of variable energy resources (VERS), and 3) occasionally, to maintain system stability. Commenters stated t hat resources used for these types of purposes generally have a low utilization rate

- both in terms of number of hours operated and the proportion of generating capacity used when operated.122 Comment 1 7 : Several commenters stated that the 70% average capac ity factor for NGCCs proposed for Building Block 2 was unsupported and unachievable for a variety of reasons, including reliability, permit limits, infrastructure, sustainability, and need for more analysis.

Response 1 7 : The EPA disagrees. 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 establ ish 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, trading, time to develo p 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 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 fin al 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:

Some of the commenters' general statements are s ummarized here, while subsequent comments addressed in later in section 3.2.2 provide additional detail.

Some commenters expressed general concerns regarding costs, control, growth, reliability, dispatch authority, and integration of the electrical system.

• Commenters contended that EPA assumes that utilities will shift generation from coal to natural gas units, and that natural gas units will run at 70 percent capacity. However, according to the commenters, if these natural gas units were more cost

effectiv e, they would already be running at higher levels.

• Commenters argued that requiring natural gas combined cycle units to operate at 70 percent capacity is a goal and not an emissions standard and it increases gas emissions without consideration of reliabil ity, cost or ownership.

• Commenters asserted that the EPA's assumption appears 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 analysis of the technical
cap abilities of the plants or gas delivery system.

• Commenters stated there are events outside of an EGU

- operator's control which affect an NGCC facility's annual capacity factor.123 • Commenters stated that the homogenous energy mix resulting from such explicit
p reference in fuel sources could leave the grid more vulnerable to supply constraints and price shocks due to unforeseen production and transmission disruption.

• Commenters stated that the EPA is incorrect in assuming that many states will be able to meet p eak electricity demand without operating their coal

- fired power plants; this assumption disregards the reality that electricity is not just about generating megawatt

- hours but is also about generating capacity and meeting electricity demand every second of every day.

• Commenters asserted that a certain amount of NGCC availability is needed for load

- following in order to support increasing renewable energy levels.

• Commenters stated the EPA failed to adequately consider 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 retired as result of the rule, including (i) certain coal

- fired EGUs may be "black start" facilities that are capable of restarting without any elect ricity input; (ii) certain coal

- fired EGUs may provide voltage support and other grid reliability benefits; and (iii) certain coal

- fired EGUs may be deemed supercritical "must run" facilities by FERC and/or RTOs, which will make retirement impossible.

• Comm enters indicated that the assumption that all NGCCs should run at 70% capacity factor fails to recognize the benefit of NGCCs to the electrical system in that NGCCs can operate across resource categories (base

- load, intermediate and peaking) depending on t he needs of the system

- this flexibility is lost under EPA's proposed approach.

• Commenters stated the EPA's assumptions regarding the ability of states to require significant increases in natural gas generation are unrealistic and unsupported.

• Commenter s 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 for a sustained period of time is not whether some plants, which may have historically 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 another was sufficiently large to demonstrate that the existing natural gas and electric transmissi on systems have the necessary capacity and flexibility to accommodate 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 facilit ies were constructed to meet projected load growth, rather than to serve as additional available capacity. Commenters stated there is little surplus capacity to reduce coal generation when growth projections are taken into account. Commenters suggested 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 FERC

- established economic, market and practical considerations that make dispar ities between unit availability and operation net

- beneficial. Commenters stated that 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 transition to 70% utilization of natural gas resources and shutdown or retirement of large amounts of existing base

- load capacity overlooks the impacts of stranded investments, market dispatch fundamentals, energy infrastructure constraints, system reliabi lity, 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 because coal plants do not have the capability to ramp quickly enough to serve this function and increased generation from wind/solar plants increase the need for regulation.

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

Some commenters expressed general concerns regarding various constraints that may prevent realizing a 70 percent capacity, such as des ign, permit limits, infrastructure, new NAAQS, peak loads, and water supply.

• Commenters asserted that, although a 70 percent capacity factor for combined cycle plants might be technically possible, permitting, transmission constraints, and higher maintenan ce costs in the energy demand all 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 designed to operate at much lower thresholds that the proposed 70 percent capacity factor and, according to the commenters, when such NGCC plants are operated at higher levels, they will
wear out. Commenters reported that they typically do not have air permits that allow ope ration at anything close to the 70 percent capacity and that they are doubtful that the natural gas storage rights and pipeline capacity currently exists for operation at the level assumed by the proposed standard.125 • Commenters stated that some units are un able to increase 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 make up for these lower

utilization units.

• Commenters contended that there are numerous technical 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 see ms to ignore that new NGCC generation must meet existing and revised NAAQS standards when it prepared baselines and its building block structure that relies so heavily on NGCC.

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

• Commenters asserted that existing natural gas inf rastructure is unavailable and significant time will be needed to expand natural gas infrastructure.

• Commenters stated some Iowa NGCC facilities have existing, available natural gas supply that would allow them to operate at a 70% capacity factor; however

, there is some question whether adequate firm gas supplies will exist for other Iowa facilities. Commenters stated transmission system availability may affect whether certain NGCC plants will be able to operate at a 70% capacity factor.

• Commenters stat ed 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 each unit at the plant on a rolling twelve

- month basis, which would prevent it from operating at Building Block 2's target capacity factor.

• Commenters stated that units are subject to contractual commitments which dictate operational time and may need upgrades to run at higher capacity factors. Commenters concluded the EP A has arbitrarily and capriciously proposed this building block, without full analysis of the ability to implement 70% capacity factors on NGCC units and the impact by other Building Blocks.

• Commenters stated that the EPA has overlooked the purpose and na ture of NGCC units in many states: to provide critical peak power.

• Commenters stated that it is not rational to assume without data that the technical plant capability, gas, gas transportation, gas storage, and electric transmission capacity are all availa ble or easily developable to double the generators' historic average performance.126 Some commenters expressed general concerns that, while some NGCCs could meet a 70 percent capacity goal, not all NGCCs could meet 70 percent capacity.

• Commenters stated th at, as owners of significant combined cycle capacity, they have never been able to economically dispatch our units 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 were 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 potential generation. For states with only a few NGCC power plants, commenters stated that achieving an average capacity factor of 70 percent may be overly optimistic.

• According to commenters, units were financed, designed, and maintained f or the specific purpose of operating in cycling duty rather than as base

- load, and many of these units would not be able to achieve the target utilization rate without significant upgrades and testing to ensure that they are technically capable of operatin g near full load on a continuous annual basis. The commenters added that these units' permitted emission limits may not allow 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 specific capacity factor, due to the technology used, that varies across the fleet that may not be amenable to a 70% capacity factor. Commenters stated the EPA should 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 t o adequately demonstrate that a minimum 70% capacity factor requirement has been achieved 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 identified of a specific requir ement 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 different markets with different demands, different owners and operators with different practices, and in intended

use.

• Commenters stated the fact that a portion of a system may have been able to manage increased gas

- based elect ric production in 2012 does not justify its use as127 a national benchmark for the future because limitations such as the location of each plant in the electric grid and load must be considered, as these locational limitations matter as much as unit size or t echnical capabilities.

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

• Commenters asserted that, based on the experience of Mi nnesota Utilities, in operating combined

- cycle plants, they believe it would be impossible to maintain a 70

- percent capacity factor for such plants over the long term, which could lead to serious compliance problems and substantial degradation of the relia bility of the nation's electric system.

• Commenters stated that it is unclear if EPA considered 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 o pinion on whether a 70 percent capacity factor is sustainable; Kentucky utilities voiced a range from 55

- 80 percent, with maintenance downtime being a major concern.

• Commenters stated that the EPA has not demonstrated that all state NGCC fleets will be able to sustain that rate over the long

- term

• Commenters stated that the NERC notes that NGCC units have traditionally been used for load following purposes and, while some are capable of operating at a high capacity factor, they are generally less wel l suited to serve as base

- load resources than coal generation.

• Commenters stated the dynamics of wholesale power markets make it difficult for existing NGCC power plants to achieve and sustain an average 70 percent capacity factor. Commenters stated that increased output from existing NGCCs will signal a market need for new NGCCs to provide intermediate generating capacity and these cheaper, more efficient new units will arise to replace generation from existing units before existing units can achieve an a ggregate 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 attain high capacity factors only through cyclica l operating patterns, rather than over sustained periods that can occur during high demand seasons.

• Commenters stated the 70 percent target and expected NGCC capacity is overly optimistic in that while individual NGCC may achieve 70 percent capacity facto rs 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 additional analysis is needed.

• Commenters, in agreement with EPRI's comments, asserted that EPA should conduct detailed transmission reliability evaluations as part of the reliability, economic and financial impacts analyses of the rule.

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

• Commenters stated that the EPA's 70 percent assumption substantially overstates the amount of NGCC generation that would be available 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 baseline inventory includes NGCC units that have been e ither out of service for several years or retired and 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.

• Commenters stated t he EPA's analysis included NGCC units that have been out of service for several years or retired.

Some commenters expressed general concerns regarding costs.

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

• Commenters stated the EPA's proposed 70 percent target utilization rate is unreasonab le because the EPA's economic impact analysis failed to consider
state

- specific employment impacts of such extensive re

- dispatch.

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

• Commenters stated that the EPA's assumption of economic dispatch at an average 70 percent rate is derived by using an arbitrary $30/ton CO2 price (tax) which would fundamentally convert the current ele ctric grid from an economic dispatch to a carbon dispatch model.

• Commenters stated the increased cost to our communities under Building Block 2 is estimated to be about $370 million over the period 2020 through 2030. Commenters stated this increase includ es the cost of new pipeline capacity needed to provide additional gas to the facility.129 • Commenters stated that, from an economic dispatch perspective, EPA's assumed 70% NGCC utilization rate for BSER is unrealistic and based on faulty assumptions and expec tations.

• 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 stated that several billion dollars will need to be spent on new gas pipelines and storage fields in order to adequately increase the level of firm resources that would be needed."

• Commenters stated that additional, costly transmission infrastructure would be required for re

- dispatch to be viable. Commenters explained 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 transmissio n infrastructure typically operates at maximum capacity.

Comment 1 8 : Commenters expressed concern regarding the assumed NGCC capacity factor relative to new and older units.

Response 1 8 : The EPA disagrees , and believes the data support the 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 stru cture 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 reliability, fuel diversity, other regulatory re quirements 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 7 5 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 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 the EPA's position conflicts with EPA's assumption that new, under

construction, NGCC units will only perform at a 55% capacity factor (79 FR 34896). Commenters stated that this 55% capacity factor assumption may be reasonable for these n ew, market

- driven units, but 55% would be a completely unreasonable assumption for existing, older NGCC plants. Commenters stated the EPA's 70% capacity

- factor assumption also conflicts with its own findings in the New

- Source 111(b) Rule Proposal, which fo und that small NGCC units130 that are generally designed for operation during peak demand will usually supply less than one

third of their potential electric output to the grid (79 FR 1445).

Commenters stated that, while the EPA describes NGCC units as techn ically capable of operating in base

- load roles where the average annual availability exceeds 85% and can exceed 90% for some units (79 FR 34862), one of the two studies 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 upgrades occurred.

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

Comment 1 9 : Commenters contended that the recent increase in natural gas gen eration provides little justification for a state's capability to maintain a 70 percent NGCC fleet

- wide capacity.

Response 1 9 : 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. T he 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 reliability, fuel diversity, other regulatory requirements and infrastructure. The 111(d) final rule do es 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 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 nationally trending increases in NGCC dispatch and decreases in coal generation dispatch (and, as included in another comment, small percentages of existing NGCC units nationwide that operated at annual or seasonal capacity factors of 70 percent or higher in 2012) do not provide an independent rationale for re

- dispatch up to 70 percent of NGCC units' capacity. Rather, they appear to be ex post rationalizations of a re

- dispatch amount that EPA has otherwise failed to explain. The IPM model runs that EPA conducted to analyze re

- dispatch costs are of no import to the Agency's initial determination regarding the appropriate capacity factor. According to the commenters, the EPA must justify the NGCC capacity factor it ultimately utilizes for each state to which that capacity factor applies. The commenters asserted that the EPA cannot do so because state

- specific considerations render the 70 percent capacity factor unattainable.131 Commenters recommended that the EPA review the dispatched gen eration in 2012, which they believed demonstrated that even with historically low natural gas prices, natural gas dispatch did not approach 70% utilization; indeed, capacity factors for NGCC units were 60.4% in the PJM reliability region.

Commenters state d that the EPA points out that nationwide NGCC generation increased by approximately 81 percent between 2005 and 2012 (compared to the estimated 47 percent increase by 2020 that would be required in order to implement Building Block 2), while failing
to ac knowledge that this figure includes new NGCC units that were constructed from 2005 to 2012 and does not simply reflect increased utilization of existing units, which is the centerpiece of the Building Block 2 approach (GHG Abatement Measures TSD at 3

- 11).

Commenters contended that the recent increase in natural gas generation provides little justification for a state's capability to maintain a 70 percent NGCC fleet

- wide capacity factor. Commenters stated t he EPA provided no supporting data to justify that an entire state could, beginning in 2020, indefinitely achieve an NGCC fleet

- wide average capacity factor of 70 percent. Commenters stated that i n fact, during 2012, with historically low natural gas prices and high natural gas consumption from the electri city sector, no state obtained a 70 percent NGCC fleet

- wide annual average capacity factor. According to the commenters, the EPA has misinterpreted the role of NGCCs in an integrated electricity system and eliminated or severely reduced their ability to re liably serve a state's electricity demand.

According to commenters, the EPA stated that NGCC generation increased by 22 percent between 2011 and 2012, supposedly demonstrating that existing natural gas infrastructure can accommodate rapid increases in exi sting NGCC utilization (GHG Abatement Measures TSD at 3

- 9 to 3

- 10). However, commenters assert ed that the EPA fails to note that even after this expansion

- which was largely a function of historically low natural gas prices in 2012 due to the widespread d evelopment of hydraulic fracturing technology

- over half of the existing NGCC units that EPA examined still operated at a capacity 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 units would require a 75.9 percent increase over the 2009 capacity factor (the lowest reported) and a 37 percent increase over the 2012 cap acity factor (the highest reported). Commenters stated that there is no rational way to conclude that Building Block 2 is adequately demonstrated. Commenters referred to the EPA Goal Computation TSD and stated that not a single state had a 70 percent capac ity factor for NGCC generation. Commenters stated that the highest state 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 Hampshi re

- 53 percent, Ohio

- 55 percent, Alabama and Pennsylvania

- 59 percent, Virginia

- 60 percent and Conneticut

- 63 percent). Commenters stated that the NGCC historical capacity factors demonstrate that the EPA's proposed 70 percent capacity factor is not achievabl e, is not demonstrated, and is arbitrary and capricious.

Even with historically low natural gas prices for NGCC 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 outag es, both forced and unforced; the price of natural gas will not remain at low

- levels, due to the volatility of the natural gas market.

Commenters stated the E PA incorrectly claims that its 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 commenters stated the EPA fails to recognize that market

- caused shifts between coal and gas generation 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 generated 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 cyclic al factor, while coal

- fired plants can run at higher or lower capacity factors depending upon overall demand and the relative price of coal and natural gas.

Commenters stated that the EPA policies

- such as MATS and the proposed CPP rule force the retirement of coal base load power plants and are therefore a permanent structural barrier to assuring the electric grid remains diverse enough to minimize both reliability crises and higher and more volatile prices that reverberate throughout the economy. Commenter s further stated it is not correct for EPA to claim that its proposal merely builds on a preexisting trend; rather, EPA itself is the cause of a massive shift of coal generation to gas and of the consequences that will ensue. The commenters cited a 2008 DO E 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 commenters also referred to a study performed by the Duke University Nicholas School of Environment and provided the following additional information.

Commenters asserted that the EPA's view that the unprecedented size of coal EGU retirements are a product of natural gas prices and not the Agency'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 prices." According to the commenters, without the MATS rule, only 9 percent o f the current coal capacity 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 generation 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 the 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 February 2012, the month before the study was published, the commenters reported that the price of coal for electricity generation was $2.41/MMBtu and the price for natural gas was $3.72/MMBtu, fo r 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 electric 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 2.0 1. According to the commenters, the Duke study also found that, with EPA regulations, natural gas prices to utilities can increase to more than four times the coal price (NG2CP of 4.3) and remain competitive with coal plants. In other words, the
commenters asserted, the EPA's finalized MATS regulations 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 rule . 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 in cludes, 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 perio ds. The Building Blocks are not 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. The 111(d ) final rule does not require every individual NGCC unit 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 prea mble 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:

Individual units have different capabilities.

• The EPA did not undertake any assessment of the differences 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 operatin g above 70 percent on an annual basis were "largely dispatched to provide base load power," and that units operating above 70 percent on a seasonal basis typically "were idled or operated at lower capacity factors" during periods of lower demand. But EPA d id not examine whether the NGCC units providing base load power have different characteristics 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 dem and did so because of economic, technical, or regulatory constraints on their 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
t he electric system. In some cases, NGCCs operate as base load resources; in others, they operate as non

- base load resources

- such as load following, mid

merit or even peaking resources, playing a critical role in providing essential ancillary services to balancing areas.

• Different NGCC plants may operate different equipment and service different demand profiles and when EPA assumes all existing plants can achieve its best system standard, the agency conflates technical capability with operational feasibil ity.

• The 70% capacity factor is an arbitrary number selected based on the historic operation of a small percentage of NGCC units and justified with qualitative criteria that offer nothing to credibly conclude that the 70% determination is technically, eco nomically, or legally feasible.

• According to the commenters, EPA's process for selecting the 70% capacity factor gives no regard to important considerations such as the availability of adequate transmission capacity to allow increased NGCC utilization to offset the operations of other fossil fuel

- fired facilities located in the same state; the availability of adequate and reliable sources of gas supply; existing unit conditions; outage scheduling; or the lack of regulatory authority or mechanisms
necessary to establish and enforce such utilization requirements.

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

• Despite the EPA's assumption that all NGCC units currently in operation were designed to achieve utilization rates between 85 and 95 percent (79 Fed. R eg. at 34,863), NGCCs that have been designed to operate as 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 achievable, the EPA must "establish that the test data relied on by the agency are representative of potential industry

- wide performance, given the range of variables that affect the achievability of the standard." Sierra Club v. Costle , 657 F.2d 298, 377 (D.C. Cir. 1981). T his 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 them from its calculations of135 each state's existing NGCC capacity in the Goal Computation TSD. Compare 2012 NGCC Spreadsheet (including, inter alia, Martinez Refining units in assessment of achievable NGCC capacity factor); with Goal Computation TSD, App. 7 (excluding, inter alia, Martinez Refining units from California's existing NGCC capacity).

• Commenters stated that, because the EPA did not conduct any analysis to understand why a small number of units in 2012 operated 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 arbitrary.

• Com menters offered several reasons why certain units may not be able to operate in a baseload mode all year: all NGCC plants have operating permits that limit emissions, and these permits may limit the number of hours these facilities may operate, particularl y during the summer ozone season; a utility may build an NGCC unit specifically to operate in an intermediate mode because it already has other baseload resources; and utilities build different types of facilities in different locations to serve discreet p urposes and these facilities cannot be operated in a different fashion to serve a different purpose without undermining their ability to serve their original purpose. Commenters stated that, for instance, Basin Electric Power Cooperative designed the Deer Creek NGCC facility to operate a little less than half of the time, not 70%, in order to integrate 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 capabi lity to dispatch up when the wind suddenly does not blow, and need to be able 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 purpose.

The 90% operatin g at lower rates should be addressed.

• The EPA's selection of 70% as a reasonable capacity factor for NGCC units as BSER is arbitrary and capricious because the EPA only considered the result of 10% of the NGCC fleet operating at a 70% capacity factor and n ot 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 achieved consistent, or even intermittent, operation at 70% of capacity, the NGCC capacity target set i n Building Block 2 is completely arbitrary and the Proposed Rule establishes a 70% NGCC capacity target that is grossly inflated and practically infeasible.

• Commenters stated the EPA's rulemaking data on the operation of NGCC plants conflicts with its pre sumption that all units can reach a 70% capacity factor. Commenters referenced the GHG Abatement Measures TSD 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 times, the vast majority of NGCC units failed to meet the 70% capacity factor (only 19% of NGCCs in the winter of13 6 2011/2012 and 20% in the summer of 2012 reached this capacity factor); and (3) only 6% of NGCC units operated at a 75% capacity factor, or hig her, in 2012 and only 16% of units operated at 65% of higher.

• Commenters concluded that one out of ten units achieving 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 statistics 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 low natural gas prices.

• The EPA has failed to establish that the 10 percent of existing NGCC units operating at 70 percent capacity factor or higher are repres entative of the remainder of NGCC units in the source category. The fact that only 10 percent of the NGCC units that operated in 2012, a year of exceptionally low natural gas prices, did so at a 70 percent capacity factor is more indicative of the inabili ty of all NGCC units to operate at that level than the opposite.

• It is unreasonable to assume (79 FR 34863) that because natural gas consumption increased by 20% in 2012, a record low market price period, the system is now capable of maintaining 100% of t he NGCC units operating 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 that any of the units that operated at a 70 percent capacit y factor in 2012 did so in previous years, yet EPA assumes that these and other units can operate at that level indefinitely into the future. Presumably, if a significant number of NGCC units had operated at 70 percent capacity factors over longer periods of time, 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% capacity in 2012 that the rest of the NGCC fleet can be dispatched at this same level every ye ar. 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 more valid to say that 2012 does not represent a NGCC capacity factor that can be achieved on a long

- term basis

. Commenters stated the EPA can only conclude that NGCCs operated at a 45.8% capacity factor during a single year that experienced an unusually high level of NGCC operation due to unique circumstances.

• Commenters disagreed with the use of 2012 as the basel ine year in the EPA's goal calculation because 2012 was the year of lowest coal generation utilization rate in137 Arizona in the past 10 years and is not representative of an electric utility system under full demand load. Commenters stated that, not only is 10 percent of the industry an insufficient sample size, the use of only 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 NGCC fleet over a 1

- year period, th erefore, EPA's own data indicate that what is proposed 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 7 0 percent capacity factor in certain seasons is not representative of how these units could 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 operating lev els are needed than units that do not have that opportunity. Accordingly, EPA cannot simply assume that seasonal performance is a fair benchmark of continuous, year

- round performance.

• Commenters stated that, to assume that, because some units of the NGCC fleet operated at 70% of capacity in limited operation, therefore the same units are capable of running at 70% for much longer periods of time is fool

hardy. Commenters stated that, based on common usage in the electric industry, this clearly indicates th at those units operating at 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%, the transmission interconnection and transmission agreements reflect tha t capacity and, likewise, if a unit was constructed to run at 70% of capacity for winter or summer peak periods, that also would have been reflected in transmission wheeling agreements or interconnection agreements.

70 % is unreasonable, given the market forces.

• The market forces that actually determined NGCC dispatch in 2012 do not appear to agree with EPA's assessment of economic reasonableness for high NGCC dispatch, since even at the historically low natural 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 existing NGCC fleet to achieve average utilization rates of 70 percent because a si gnificant number of NGCC units achieved capacity factors between 50 and 80 percent during the winter and summer seasons of 2012 (79 Fed. Reg. at 34,857). This conclusion is not based on sound data analysis and is predicated on a misunderstanding of the ele ctric system. Neither the existing natural gas nor the existing 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. This demonstrates the138 importance of a nalyzing the performance of individual plants in the context of the whole system. It also reinforces the idea that, even though one plant may achieve a certain utilization rate at one point in time, other plants within the same system may not be able to do so, and system

- wide constraints may become particularly acute when, on average, all units are expected to achieve that utilization rate. The appropriate measure for determining whether existing 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 whether the increase in the utilization rate from one year to another was sufficiently large to demonstrate that the existing natural gas and electric transmiss ion systems 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 same data used by the EPA shows that only a fraction of those plants cite d by EPA as operating at high capacity factors in fact had experienced a significant increase in their utilization rates (citing Appendix D to the comments). These particular units, therefore, already operated in a system that was designed to accommodate t heir high capacity factors, so EPA's analysis does not provide sufficient justification to find that the entire natural gas pipeline and electric transmission systems can accommodate large increases in natural gas usage.

• Commenters stated the EPA's assump tion that the NGCC 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% have ever run at 70% capacity for a year. Commenters stated that, to extrapolate from th is that the entire fleet can achieve 70% is unrealistic, and to base one quarter of major energy policy on such an assumption is reckless and gives no consideration to the critical issue of grid reliability.

Comment 21 : Commenters stated that the CPP goal s may not be achievable due to the lack of in

- state NGCC or lack of demand for in

- state NGCC at 70% of nameplate capacity year

- round and provided state

- specific information.

Response 21 : The EPA disagrees with the interpretation of the 111(d) final rule . 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 stan dards 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, addition al 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 circumstanc es as they develop their plans, including system reliability, fuel diversity, the need139 for ancillary services 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 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 West Virginia to increase the dispatch of NGCC, given absence of NGCC units. Commenters st ated 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, therefore, no Building Block 2 CO2 reductions are possible in West Virginia. Co mmenters stated that all affected EGUs within the state are existing coal

- fired steam EGUs, or simple cycle natural gas

- fired peaker units that are not defined as affected sources under the proposed rule.

Commenters stated that, since North Dakota does no t have any gas

- fired plants, they cannot re

dispatch. Commenters added that in South Dakota there is one coal and one gas plant which are separate entities and not members of the same regional transmission organizations and that re

dispatching 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 Dakota and are charged for it in their rates.

Commenters stated that, as a small public power wholesale electric generation and transmission provider, Platte River's resource portfolio does not include NGCC and, consequently, Platte River and many similarly situated public power providers will be rel iant on the availability and willingness of other generation providers with existing 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 li kely result 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 York to operate at 70% of nameplate capacity
year

- round, which is anticipa ted by the application of this building block to New York. Commenters provided Table 2, Capacity Analysis, showing New York State's monthly NGCC load compared to 70% of its monthly nameplate capacity, and noted there were eight months in which total fossil load is less than 70% of NGCC generation capacity. Commenters stated that in those eight months, fully re

- dispatching all oil/gas and coal generation to NGCC would leave the NGCC units operating at less than 70% of load; in March 2012, for example, 74 % o f fossil generation was from NGCC, yet it only represented up to 38% of EPA's nameplate capacity. Commenters also noted that Table 2 demonstrates that total fossil load in each of the four months from June to September exceeds 70% of EPA's NGCC capacity; i n those four months alone, re

dispatching coal and oil/gas steam generation to NGCC 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 reliability rules and transmission limitations, the only way to re

- dispatch existing coal and oil/gas generation 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 that 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 elect ricity 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 flawe d assumption that utilities and states may meet the targets by

re

- dispatching existing NGCC to off

- set coal. Commenters 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 sufficient NGCC capacity to offset its emissions from coal

- fired facilities in the same state. Commenters stated that the owners of the affected EGUs are not the owners of available NGCC units. Commenters stated th at, while MRES is a

co

- owner of LRS, located near Wheatland, Wyoming, MRES does not own any NGCC in Wyoming to offset its emissions or otherwise decrease the run

- time of LRS. Commenters stated that, not only does MRES not own any NGCC in Wyoming, 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. Commen ters 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, there 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 as proposed, since there are currently no natural gas combined cycle units subject to the proposed rule operating in Kansas.

Comment 22 : Commenters objected to the use of a single capacit y 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 ; some commenters suggested use of a 3

- year average

. Response 22 : The EPA disagrees with the interpretation of the 111(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 flexibility as to how they structure those plans to

ac hieve 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 em ission rate achievement between performance periods. The Building Blocks are not prescriptive, and states may consider local circumstances as they develop their plans, including system reliability, fuel diversity, other regulatory requirements and infrastr ucture. 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 fin al rule preamble of the CPP and Chapter 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 intermediate load and o thers are designed as peaking units. Commenters stated these varying purposes reflect how a utility integrates its various generating resources to provide a reliable and stable source of electricity.

Commenters requested that the BSER guidance regarding N GCC capacity factors not exceed historic highs experienced on a state specific basis. Commenters stated that, in Michigan's case, this is no greater than a 42% capacity factor; commenters estimated that this revision would add 137 lbs CO2 per MWh to the pr oposed Michigan standard. 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 support the proposed average dispatch rate of 70% when gas prices have since increased and are projected to slowly increase for the foreseeable future.

Commenters stated that unit

- specific factors uniquely influence the potential amount of increased utilization that may be achievable by an individual unit. Co mmenters questioned why the EPA gave no consideration to these unit

- specific variables, stating that the Agency has previously acknowledged and analyzed such differences in support of the Section 111(b) proposal (listing such variables and citing the Combu stion Turbine Standard TSD pp. 1

- 4). Commenters noted that this EPA study identified a number of differences among NGCC units commissioned from 2000 to 2010, and added that these differences become even more pervasive when considered across the entire flee t, which encompasses units commissioned from 1949 through 2014. According to the commenters, these units represent a wide spectrum of process designs, business models, regulatory requirements and operating conditions that collectively and uniquely influenc e the potential future performance of each individual unit. Commenters listed the following factors that contribute to these differences: variations between combustion turbine manufacturers and suppliers; variations in the vintage 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 turbine design; differences in equipment redundancy to support increased utilization; differences in the winterization of equipment to enable cold weather operations; differences in the condition of process equipment to support increased utilization.

Commenters also sta ted that the EPA ignores the fact 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 language from the air permits for two NGCC fa cilities in Arkansas (which indicates that the units are intended for intermediate or peak load conditions) and historical data from the units (which shows that they both have operated at very low capacity factors

- as they were designed and intended to op erate

- for various technical and economic reasons). Commenters stated that it is ironic 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 sources (citing 79 Fed. Reg. 1445 and 1459). Commenters went on to state that for those units that are not designed to readily increase utilization or that may not have historically operated at higher capacity factors, EPA references in t he proposed CPP a 2011 paper to suggest that increased 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 schedu led outages; (2) efficient scheduled outage management with emphasis on quality; (3) proactive intervention with remote monitoring technology and (4) improved design and upgrades for longer parts life". Commenters asserted that the EPA provides no evaluati on to assess whether this "approach for achieving higher availability and reliability" has been or even could be implemented across the entire NGCC fleet, and that the EPA fails to examine how any of the aforementioned unit

- specific criteria may lessen the potential for existing units to increase operations in the future. Commenters noted that the EPA did recognize and account for some of these factors in the 111(b) proposal for new sources by proposing separate 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 demonstrated that it is feasible to establish a single capacity factor goal that can adequately account for and ad dress unit

- specific factors that affect the potential for increased utilization, whether that capacity factor is set at 65% or 70%. Commenters asserted that aside from deferring to the lowest common denominator capacity factor that could potentially be ach ieved by an individual unit, it is not possible to determine a single goal that could be achieved by all units, and that given the inherent differences that determine a unit's potential for increased utilization, 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 designed 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. Commenters cited a November 2014 Energy Ventures Analysis and stated that many NGCC units were not constructed for base load operations and could require significant evaluation and upgrades to enable them to operate continuously a t a 70 percent or greater capacity factor on an annual basis. Commenters cited UARG comments (Section XV.B) and stated that some units were financed, designed, and maintained for the specific purpose of operating in cycling duty rather than as base load an d, thus, many of these units would not be able to achieve the target utilization rate without significant upgrades and testing to ensure that they are physically capable of operating near full load on a continuous annual basis.

Commenters stated the EPA f ailed to consider the unit

- 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. Commenters stated the EPA failed to give adequate considera tion to potential infrastructure challenges from significantly increasing NGCC utilization.

Commenters stated the EPA's assumptions regarding capability of the existing NGCC fleet fail to consider the unit by unit variations of the fleet. Commenters state d 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 Midwest are considered intermediate resources with much lower capacity factors. Co mmenters 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. Commenters 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 frequent 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 achievable and adequately demonstrated is flawed because the EPA confuses unit

- level NGCC capabilities with the capabilities of state

- wide or natio n

- 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. Com menters stated that, for example, increasing 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 balancing authority, RTO, o r even grid). Commenters suggested the EPA reconsider its assumption that all states will be able to achieve a NGCC capacity factor average of 70% and take into consideration 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 than 70% for NGCC units. Commenters stated the appropriate rate sho uld be determined on a state

- by

- state basis that takes into account the type of turbines in use and restrictions on their hours of operation, the adequacy of the state's transmission grid, and the availability of firm natural gas service to allow for incre ased operations at the NGCC units. Commenters stated the EPA designed this building block without considering the availability of infrastructure (both with respect to natural gas supplies and electric transmission), operational constraints based on criteri a pollutant emissions, or the type of technology used in the existing NGCC fleet to determine whether that level of re

- dispatch is possible for a state. Commenters stated that LPPC members 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 aeroderivative

- design combustion turbines (instead of heavier

- duty, industrial class designs) are not capable of operating at a 70% capacity factor and that s everal LPPC members report that their states have existing NGCC units of this type.

Commenters stated that, at a minimum, the EPA should set a NGCC capacity factor for building block 2 on a state

- by

- state basis using a three

- year 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 t he 70% capacity factor. Commenters stated that EPA should then test the viability of the resulting three

- year average capacity factor by considering the worst

- case conditions that may occur in each state. Commenters stated these conditions, should, at a mi nimum, account for peak natural gas use by all sectors (residential, commercial, vehicle, etc.), natural gas transmission and storage constraints, and peak electric reliability needs. Commenters suggested that any capacity factor also be evaluated for offs etting interactions with other building blocks. Commenters stated this approach would ensure each state

- specific capacity factor could support system demand over the long

- term, including periods of extreme demand (e.g., polar vortex events). Commenters sta ted 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 constrained state (i.e., the state with the lowest historic 3

- yea r average capacity factor). Commenters 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 fac ility 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 performance improvements. Commenters stated that in EPA's Regulatory Impacts Analysis (RIA) the conclusion is made that the NGCC fleet will only reach CF of 50

- 57 percent, not the 70 percent utilization 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 amount of NGCC dispatch based on generic information as done in Building Block 2, the EPA should defer to the states in determining the degree of NGCC re

- dispatch that is feasible, taking into considera tion state

- specific variables, including plant ownership considerations, air permit limitations, remaining useful life, electric transmission capacity, load pockets, gas availability, location and actual capacity of the NGCCs (including climatic and altitu de considerations), commercial limitations, contractual restrictions, pipeline capacity, transmission capacity, actual heat rates, and other issues. Commenters said that states are in a much better position than EPA to determine 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 is 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 coal

- fired EGUs taking into account numerous factors, including, tra nsmission constraints, 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 existi ng NGCCs, environmental constraints (such as permit limits due to proximity to non

attainment areas), national security risks, and market limitations.

Need to consider the maintenance outages and the equipment availability factor.145 Commenters expressed con cern that there will be periods when the NGCC units will be off

- line for scheduled maintenance outages, as well as instances of forced outages of unpredictable duration. Commenters stated that, while the data demonstrate that it is feasible for Smith 4 and 5, and Buck to operate at capacity factors of 70%, they cannot operate exclusively in this manner. Commenters stated, for example, the equivalent availability factors (EAF) for North Carolina's operating NGCC units for calendar year 2013 25 ranged from 87 .88% to 93.29%, meaning that on average, during calendar

- year 2013, the NGCC units 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 perio ds of partial 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 les s than EAF for the same period. Commenters stated that, as the NGCC units age, they likely will be subject to even more scheduled maintenance and forced outage conditions, driving their EAF, and thus capacity factor, lower. Commenters also noted the histor ical 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 wit h their excellent heat rates (~7,000 Btu/kWh).

Commenters stated that, because NGCCs are complex mechanical systems that malfunction even under the best of readiness and preventive maintenance programs, the EPA must consider both unit availability and the increased potential for outage 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

- simplified the potential for re

- di spatch. Commenters stated that limitations such as the location of each plant in the electric grid and plant position vis

- a

- vis nodes and load must be considered. Commenters stated these locational limitations matter as much as unit size or technical capab ilities. Commenters stated, for example, some NGCC units that theoretically could run at higher 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 natural 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 units, as (I) that large of a block of power doe sn'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 support 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. Commenters stated both NGCC units are "two

- on

ones," that is, two simple cycle natural gas turbines 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 cycle mode in the off

- peak, winter months, both have the ability to operate using one of the two gas turbines depending on demand, and both have operating c apacity factors that range from 45 to 60%. Commenters stated the > 200 MW block is at times too large to manage the changes in 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., cool evenings and hot afternoons typical of our desert climate) and/or seasonal changes (turn off CC in wintertime). Commenters stated that EPEC is unique in its location at the southwest corner of WECC, and in satisfying reliability criteria including managing frequency, regulating voltage, and meeting our reserve obligation. Commenters stated that, depe nding on various circumstances, NGCC is not optimal/economic dispatch. Commenters stated that, because these units 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% ca pacity requirement is not demonstrated.

Commenters alleged that the EPA has failed to adequately demonstrate that a minimum 70% capacity factor requirement has been achieved by any existing NGCC unit. Commenters stated that based on c ommenters’ survey of o ver 300 air permits 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 o bligation for an existing NGCC unit that 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 factors at or above a 70% capaci ty 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 achievable across the range of operating, outage, and market conditions experienced over the life of a unit.

Comment 23 : Commenters disagreed with the EPA's use of a national average capacity factor to claim that a 70 percent annual capacity factor is an 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 capacity factor . The 111(d) final rule requires that states develop plans that establish emission standards for a ffected 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 bef ore 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 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 fa ctor 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 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 nationwide NGCC capacity factor during peak hours of the day averages 11 percentage points higher than the ov erall 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 percentage points higher than the 2012 national average capacity factor of 45. 8 percent) . Commenters asserted that the EPA did not explain why it believes it is reasonable to expect that the current 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 concerning its entire justification for Building Block 2 in that the Agency cites different values for this analysis in the preamble than in the GHG Abatement Measures TSD. According to the commenters, in the preamble the EPA claims that national average capacity factors are "60 percent 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 Abatemen t Measures TSD that national average capacity factors are "approximately 50%" during peak hours, and that these 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 match 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 potential constraints.

Commenters stated the assumption th at NGCC units can consistently achieve a 70% capacity factor requires evidence that has not been demonstrated by the EPA or any other entity. Commenters stated that SMEPA owns a significant amount of NGCC capacity, but has never economically achieved more than a 32% capacity factor and that was in 2012, when natural gas prices were at a 10 year low. Commenters stated this is due to a number of factors, including forced outages, planned outages, and economics. Commenters 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 several NGCC units in Mississippi that are mothballed or have never dispatched due to transmission or other limitations. Comm enters stated the EPA should investigate each NGCC plant to verify 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 differences in both existing and potential new infrastructure. Commenters stated that, since not all states or regions h ave a 60% NGCC utilization rate during constraints or otherwise, the EPA's conclusion appears to incorrectly assume that in all instances the infrastructure exists to allow natural gas plants to meet the 70% utilization rate.

Commenters stated that, in som e areas, NGCCs with the 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 Comm enters stated that in January through October 2014, for Entergy units, the average NGCC capacity factor was 57.7%, and the average coal plant capacity factor was 71.1%. Commenters stated this demonstrates that, for these units, the national average does no t apply. Commenters stated that two problems arise in this situation from EPA's reliance on Building Block 2: (1) there may be less delta in current and future (up to 70%) capacity factor that should be factored into Building Block 2 and (2) if an NGCC un it already is being used at a high

- capacity factor, such as for load following or even baseload generation, the unit's flexibility to take on additional generation responsibilities within the system likely is limited.

Need to account for seasonal and regi onal differences.

Commenters stated the EPA's assumption that coal fired generation can be re

- dispatched to NGCC up to a 70% capacity factor fails to account for season and regional differences in dispatch of natural gas. Commenters stated that the EPA's a ssumption 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 avai lable capacity at existing NGCC EGU's to allow for seasonal variations in load demands. Commenters stated that Nevada has considerable installed NGCC generating capacity (over 5 GW) located in southern Nevada and, during summer months load demands in these areas may be double that of winter. 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 coal generation. Commenters stated that, bec ause of the limited generation in northern Nevada, 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 ou tstrip available supply. Commenters stated that achieving such a dramatic shift in generation and transmission of power would disrupt the operation of the electric grid, particularly in northern Nevada where most NvMA members operate.

Commenters stated th at, 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. Commenters provided a Chart showing th e 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 sev enty percent in four of the 12 months. Commenters stated that, because these months which coincided with peak load levels, these plants were necessary to ensure system reliability and were not surplus to the system and able to stand in for other plants; i. e., they would not be available to replace reduced coal

fired output during peak load periods. Commenters stated 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. Commenters 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 only lead to increased car bon emissions, not to mention difficulties in transmission capacity, a problem already experienced with increased regional wind generation in the spring.

Capacity targets should be based on state

- specific information.149 Commenter s 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 setting South Carolina's em issions reduction target over

- estimates the ability of South Carolina utilities to increase the capacity factor at existing NGCC units currently on their system. Commenters stated the four NGCC units controlled by South Carolina utilities actually performe d at an average capacity factor of 65% in 2012. Commenters stated that, if South Carolina could 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 factor to reflect the true capacity factor in South Carolina. Commenters stated that, for example, a 550 MW natural gas combined

- cycle (N GCC) with Duct Firing plant, (does not include Heating Steam output to Industrial Customer of approximately 95 MWs), owned by EPHOS Energy (formerly Columbia Energy), and operated by LSP, located in South Carolina, operated at less than a 1% capacity facto r in 2012. Commenters requested the EPA provide an explanation for how it determined the available capacity factors of natural gas units in South Carolina.

Commenters stated it is not appropriate to apply nation

- 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% capacity factor, which allows the Proposal to push existing generation to these new units (http://ampd.epa.gov/ampd/). Commenters s tated the justification that new NGCC only operate at 55% capacity factor under business as usual is based on a nation

- wide review of the typical capacity factor from all NGCC that began operating within the last 5 years. Commenters provided a table 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 little, 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 90th 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 pipeline 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 a nnual average peak hours across the entire nation. Commenters stated this is not a "peak" with which would define a capacity constraint of a pipeline. Commenters stated that, if EPA's assessment were correct, there would not have been curtailment as recent ly as 2014. Commenters added that since Florida's two gas pipelines have little to no access to storage, Florida is more susceptible to peak demand challenges than other areas of the country.

Comment 24 : Commenter s described its exploration of the hypothesis 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 analysis 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 requires that states develop plans that establish emission standards for affected EGUs. We are providing states with subs tantial 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 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 reliability, fuel diversity, permitting, 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 calc ulations 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 pu blic comments under this comment:

Commenters investigated whether NGCC units located in ozone nonattainment areas may have taken run restrictions or tonnage limitations in order 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, on ly two contained permit restrictions that might constrain its availability to run for re

- dispatch at below an 70 percent annual utilization factor and installation of NOx controls would allow both of them to run at utilization factor greater than 70 percen t. The commenters concluded that the examination of available 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

- dispatch 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 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. T he 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 reliability, fuel diversity, permitting and other regulatory requirements. The 111(d) final rule does n ot 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 Chap ter 3 of the GHG Mitigation Measures TSD for the CPP Final Rule 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 capacity to 70% would, in many cases, re quire units to undergo re

- permitting by state regulators, a process which can take years. Commenters recommended that reforming and streamlining the permitting process for utility facilities could improve the possibility of at least reaching the final 2030 goal. Commenters stated that the EPA's NGCC re

- dispatch analysis should account for NGCC permit limitations on operating hours, total emissions and incremental consumption, as well as operation limitations driven by ozone nonattainment concerns. Commenter s 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 impossibility. Commenters stated there may be operational cons traints that would limit the capacity factor of existing NGCC units due to air permit requirements that were written to cap emissions of NOx or carbon monoxide in ozone nonattainment areas.

Commenters gave the following examples of constraining permit lim itations:

• EPA assumed that Afton Generating Station in New Mexico 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 operation of the duct burner for 1,920 hours per year, or less than 22 percent of the time. The generating capability of the unrestricted portion of the facility (i.e., without the duct burner) is 337,260 MWhr short of EPA's expectation for Afton. For the duct burner to make up that difference , based on the 60 MW capacity of the burner indicated in the Afton permit, the burner must operate for at least 5,621 hours, which is nearly three times the level that the Afton permit authorizes. Conversely, if the duct burner operated for the hours the p ermit authorizes, the unrestricted portion of the facility would be required to operate at a 81 percent 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 Jackson 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 and 12

- month rolling NOx emission limits, such that high capacity factors (utilization rates) would result in annual NOx emissions above their annual limits. Consumers Energy, which has a contract to purchase the facility, undertook an internal analysis and examined the 2012 high utilization period (May to August), concluding 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 capac ity factor, and Arapahoe is limited to 30% annual capacity factor.152 • Commenters stated that many existing NGCC units, such as Tri

- State Generation and Transmission Association's J.M. Shafer Generating Station (272 MW) and Arkansas Electric Cooperative Corpo ration's (AECC) Harry L. Oswald (548 MW) Generating Station and Thomas B. Fitzhugh Generating Station (165 MW) facilities, have operating permit mass emission limits and/or fuel usage limits, effectively capping their maximum possible operations below a 70 % capacity factor.

• Commenters stated that many NGCC units in Southern California are prohibited from increasing their capacity by both state and federal environmental rules and policies. Commenters stated that, because units located in the South Coast Ai r Quality Management District (SCAQMD) must obtain and surrender Regional Clean Air Incentives Market (RECLAIM) credits to cover all of their nitrogen oxides emissions, consequently, these units may be prevented from increasing their capacity factor signif icantly due to the limited amount of RECLAIM credits available. Commenters noted that the SCAQMD recently proposed an additional reduction in RECLAIM credits that could further restrict NGCC units in the air district from increasing their utilization to re place lost coal

- fired generation. Commenters stated that the EPA should individually evaluate NGCC EGUs to determine if they are located in areas that will limit their operation, and account for this when establishing goals for states.

• In addition to loca l electrical grid constraints such as transmission, local environmental regulations may already be in place that would conflict with increased operation at NGCC units, Commenters stated that, for example, system owners in the Houston

- Galveston

- Brazoria (HG B) eight

- hour ozone nonattainment area whose system is comprised mostly or entirely of NGCC units, may not have sufficient operational flexibility under 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 non

attainment for a NAAQS, and as a result would likely have operating permits imposing mass limits on carbon monoxide ("CO") or NOx emissions that would effectively establish a cap on those units' operations. Marchetti Report at 26.

• Commenters stated that increasing NGCC generating capacity in the West could lead to conflicts with ozone at tainment plans and unit

- specific run

- time limitations that are contained in many NGCC operating permits. Commenters stated that units in ozone non

- attainment areas throughout California and neighboring states, and units with permit

- level run

- time restricti ons will likely be unable to increase utilization to levels approaching 70%. Commenters stated that, even if NGCC units are able to increase their utilization in these areas without violating environmental laws and regulations, the increase in generation c ould exacerbate ozone or particulate matter problems in some non

- attainment areas. Commenters noted that studies by WECC and others could reveal additional constraints related to water or drought impacts in the West, or the need for significant additional pipeline and transmission capacity. The EPA should153 individually evaluate NGCC EGUs to determine if they are located in areas that will limit their operation, and account for this when establishing goals for states.

• Commenters stated that increasing NGCC generating capacity in the West could lead to conflicts with ozone attainment plans and unit

- specific run

- time limitations that are contained in NGCC permits. Commenters stated the EPA should identify how to address these broader and state

- specific constr aints in developing and testing its assumptions about re

- dispatch 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 NOx emission credit allocations from affected sources. Commenters stated that, depending on how the reductions are allocated, the capacity factors of EGUs in the SCAQMD may be specifically limited.

• Commenters stated the EPA must ensu re that block two targets do not interfere with the ability of Utah to protect its air sheds and address existing and future air quality regulations. Commenters stated the EPA fails to properly account for the efficiency penalties caused by NGCC emission r educing technologies; for example, some of Utah's NGCC plants include selective catalytic reduction (SCR) for NOx emissions control, which can further reduce plant efficiency.

• Commenters stated that since NSR permitting may limit a unit's operation, the E PA estimate of re

- dispatch to certain facilities is greatly overestimated. Commenters stated that, unless NGCC facilities are already permitted at 70% capacity or more, re

- dispatching could cause a facility's increased usage to trigger new source review ( NSR), making this option either infeasible or very costly. Commenters noted that, for example, Afton Generating Station is permitted to operate only 1,920 hours per year with its duct burner, yet EPA assumed full nameplate capacity using duct burners to de termine the amount of re

- dispatch to this facility under Building Block 2. Commenters stated that, for this assumption to be a possibility, the facility would need to undergo NSR permitting in order to fully utilize the duct burners and that NSR permitting would require the evaluation of additional impacts to the air shed, additional emission controls which lower the unit's efficiency, and increased operating costs.

• Commenters stated the EPA's assumption that existing NGCC units can be operated at a 70 per cent capacity factor ignores permitting 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 there are environmental controls that could be installed to increase the capacity factor, those costs would be additive to the all of the other compliance costs associated 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 and if each unit is operated at its154 average hourly NOx emission rate, the facility would be limited to a maximum annual capacity factor of about 60%. Commenters stated that AECC's Thomas B. Fitzhugh Generating Station's air permit lists a natural gas usage limit of 9.626 billion cubic feet based on a twelve

- month rolling average which limits the plant
t o a maximum annual capacity factor of about 63%.

• Commenters suggested that EPA should evaluate existing permit limits or determine how existing requirements may limit the feasibility of NGCC units to achieve increased utilization rates. Commenters stated that a variety of air permit requirements are in place that provide operational flexibility or that restrict operations, which may significantly impact the amount of potential re

- dispatch that may be available for certain units. Commenters provided an exam ple permit condition from an NGCC facility in Rhode Island which describes various conditions where natural gas shall be deemed unavailable in which case the permittee is allowed to utilize fuel oil, with sulfur content of 0.05 percent or less by weight, a s replacement fuel. Commenters also provided several general examples, including NGCC units that are permitted to combust fuel oil and natural gas; to co

- fire other fuels with natural gas (oil, landfill gas, coal gas, etc.); with conditions that limit natu ral gas use, which effectively limits the potential capacity factor that is achievable; to operate in simple

- cycle or combined cycle mode; and to operate the steam turbine with steam that is comingled from sources that are separate from the HRSG.

• Commenters stated that, because existing permit conditions do not allow some units to sufficiently increase operation, the 70 percent target is likely not achievable for the category as a whole. Commenters explained that permit conditions at J.M. Shafer wo uld limit it to an annual capacity factor less than 55 percent and Rifle would be limited to an annual capacity factor less than 25 percent. Commenters stated that, in practice, these facilities' capacity factors would likely be much lower since J.M. Shafe r and Rifle are subject to other limits in their Title V permits on annual emissions, as well as other permit limits on water discharge and operational constraints such as natural gas pipeline capacity. Commenters stated that, although the EPA did not addr ess this issue in the Proposal, the same barriers likely exist for many other 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 shoul d not presume that all NGCC units in any given state can achieve the Block 2 targets due to (1) air permit limits that restrict them from operating, lack of gas infrastructure, or lack of firm gas supply. Commenters noted that Colorado NGCC Plant Brush 1

- 3 is limited by its air permits to 37% annual 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 o f NOx emission limits may depend on whether 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 Colorado that have fuel throughput limits that would restrict re

- dispatch.

Commenters stated that, under the current air permit, the Holland facility could not make a target of 70 percent capacity factor without triggering NSR. Commenters stated that Holland's Net Maximum Capacity as reported co ntains a significant portion of duct burner MW hours which are limited by the air permit to 1500 hours per year. Commenters stated this limitation roughly equates to a maximum of 55 percent capacity factor for the Holland facility. Commenters stated the pe rmit cannot be modified to remove the 1500 hour 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 air perm its they have for their natural gas

combined cycle plants are limited to a 20

- percent capacity. The commenters asserted that, although a 70 percent capacity factor for combined cycle plants may be technically possible, permitting, transmission constraints and higher maintenance costs in the energy demand all affect the plants ability to run.

Commenters stated the EPA's determination that NGCCs 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 level. Comment ers 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 stated that requiring states to meet a goal premised on these entities overcoming permitting restrictions based on public safety and reliability concerns is not "reasonably reliable" or "reasonably efficient." Commenters stated that, in states such as Illinois, where the respective 2012 utilization rates were 26% and 27%, such a dramat ic 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 2 6 : The EPA disagree that analysi s of the 111(d) final rule did not consider this . The 111(d) final rule requires that states develop plans that establish 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 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 reliability, fuel diversity, N AAQS, 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, VII I.A, VIII.C and VIII.G of the final rule156 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 expre ssed concern that EPA's just announced proposed revision to the ozone NAAQS may preclude increased utilization of existing NGCC units.

Commenters pointed out that existing NGCC units are usually licensed to operate at full load continuously; however, a sig nificant change in ozone standards could result in a request to conduct additional Air Dispersion Modeling to address the higher NOx resulting from related operational changes such as ramping. Commenters indicated that it is difficult to anticipate the imp act of a revised ozone standard on existing coal or natural

- gas fired units without running air dispersion modeling for each location, and that results will vary depending on topography and proximity to other sources such as factories and roads. Commenters asserted that the EPA did not appear to take into account possible increases in NOx 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 s tates with sufficient time to go through all of the steps required to conduct the new Air Dispersion Modeling runs needed to verify attainment of existing NAAQS. Commenters indicated that the EPA apparently presumes that all or most existing NGCC units tha t would need to be re

- dispatched to a higher capacity factor to meet building block 2 would immediately pass the Air Dispersion Modeling tests. Commenters stated that the Agency didn't take into account the impact of complying with revised NAAQS under a re

dispatch scenario. Commenters added that the EPA did not consider the time needed to acquire revised Prevention of Significant Deterioration (PSD) permits for existing units when it set the interim and final compliance dates in the Proposed Rule. Commente rs stated that had EPA done so, it would have realized that more time will likely 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 background ambient NO2 levels will be determined by monitors placed near highways, there is a concern that they will be found in non

compliance because the monitors cannot separate the NGCC unit emissions from the emissions attributable to motor vehicles. Commenters warned that this could result in urban areas falling into nonattainment

- if an existing NGCC unit is sited in a newly designated NOx nonattainment area, emission offsets and/or use of some sort of control equipment not currently envisioned, or a higher stack, may be required. Commenters asserted that those costs or possible ozone precursor limitations of replacing existi ng coal plants with new NGCC units are not considered in the Proposal. Commenters added that the EPA's state plan 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 power generation to re

- dispatch to NGCCs in Maricopa County would increase emissions in our existing nonattainment areas and make achieving and maintaining existing and new, more stringent NAAQS even more difficult.157 Comment 2 7 : Commenters expressed concern that certain actions to achieve the CPP goals may trigger NSR.

Response 2 7 : The E PA disagrees. The Rule does not require states to take particular measures and provides flexibility, including trading and more time, to states to consider reliability and local circumstances, such as other environmental issues and permits. The Building Bl ock 2 provision is used to estimate an average annual capacity 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, V III.C, and VIII.G, of the final rule preamble 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 expressed concern that the change in operation to a higher capacity could invite NSR enforcement. Commenters stated that, in some cases, 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 eliminating 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 that eliminating the PSD analyses for re

permitting of natural gas peaker units like CWLP's Interstate turbine, a simple cycle natural gas (NG) unit, would facilitate greater dispatch of natural 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 consider eliminating the PSD/BACT permitting requirement for existing NG units like CWLP's, at least in the short

- term, until such time as NGCC units, and the concomitant transp ortation network necessary, reach the expected increase the EPA has set for Illinois in the GHG Rule. Commenters stated CWLP's Interstate turbine is currently not an affected unit under the GHG Rule because of low utilization, a peaker unit as defined at 4 0 CFR 72.2 and it is permitted as a synthetic 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 win ter'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 Interstate natural gas turbine would be limited by rule and permit. Commenters stated that, in the absen ce of any permit conditions, Interstate would be above major source levels and, thus, removing the operational limit would require a Best Available Control Technology (BACT) analyses for each pollutant (which may include CO2, as well) required as part of t he Prevention of Significant Deterioration (PSD) permit process. Commenters stated CWLP would need to contract for air modeling to demonstrate that the increase in emission for each pollutant would not impact the national ambient air quality standards (NAA QS) and noted a PSD permit can take many months if not years to be issued, and may contain stipulations on new emission rates and possibly new control devices, too.158 Comment 2 8 : Commenter s stated the EPA must consider oil

- firing backup.

Response 2 8 : The Rule does not require states to take particular measures and provides flexibility, including trading and more time, to states to consider reliability and local circumstances, such as backup fuel. The Building Block 2 provision is used to estimate an
averag e annual capacity factor for the purpose of establishing 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 preamble 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 no t a pipeline interruption, does not fully capture 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 Florida have oil backup cap abilities, and are permitted as such, due to Florida's unique energy profile, which is currently entirely dependent on only 2 natural gas pipelines bringing gas into the state. Commenters noted that Florida has no coal mines, no significant oil refineries, and no significant 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 planning should a natural disaster strike the state, such as a hurricane. Commenters stated that stations 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 2 9 : Commenters expressed concern that the re

- dispatch of NGCC in Building Block 2 will eliminate NGCC as a source for providing necessary flexibility to the electric system, including the ability to support renewable energy.

Response 2 9 : 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, 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 reliability, fuel diversity, other regulatory requirements and infrastructure. The 111(d) final rule does not require every individual NGCC to m eet 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 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:159 NGCC needed to support renewable energy.

Commenters stated that, to avoid undermining integration 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 analysis must further consider the need for NGCC availability to support existing renewable energy and the renewable energy the Proposed Rule urges be constructed. Commenters indicated that NGCC 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 to the commenters, gas

- fired power plants are best suited to support variable RE given their quick start

- up times and high ramping capabilities. Commenters asserted that by failing to consider that much of the NGCC generation the EPA presumes available for re

- dispatch is or must be committed 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 level of emission reduction that is achievable by NGCC re

- dispatch, the EPA needs to consider the effect of changes in load following resources. Commenters stated that, under the CPP existing NGCC units will shift from load

- following to bas eload resources, however, the need for load

- following resources will not be eliminated as a result of the rule. Commenters stated the need for load

- following resources will likely increase due to the rise in renewable penetration assumed in Building Block 3. Commenters stated that, if NGCCs become baseload resources, their intermediate and load

following role will likely be taken up by a combination of coal units operating at reduced loads and/or simple cycle peaking units operating at increased capacity fa ctors. 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 purpose of CPG S (renewable energy backup) and incorrectly assumes that it can be preferentially 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 the 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 re

dispatch of up to 70% doe s not result in additional costs to the operators or rate payers, in fact, there would be additional costs associated with higher 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 resources are down, if it were required to operate at a high utilization level, it would no longer 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 transmission system, which would be a major obstacle to Deer Cre ek Station achieving a 70% utilization rate.160 Commenters stated that building block two is inconsistent with EPA's proposed block three, which is predicated on increased deployment of low

- carbon generation. Commenters stated that, while the Proposed Rule as sumes 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 sufficient quantities of dispatchable power to balance the intermittent supply of energy from RE. Commenters stated, however, the dispatchable balancing power is principally provided by lower

- capacity factor gas units, including NGCC units. Commenters stated that, if all NGCC units are deployed at r elatively high annual capacity factors, as block two assumes, these units will be unable to provide the necessary balancing services for the operation of the intermittent types of RE. Commenters concluded that blocks two and three thus place mutually incom patible expectations upon gas generation units, and EPA's failure to address these tensions is arbitrary and capricious.

Commenters stated the Proposed Rule's drive to increase natural gas consumption would have a negative effect on the expansion of renewa ble energy. Commenters noted the EPA finds that, in light of low natural gas prices, market forces alone 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 th is market effect by rewarding, as BSER, the increased utilization of natural forces to favor natural gas power generation. Commenters stated 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 EPA 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 capacit y factor will eliminate NGCC as a source for providing this flexibility. Commenters stated 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 pa tterns. Commenters stated that eliminating NGCC units from balancing and regulation due to the re

- dispatching of NGCC units to the equivalent of base load level capacity factors, forces this flexibility 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 NGCC units generally not be pushed to operate at a utilization beyond 70 percent. Commenters stated 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 increas ing expectations 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

res pond to renewable power supply fluctuations leaves very little flexibility and reserve capacity to ensure a reliable electrical supply for the citizens of Georgia.161 Commenters stated that most of the NGCC plants that provide electricity in Minnesota were b uilt for flexibility, either to provide power during peak periods of demand or to offset the intermittent production by wind generators. Commenters stated that, if those plants are instead used as baseload plants, the ability to provide peaking power or to chase wind could be lost.

Analysis needed to avoid several issues.

Commenters stated that, in the West North Central region where wind is the predominant source of renewable energy, those wind units are backed up by the existing NGCC plants. Commenters

s tated it will require overbuilding of NGCC to ensure 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 ut ilization of highly intermittent renewable resources of solar, wind and biomass per preferential 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 suppor t for the extensive 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 needs of the local electric grid. Commenters stated the fail ure on the part of the Proposed Rule to understand this fact will have serious consequences on the reliability of the electric system for our member communities.

Commenters expressed concern that the EPA's analysis did not address whether there will be suf ficient other generation units available to handle 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 relies on nuclear and coal

- fi red generation for base

- load with NGCC generation as a load

- following resource, the EPA's BB2 proposal envisions NGCC facilities transitioning into more of a base

- load role with coal

- fired generation assuming more of supplemental supply function. Commenter s 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 will need to be addressed with careful modeling and plann ing. Commenters noted the following issues:

Even with today's historically moderate to low natural gas pricing, not all NGCCs can compete in all markets based on bidding into competitive markets. Commenters noted that the EPA proposes that states will fix this situation by forcibly 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 resources thus leaving merchant plants as peakers. Assuming states follow the EPA's suggestion of tilting the market to an environmental dispatch, this will likely cause some increase in the price of electrici ty. A few units may be located in areas where the demand is insufficient to reach these 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 unle ss 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 ca pacity factor in favor of natural gas combined cycles. However with careful modeling and planning, even at a 70% capacity factor, there can be adequate head room for NGCCs to still provide significant backup to renewables depending on demand.

Flexible cap acity margin

Commenters stated the EPA must ensure grid operators have adequate flexible generating capacity to respond to the range of daily grid

- level 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 efficiency of NGCC, the NGCC generation assets have become cost competitive with coal facilities and have provided increasing levels of baseload generation. Commenters noted that, as renewable assets increasingly penetrate the grid, flexible capacity margin will also increase in importance. Commenters stated that, based on current technology, grid operators will use a combination of NGCC and high efficiency, highly flexible simple cycle gas turbine technologies to backstop renewables. Commenters stated that grid

- balancing resources should be flexible, reliable, 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 that, as states produce more electricity from renewable resources they will increasingly face difficulties posed by variable generation and relatively quick power fluctuations. Commenters state d it is essential the EPA recognize and account for necessary capacity margins when establishing the re

- dispatch target. Commenters suggested the various balancing authorities should identify the level of flexible capacity they require, and their future ca pacity needs. Commenters noted that a variety of balancing authorities, such as Independent System Operators (ISOs) and Regional Transmission Organizations (RTOs) have evaluated necessary capacity margins and identified the need for increased flexible gene rating assets. Commenters stated the CAISO net load chart highlights the future importance of flexible generation requirements in response to increased renewable generation.

Emissions impacted re

- dispatch.

Commenters stated that, even in California, wher e Building Block 2 plays a minor role in setting the state's goal, there are some specific constraints that may impact the performance of NGCC units. Commenters stated that, while California is working towards meeting the most aggressive renewable portfoli o standard in the country, the significant 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 startups, resulting in variable emissions. Commenters indicated that such units will not result in as much emission reduction as the EPA projects in BB2.

Commenters stated that, if NGCC plants become intermediate load resources, the load

- following and cycling role will likely be taken up by a combination of less efficient coal units operating at reduced loads and/or simple cycle peaking uni ts operating at increased capacity factors.163 Commenters stated the use of coal units in this capacity at low loads will practically eliminate any heat rate improvements made at those units because heat rate degrades at lower loads and with cyclical operatio ns. Commenters stated that simple cycle peaking units, many of which are permitted as minor sources, may not be able to increase their operations to meet demand because of permit limitations.

Commenters stated that many of these plants were built for flexi bility of generation sources within a region and, if they are instead base

- loaded, the change would deprive the region of the very flexibility for which the units were built. Commenters stated that taking away that flexibility could force the cycling of le ss flexible 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 flexible firming resources. Commenters suggested
t hat EPA recognize that utilities and regions rely on a diverse portfolio of generation resources to provide different services to the grid and that requiring all NGCC plants to operate at 70% of capacity puts that critical diversity in substantial peril. C ommenters 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 purpose 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 system to date.

Comment 30 : Commenters stated that, by focusing its achievability analysis for Building Block 2 on average annual capacity factors, the EPA failed to adequately consider periods of peak demand.

Response 30 : The EPA disagrees that we did not consider peak demand. 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 incl udes, 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 reliability, fuel diversity, the need for load following, system balancing, other regulatory requirements and infrastructu re. 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 r ule preamble of the CPP and Chapter 3 of the GHG Mitigation Measures TSD for the CPP Final Rule supporting the final CPP. GHG Mitigation Measures TSD for the CPP

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

Some commente rs stated that this is further complicated 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, many states have all their existing NGCC resources in use, along with all other resources, leaving no available NGCC generation available to replace existing coal and oil and gas (O/G) steam generation duri ng these periods.

Commenters asserted that, if EPA ramps the capacity up to 70 percent for their natural gas

combined cycle plants, their plants would not be available 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 stated the mandates for Arizona are burdensome, compliance is likely impossible, and the natural gas capacity in the state is not sufficient to provide air conditioning in the summer months.

Commenters stated that continued d isplacement of coal and nuclear baseload resources by historically peaking units, such as NGCC, will result in a shortage of capacity during peak periods, threatening future reliability.

Units with interruptible contracts may not support increased operatio n.
Commenters stated many units operate with interruptible contracts for gas supply that may not support increased operation during peak demand periods, 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 continuous basis to meet the proposed NGCC generation levels, particularly in peak periods. Commenters stated that th e availability of firm transportation capacity requires not only adequate natural gas supplies, but also adequately sized pipeline facilities to deliver the increased amounts of natural gas needed to supply increased NGCC generation at the points of use. C ommenters stated 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 comparable excess) capacity capability to allow for the necessary a djustments in a timely fashion. Commenters stated that, currently many NGCC units, which primarily serve as peaking units, do not have firm transportation and balancing services, but rely instead upon interruptible natural 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 capacity on many pipelines is already fully subscribed. Commenters stated a switch from interruptible to firm service would also increase a utility's costs because rates for firm service include a reservation charge that is fixed regardless of usage along with a u sage charge for gas actually transported, while the rate for interruptible service is a volumetric charge tied to usage. Commenters 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 goals.165 Commenters argued that, if EPA insists on including NGCC re

- dispatch in Minnesota's CPP target, EPA must consider the measures and costs that would be incurred to replace the intermittent renewable resource reliability, peak power generation resource service electric and natural gas transmission support that the NGCC units currently provide in addition to what EPA has recognized will be needed to bolster infrastructure to support EPA's 70% target set for existing NGCC units, annual capacity factor. Commenters reported that early action taken by Minnesota regulatory authorities through their integrated resource planning (IRP) process already optimizes generation resources to serve Minnesota electricity customers, giving balanced consideration to customer need, economics over the long term, fuel supplies costs and risks, socioeconomic impacts and managing risks and environmental stewardship, including CO2 emission environmental externalities. Commenters asserted that Minnesota's energy mix of dispatchable capacity from Minnesota's existing coal 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 all" 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 occur.

Commenters indicated that the EPA's analysis focused 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 ma ny gas units in Texas are designed to operate during times of peak load, given the large presence of nuclear, renewable, and coal

- fired base

- load generation that currently exists in the state. Commenters stated this is one of the reasons that the average

c apacity factor for NGCC units in the state is in the 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 perform at this level co nsistently and over the long time periods envisioned by EPA.

Need to consider extreme weather.

Commenters stated that, to the extent that displacing coal

- fired units with NGCC units causes the former to adopt a reduced or nonexistent operating profile, Bui lding Block 2 could leave utilities without the tools to respond to extreme weather conditions in the future. Commenters stated that extreme weather often causes significant increases in electricity demand at the same time natural gas supplies face unantic ipated constraints and noted that, during the early 2014 cold spell known as the "polar vortex," the vast majority of coal

- fired EGUs that were slated for retirement because of EPA's MATS Rule were operating at full capacity 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 subsequent ly retired or reduced 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 local or regional basis could be compromise d. Commenters stated NGCC units provide an important balancing function that allows utilities to incorporate large amounts of variable renewable resources; 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 and low RE production. Commenters referenced a NERC report and stated that, if NGCC utilization were to increase to the levels that the EPA assumes, the system could become even m ore vulnerable to periodic blackouts or curtailments during high

- demand, low

- variable

- supply scenarios. Commenters referenced another NERC report and stated that, increased reliance on natural gas could lead to periodic weather

- or natural disaster

- related reliability issues 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 sho uld consider alternative calculation methods that account for peak demand. Commenters cited the GHG Abatement Measures TSD at 3

- 15 and stated it is unclear how EPA thinks averaging flexibility could overcome the constraints imposed by peak demand, unless t he agency believes that coal and NGCC generation could switch roles, with NGCC providing base load and coal operating only when needed to satisfy peak load. Commenters referenced a NERC report and stated that operating coal generation to serve peak demand is not technically feasible. Commenters stated that, if that scenario were feasible, then the ability to average coal emissions over a year could provide partial assistance in meeting the BB2 goal, although it would not enable Arizona or the 11 other stat es 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. Commenter s stated that it is untrue that peak demand will constrain only a limited percentage of the state

- wide NGCC fleet. Commenters referred to Appendix 3 of their comments and stated that, in the absence of coal generation, existing NGCC generation in Arizona w ill be substantially inadequate to meet peak demand in Arizona during the summer months, even if operating at nearly 100 percent capacity. Commenters stated that the annual average capacity factor for the state's NGCC fleet does not provide an adequate pic ture 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 that it is inaccurat e for the EPA to assume that all merchant generating capacity will be available to displace coal

- fired generation from within a particular state. Commenters concluded that utilities cannot rely on merchant generation to meet long

- term demand requirements d uring peak summer months in lieu of generation from existing coal

- fired units.

Commenters stated the EPA application of Building Block 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 those utilities' coal fired generation even though167 those utilities do not own or have any long

- term rights to the capacity and energy from the merchant NGCC units. Commenters stated the EPA fails to recogni ze 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 would be available for use by Arizona utilities to serve load within the state (2012 EIA 860 data).

Commenters stated the EPA should remove any merchant NGCC units from Building Block 2 in the calculation of the state goal. Commenters stated that merchant NGCC units create several problematic issues for the State to resolve in developing 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 ach ieve a 70% capacity given the gas pipeline constraints? Where should the offsets occur? Can the merchant unit owner offset with its coal

- fired assets, if any, in other states? Should other in

- state utilities be forced to purchase the merchant unit NGCC
gen eration 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, whil e NGCC units owned by 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 Columbia Energy operated at less than 1% during 2012 due to a lac k of demand for its electric output. 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, since the merchant unit owner does n ot have coal

fired generation in its South Carolina portfolio, there is no opportunity for the owner to offset its generation within the State in the manner contemplated by EPA.

Commenters stated that it is not valid to assume that merchant capacity is ava ilable under a 111(d) program for re

- dispatch to solely serve Arizona load. Commenters stated that more than 5,000 MW (53%) of the existing NGCC capacity in Arizona 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, there is no ability by the load serving entities, the state, or EPA to force merchan t generators to continue 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 A rizona utilities will need to compete for natural gas supply for NGCC generation with shippers from California, New Mexico, and Texas. Commenters stated that recent increases in exports to Mexico raise additional concerns as to the feasibility of securing adequate natural gas supply in the near term.

Commenters stated that, given the uncertainty in availability of merchant resources to serve Arizona load, utilities will need to construct new NGCC plants to ensure adequate system reliability during peak de mand periods if existing coal and OG steam must be curtailed or retired under the 111(d) program. Commenters stated that new infrastructure will be needed to operate existing NGCC at the higher capacity factors assumed by EPA. Commenters stated that the tw o pipelines that provide service to SRP's gas plants have limited excess capacity available and are168 nearly fully subscribed in the winter months. Commenters stated that, if SRP were to operate its existing NGCC at a 70% capacity factor in the winter months , SRP would need an additional 160,000 decatherms (dth) per day of natural gas from the pipeline system. Commenters stated that existing winter capacity available for contracting currently ranges between 0 to 50,000 dth per day, far less than required by S RP.

State

- specific comments

Nevada

Commenters stated that, in assuming 70% capacity factor, the EPA failed to take into consideration actual capacity factors for affected EGUs as they are currently operating, as well as location, infrastructure availabilit y, reserve margin requirements, and other factors adding complexity to the analysis. Commenters stated the Nevada Agencies evaluated the existing natural gas

- fired EGUs capacity factors and existing infrastructure, and concluded that re

dispatching even 50 % (the amount the USEPA determined would be necessary to take Nevada's coal

- fired facilities offline) would be a significant challenge. Commenters stated that, even assuming that the EGUs could operate at a 100% capacity factor, the existing natural gas

- fi red 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 existing NGCC EGUs cou ld operate at a 70% capacity factor, the number of hours where re

- dispatch 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 available 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 design ed for re

- dispatch to a 70% annual capacity factor. Commenters stated the older gas fired units are maintained and used solely for peaking and short term reliability needs because they typically have a higher heat rate, perform at lower efficiencies, and a re 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 t he multiple strategies available to Nevada to comply with the Rule. Commenters stated that their internal analysis, which was shared with the Agencies, suggests that a modest re

- dispatch may be needed in the early years to comply with the interim 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 higher levels of renewables, and a bad investment in the long run.

Commenters stated that most gas

- fueled generation in 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 factors between 50% and 80% during winter and summer seasons may be valid, it does not necessarily take into consideration the ability of those units to run at such a level at an annual capacity factor, n or does the assessment address the169 availability of natural gas in all seasons or locations. Commenters stated the capacity factor of NV Energy's NGCC fleet exceeds 70% during the summer 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 1,000 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 b y the coal fleet to the NGCC fleet during 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 standards. Commenters stated this level of operation during a summer season that already experienc es frequent "do not touch" reliability mandates is not appropriate or sustainable. Commenters stated it is not reasonable to assume a complete displacement of the baseload coal which meets 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 plants in New Hampshire have been unable to perform to expectations during peak heating demand periods in recent winters. Commenters stated that, while natural gas g eneration 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 sequence 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 o ver the course of an entire year, especially during the winter months when 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 Ar izona.

Commenters expressed concern that the proposed re

- dispatch to Maricopa County NGCCs may consume peaking capacity that is currently necessary to meet summertime demand as well as consume electric system growth capacity more rapidly that infrastructur e planning can meet.

Commenters noted that the EPA suggested that the state's utilities could just operate coal

- fired generation during peak demand periods, but stated this is not a viable option. Commenters indicated that the coal

- fired power plants in Ar izona 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 wo uld not be economically justifiable. Commenters suggested that when calculating Arizona's emission goal, portions of coal and gas steam cannot be re

- dispatched to NGCC and must be factored into the carbon rate goal. Commenters 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 August 7th, hour 16, 2012, Arizona NGCCs were generating 8,455 MW (net) and the coal and gas steam units were g enerating 4,098170 MW (net). Commenters stated that, in order to re

- dispatch all coal and gas steam with NGCC generation as assumed by the EPA, the NGCCs would have to be operating at 12,553 MW (8,455 MW + 4,098 MW); however, the maximum capacity assuming all units are fully available, however, is only 9,305 MW. Commenters provided 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 (100% cap acity 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 capacity of all NGCC in Arizona. Commenters stated the same phenomenon occurs dur ing the months of May through October and, as a result, if all coal units were retired as modeled by the EPA, Arizona could face serious reliability issues in a significant number of hours throughout the year. Commenters also provided Table 2, which shows that nearly 800 hours throughout the year 2012 could not meet the NGCC re

- dispatch requirement envisioned by the EPA.

Commenters expressed concern that the EPA's assumptions 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 EPA's calculated capacity factor for the NGCC fleet in Arizona of 53%, NGCC generation would entirely displace coal and OG steam generation. Commenters objected to what they describe 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 that 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 obligati on to meet peak demand. Commenters stated that utilities must ensure that sufficient 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 deman d because those facilities are already being fully utilized in certain hours of the year to serve regional loads. Commenters stated that, currently, coal and OG steam plants provide vital capacity during summer months that ensures system reliability during periods of peak demand. Commenters 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 easily run at a 90% capacity factor duri ng the peak summer hours, but have an annual capacity factor 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

- peak months. Comment ers added that, while forecasted values trend well with actual values, utilities 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 provid ed Figure 7

- 4, Resources Needed by SRP to Meet Peak Demand on August 8, 2012, and stated that, during this hour, all available generation resources, including coal and OG steam plants, were being utilized at full capacity to meet that peak demand. Commente rs added that, even with all SRP system resources being utilized at full capacity, 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 meet the peak electricity demand without purchasing a significant amount of electricity from the short

- term market in addition to what is already being purchased, which is a costly and risky endeavor, as suming that such power is even available.

• Commenters stated that, while Figure 7

- 4 shows a single 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 factor on an hourly basis, which equates to 84% on an annual average basis, Figure 7

- 5 demonstrates SRP stil l would experience significant shortages in generation for several months in the summer. Commenters noted this lack of generation would be further aggravated if out

- of

- state coal resources also are eliminated due to compliance with the Proposed Rule.

• Comm enters provided Figure 7

- 6, Merchant NGCC Plant Utilization in Arizona, and stated that the merchant plants in Arizona often already operate at full or nearly full output during summer peak months to meet demand, even with the existing coal

- fired generatio n in operation. Commenters concluded that the Arizona utilities cannot rely on merchant generation in long

- term planning to meet system demand requirements during peak summer demand periods. Commenters added that regional peak demands have been increasing and are projected to continue to increase.

Commenters stated that, while the EPA seems to suggest 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 3 4887), 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 sufficient to implement Building Block 2, nor is sufficien t 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 stated that, to the extent th at 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 rights to that unused NGCC capacity in order to replace their own displaced coal

- fired generatio n

- making replacement generation exceedingly difficult to find for an entity like Tri

- State, which 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 replace the loss of Springerville Unit 3.

Commenters provided the following analysis by the Salt River Project (SRP) as an example which, ac cording 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 of 6,663 MW, in which all of its generation resources (including coal and O/G steam units) were being ut ilized at full capacity. Even then, SRP was forced to purchase power to meet its peak demand and its mandated reserve requirement. With coal and O/G steam units prohibited from operating for purposes of meeting the state's CO2 emission goal, as EPA's Inter im and Final Goals for Arizona require, 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 extraordinarily costly. The EPA failed to include such costs in its Regulatory Impact Analysis. This highlights another important factor that EPA failed to consider: the 5,000 MW of merchant NGCC located in Arizona. The state's various loa d serving entities purchase electricity from merchant generators on either long

- or short

- term agreements, but have no control over how the merchant units are dispatched. SRP found that all merchant plants in Arizona operate at or nearly at full output dur ing the peak months not only to meet the demand in Arizona, but also in neighboring states such as California, Nevada, and New Mexico. Consequently, Arizona utilities cannot rely on merchant generation to meet long

- term demand requirements during peak summ er months, and both coal and O/G steam capacity provide a vital resource to meet demand and ensure reliability. SRP also points out several factors that can complicate the construction of additional NGCC capacity: (1) lengthy timelines in siting and permit ting new energy 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 capacity is retired in 2020 it would affect both the reliability and load serving capability 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 believes that measure should better capture the units ’ ability to produce power on a sustainable basis. 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 Miti gation 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 firing. Commenters noted that all Wisconsin NGCC units have duct

- fired peaking capacity that generally comprises at least 10

- 20 percent of the total capacity of the units. Commenters stated the duct

- fired capacity has a sign ificantly higher173 incremental heat rate and emission rate than the unfired capacity, so the duct

- fired capacity has historically been operated fairly infrequently. Commenters stated that, in order to achieve a capacity factor of 70 percent, additional duct firing will likely be required at some units. Commenters recommended that, when determining the appropriate emission rate to use for re

dispatched NGCCs in calculating state goals, EPA consider the fact that re

- dispatched NGCCs operating under the assumpti ons 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 not be considered in assessment of NGCC capacity within the context of displac ing coal generation 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 throughput, but the point of heat addition in the thermodynamic c ycle 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 thermal stress in a unit's heat recovery ste am generator (HRSG) and this accelerated component wear is incurred only in exchange for premium power prices. Consequently, Commenters believe d that duct burners should be considered temporary operating modes and the incremental power derived should not b e 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 duct burner capacity that is included in Georgia's NGCC capacity used by the EPA in the Building Block 2 calculation. Commenters indicated that the generating capacity for th is 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 heat rate for this facility operating at steady state conditions. A ccording to the commenters, the desire by an owner to retain duct burner augmentation as a temporary mode is due to both a compromise in heat rate and the deferred cost of induced thermal stresses to the HRSG.

Commenters stated that, while NGCCs are equipp ed with 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 normal operation and it increases NOx emissions, which is particu larly important in meeting NOx emission 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 triggering duct

- firing or accounting fo r these impacts by setting less stringent targets.

Commenters stated the EPA could also consider simply excluding NGCC units located in non

attainment areas or, alternately, assuming additional costs for installing NOx control equipment.

Commenters state d that duct burners and the incremental power derived should not be considered in any discussion of the use of either nameplate or summer net generation to displace annual coal generation. Commenters stated that, since 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 pre mium power prices.174 Commenters stated the additional power output but compromised heat rate induced by duct burner firing can be significant; e.g., by including the duct burner capacity, the generating capacity for one facility was overstated by more than 2 0%. Commenters stated the heat rate for these duct burners is approximately 2,000 Btu/kWh higher than the net heat rate for the TASF when operating without duct burner firing. Commenters stated that duct burners have different operating characteristics tha n a NGCC and should not be considered in assessing the ability of existing NGCC capacity to displace coal generation.

Commenters stated the EPA did not distinguish between size of NGCC, industrial frame designs

vs. aero

- derivatives, or those facilities wit h supplemental 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 determining re

- dispatching), yet if not used in 2012, the impacts on po orer heat rate would not be captured in the emissions data. Commenters stated this is especially true for situations similar to what exists at Arvah B Hopkins. Commenters stated that, when the station repowered, the City utilized the existing steam turbine ; the steam turbine's generating capacity is greater than 50% of 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). Commente rs 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 state goals and adjust the required CO2 emissions rate or the nameplate capacity accordingly.

Comment 3 2 : Commenter s stated the EPA fails to consider a specific category of natural gas electric generating facility “ regulating units. ”

Response 3 2 : The EPA disagrees. The EPA has not ignored the role of simple cycle CT units in contributing to regulation. Many different types of units contribute to regulation. These units are not precluded from contributing system regulation 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 combustion turbines. Commenters stated that, unlike a peaking unit, a regulating unit must be able to start and ch ange load quickly because of variations in non

- dispatchable renewal energy generated in moderate

- sized electrical balancing authority areas. Commenters stated that, because large

- scale wind generation is non

dispatchable, it is very difficult for a regulat ing unit to predict when it may need to operate to balance drops in wind generation. In response to this variability, Commenters stated a regulating unit may be required to operate in hot standby, ready to respond in minutes to a drastic drop in renewable generation. Commenters stated the heat rate achieved while operating a combustion turbine in hot standby results in a disproportionately 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 constructed in 2011, recently disclosed that it would not meet the currently proposed efficiency

- based emission 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 demand at all times; therefore, a regulating unit may operate at a higher capacity factor than a typical peaking unit. Commenters expressed concern that the EPA's proposed 33 perc ent capacity factor to exclude peaking units from the NSPS may not be sufficient to also exclude regulating units. Commenters stated that even the 40 percent capacity factor considered in the NSPS may not provide the flexibility for a regulating unit to fu lfill its legally defined mission. Commenters stated the proposed rule as written ignores this type of facility and may prevent future regulating units from being constructed, directly in opposition to the Obama Administration's Blueprint for a Secure Ener gy Future and to many states' Renewable Portfolio Standards.

Comment 3 3 : Commenters did not agree with the Proposal's treatment of CHP and/or retiring NGCC units.

Response 3 3 : The 111(d) final rule does not include all CHP units in the goal calculation

. CHP units are included where these are primarily involved 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 final 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 not include useful thermal output in the goal calculation but does pe rmit it to be used for compliance. 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 specif ic public comments under this comment:

CHP may not be dispatchable.

Commenters requested that the EPA ensure that the Emission Guideline does not inadvertently reduce the use of CHP by exempting facilities that utilize efficient CHP from being affected EGU s. 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 c ommenters CHP is often installed for the host's industrial process and 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 b oth 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 b egin with.

Commenters stated the EPA improperly included combined heat and power (CHP) units in its Building Block 2 goal calculation, mistakenly assuming that CHP units can re

- dispatch to higher capacity factors in the same manner that non

- CHP NGCC 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 units 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 excluding all CHP units from the calculation. If, however, EPA chooses to include CHP units in Florida's goal calculation, commenters stated it must do s o according to the same applicability criteria that EPA establishes under the proposed new source rule, which provides different applicability criteria that the existing

- source proposals for CHP units.

Commenters stated that the EPA inappropriately include s non

- dispatchable combined heat and power (CHP) units in its calculation of the potential 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 the EPA included in its analysis industrial

non

- dispatchable CHP plants which, in 2012, accounted for almost a third of the NGCCs over 25 MW and approximately 15 percent of the total electric generation analyzed by EPA. (Commenters noted that u nless these units sell more than one

- third of their potential output to the grid, they are not affected units, making their inclusion in EPA's analysis particularly inappropriate.) Commenters stated their operation is completely different from that of a po wer 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 than EGUs, their electric output is directly related to their on

- site industrial activity and heat (or ste am) production, they do not respond to the demands of the grid and many CHP plants use much of the electricity they produce for their own needs and cannot be dispatched like power sector plants. According to the commenters, more than half (34 out of 64) of the plants that EPA identifies as having utilization rates of 70 percent or more were, in fact, CHP plants (Id.). Commenters asserted that these CHP plants cannot be taken into account when assessing the potential 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. Commenters concluded that the re

- dispatch portions of the state targets must be recalculated accordingly.

CHP are not representative of NGCC capacity

. Commenters stated that, while the EPA did not provide 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 stat ed that, because CHP plants primarily generate based on the needs of adjacent customers, their operations are not representative or indicative of typical NGCC capacity factors. Commenters stated that, through operating an integrated system, Southern Compan y is uniquely aware of the important role NGCCs play in maintaining reliability and suggest EPA reassess its dataset focusing only on non

- CHP NGCCs and sustained
state

- wide achievements.

Commenters requested the EPA correct the error of the inclusion of co mbined heat and power (CHP) facilities in the CPP's analysis of existing NGCC capacity factors. Commenters stated existing CHP facilities have been specifically designed to operate in a symbiotic relationship with other partners; often either a municipalit y or industrial process. Commenters stated each CHP system is constructed to meet the needs of an individual 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 energy requirements of the site, which are often a fixed temperature, pressure and volume of steam. Commenters stated the steam demand is frequently constant, but not necessarily a high volume demand. Commenters stated variation s in designed steam output could have significant impact on the receiving entity because the CHP unit is optimized for steam production per the contractual relationship. Commenters stated that NGCC units without CHP are optimized for their combined steam c ycle to generate electricity. Commenters stated the decision to design and operate 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 assumed that the re

- dispatch of any coal, oil, or gas steam generating unit to existing NGCC will reduce 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 A ct of 1978; these CHP facilities are qualifying facilities (QF), and utilities have a legal obligation to take power from QFs at specified rates. Commenters stated that, because fuel combustion is generally needed to produce steam for industrial or other p urposes at a constant, defined rate, incremental re

- dispatch of particular CHP units is generally not possible; therefore, these facilities are not subject to typical dispatch decision

- making. Commenters stated that highly efficient steam CHP systems may h ave emission rates lower than NGCC units that are not part of CHP systems. Commenters referenced EPA's TSD 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 Syrac use Energy coal

- fired CHP unit had an emission rate of 1251 lbs. CO2/MWh.5 Commenters stated that re

- dispatching from the steam generating CHP unit to the

non

- CHP NGCC unit would result in an increase in New York's electric sector emission rate, rather tha n 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 produce useful ste am

- 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 fossil fuel combustion, and therefore CO2 emissions, to produce that useful steam ; however, instead of using the steam to also generate electricity

- with no or little net emissions

- a separate NGCC facility will be required to burn additional gas to make up for the re

- dispatched electricity. Commenters stated this re

- dispatch will result in more fuel combustion and CO2 emissions than efficiently using the fossil fuel at the CHP unit for both electricity and steam.

Commenters stated the inappropriateness of EPA's goal calculation methodology is made clear by considering how the Clean Power Plan treats steam generating CHP units when applying building block 2. Commenters stated that the EPA first calculates a facility's electric output from EIA data; then the EPA calculates the emissions associated 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, c ommenters stated, if a CHP facility had 20 percent electric output, its emissions associated with electric output is assumed to be 20 percent of the unit's total emissions. Commenters stated this calculation is based on an incorrect assumption:178 there is no reason to believe that if a CHP unit decreased its electric generation, the unit's total emissions would decrease by the same proportion. Commenters stated that decreasing a unit's electric generation may not change the unit's emissions at all.

Need to adjust calculation to credit CHP.

Commenters suggested the EPA does not credit CHP properly in the proposal because, by dividing the CO2 emissions by the gigawatt hours generated, there is no accommodation for the use of waste heat by CHP, which leads to an incorrect lowering of the ratio used in the calculation. Commenters suggested there should be an 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 combustion sources and should be credited in this rule.

Commenters urged the EPA to ca lculate Building Block 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 emissions of coal, oil, and gas steam generating CHP u nits and replaces that electric generation 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 stated that, although the EPA continues to treat these units as affected EGUs, including emissions and output from these units in state goal calculations, the inclusion of these units' emissions and thermal output make little conceptual sense for a rule purporting to regulate EGUs and not 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 contended that, in many cases such re

dispatch will result in wasted useful steam, excessive fossil fuel combustion, increased emissions, an d higher costs.

Commenters stated the improper use of net energy instead of actual electric generation incorrectly reduced Michigan's baseline by almost 20% and must be corrected. Commenters stated that, for the CPP analysis of Michigan, EPA identified fo ur CHP facilities; three of which are NGCC units. Commenters stated Michigan had 5,008 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 a s a CHP unit is so high, the state's net energy output is substantially higher than the actual electric 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 would 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). Commenters stated that, in Michigan, this inconsistency has significant effects. Commenters stated that, when establishing the 2012 emissions inventory, EPA quantified the UTO from the 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, expressed in MWhs. Commenters stated this resulted in an incorrectly proposed NGCC emissions rate of 810 lbs/MWh18 rather than a realistic and179 accurate standard of 1,000 lbs/MWh equivalent to new 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 n ew unit proposal. Commenters estimated that this revision would add 59 lbs CO2 per MWh to the proposed Michigan standard.

Commenters stated that, because EPA is proposing a regulatory scheme addressing GHG emissions from existing fossil fueled electric gen eration units, it is appropriate to only consider those production impacts. Commenters stated this ensures regulatory consistency with previous regulatory programs as EPA recently embraced this very concept in the proposed Standards of Performance for Gree nhouse Gas Emissions From New Stationary Sources: Electric Utility Generating Units. Commenters stated that, in that proposal, the EPA states "In today's action, we propose that if CHP facilities meet the general applicability criteria they should be subje ct to the same requirements as electric

- only generators. ..." and the EPA further states: "... under this approach, all combustion turbine units that meet such applicability requirements ... would be subject to the standard of performance for CO2 emissions . That standard would be: (i) during periods when certain conditions (noted below) are met, 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 CH P applicability. 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 proposal did not include any CHP adjustment, instead EPA dec ided 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 Useful Thermal Output (UTO) when
esta blishing 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 flexibil ity and operating philosophy of 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 indicated that the EPA acknowledges and discusses these distinguishing characteristics thorough a website and support documents associated the "EPA Combined Heat and Power Partnership." Commenters further quoted the EPA's "CHP Project Development Handbook" as saying: "Whether CHP can be economi cally beneficial at any particular site depends on a host of site

- specific characteristics such as the energy consumption profiles of the facility, the relative prices of fuel and retail electricity, and the costs of installing and maintaining the CHP equi pment." Commenters highlighted the differences in how CHP facilities operate by including the permit condition for one CHP facility in Connecticut, which discusses significantly different 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 natural gas and No. 2 fuel oil. The turbine and the boilers can be operated by themselves or under the following combinations: turbine and the eq uivalent of one boiler, two boilers without the 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 inaccurate baseline NGCC emission rate that is biased low and that has not been adequately demonstrated. Commenters stated that this results in overly stringent state emission rate goal. Commenters explained this assertion as follows:180 • "Co

- generation units are capable of providing both electric energy output a nd useful thermal output (UTO). For CHP facilities subject 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 production. EPA then adds only the UTO relat ed energy output to the electric output to calculate a revised baseline NGCC emission rate for the facility. The UTO related CO2 emissions are not used to calculate the revised baseline NGCC emission rate, but instead are added into the "Other Emissions" c omponent of the building block two methodology."

Commenters illustrated this concern using the EPA goal calculations for Arkansas where the agency identifies seven NGCC facilities in the state, one of which is a CHP unit (Pine Bluff) where energy output an d CO2 emissions associated with useful thermal output were calculated. Commenters provided the following explanation:

• "The impact of EPA's methodology for considering UTO energy output is significant as it reduces Pine Bluff's emission rate by 47% from 1,1 32 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 rate 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 equal 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 eval uated NGCC CO2 emission rates, which indicates that even the most optimistic of CO2 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 appropriately for retiring NGCC units. Commenters believe that if plants under construction are included in the goal

- setting calculations, then it is also appropriate in some instances to exclude plants that were scheduled t o be retired between 2012 and 2014. Commenters said that, given the large number of possible NGCC retirements suggested by the age of the natural gas

- based fleet, the EPA's failure to account for future unit closures while simultaneously including under co nstruction units potentially overestimates the size of the NGCC fleet, as new NGCCs could be replacing older units scheduled to be retired. According to the commenters, 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 being taken by utilities within the interim period to comply with other CAA programs, such as regional haze, that result in the cessation of

coa l

- firing at affected units. Commenters stated that, 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

- dispatch under B uilding Block 2 prior to their committed shutdown or conversion date.181 Commenters stated that, in establishing the state goals, the EPA needs to take into account any existing, enforceable agreements between the states and affected facilities located in the ir 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 2 022. 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 their scheduled installation before 2022.

Comment 34 : Co mmenter s 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 TSD 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, includ ing that it is essentially carbon neutral. Commenters stated this 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" b ased dispatch block will require certain states to displace electrical production from higher carbon fuels 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 coal 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 the 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 using natural gas should be sufficiently flexible to excuse compliance during times of significant capacity constraints or other emergencies, such as during the January 2014 polar vortex, Hurricane Sandy in 2012 or Hurricane Katrina in 2005. Commente rs stated that failure to account for these practical implications will put citizens at182 great risk as utilities are forced to weigh environmental 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 s hortages could become more frequent and longer, making it very difficult to maintain 70% load year round. Commenters suggested that the rule include a provision for natural gas curtailment much like the National Emission Standards for Hazardous Air Pollut ants (ICI Boiler MACT SD and Area Source Boiler GACT 6J).

Comment 36 : Commenters recommended changes to the EPA's Building Block 2 calculation regarding oil/gas steam units , timing, and the preservation of a minimum level of coal steam MWhs.

Response 36 : The EPA disagrees with the interpretation of the rule. 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 proposal and RIA

– the establis hment of CO2 emission reduction standards is regionally based 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, 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 achie vement between performance periods. The Building Blocks are not prescriptive, and states may consider local circumstances as they develop their plans, including system reliability, fuel diversity, the need for “ancillary services” and other regulatory
requ irements. 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 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 recommended the following suite of adjustments to EPA's Building Block 2 calculation and stated they would not support adopting one or two and not the other(s). Commenters stated that, while it is important that the EPA maintain the interim targets to ensure that states achieve emission reductions across the compliance period and not delay emission reduction prog rams to the latter half of the decade, it is important to establish more of a "glide path" from where states are today to the final goals in 2030. Commenters specifically recommended the following suite of adjustments :

“ First, we recommend that, in deve loping the proposed state targets, 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 necessary to support this level of utilization is in place or to incre ase the use of other compliance strategies. Second, we recommend that 2012 generation from183 affected oil/gas steam units be excluded from the goal 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 ra mp 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 provide. Commenters stated that, in contrast to the two other building blocks, coal plant efficiency improvement and increased utilization of NGCC capacity have no impact on annual rates between 2020 and 2029 because the goal computation formula raises efficiency levels of coal plants and utilization of NGCC facilities to th eir final target levels in 2020. Commenters stated that, because Building Blocks 1 and 2 account for over 40 percent of the total proposed reduction under the rule, front loading the emission rate trajectory causes the rates used to calculate the interim g oals to be sharply lower in 2020 than the 2012 baseline, with little change thereafter between 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 th e calculated 2020 emission rate. 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.

Commenters recommended th at 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 factor in 2012. Commenters noted that, in 2012, natural gas prices were relatively low, so NGCC utilization rates were relatively high. Commenters stated the EPA could take a range of approaches to introducing NGCC to the goal setting equation. To be consistent with the proposed approaches to renewable energy and energy efficiency, Commenter s 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 that considers the potential permitting and system constraints described above.

Commenters stated that the other two changes they recommended to Building Block 2 are similar in terms of justification and implementation. Commenters stated that oil/gas steam units serv e a different segment of the dispatch curve and are often used as a backup to coal and natural gas baseload generating facilities. Commenters stated that, in 2012, NGCC capacity factors increased significantly and coal steam utilization rates declined; how ever, the average utilization of natural gas and oil steam units was virtually unchanged between 2011 and 2012, demonstrating that utilization rates of oil/gas steam units do not correlate with NGCC capacity factors.

Commenters stated that, according to E PA's eGrid database, fossil steam units with capacity factors of 40 percent or less accounted for 12.3 percent of total fossil steam MWhs in 2012. Based on this analysis, c ommenters recommended that EPA preserve at least 10 percent to 12 percent of coal st eam generation in calculating the state goals. Commenters stated these lower capacity factor units tend to be used for peak demand 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 2012 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 sources 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 elimination of 100 percent of boiler steam MWhs in the state goal computation. Commenters noted that, 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 comp utation. Commenters stated the proposed change would preserve an element of fuel diversity that we believe is important to capture in the goal computation.

Preserving a percentage of coal

- fired steam generation.

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. Simil ar to the coal units, commenters stated 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 for exclusion of 2012 generation from oil/gas steam units from Building Block 2.

Commenters agreed with EPA's assessment that significant reductions in CO2 emissions are available through the re

- dispatch of cleaner NGCC units as seen in the northeast with lower natural gas pr ices. Commenters referred to an attached 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 complete elimination of fossil f uel

- 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 significantly over recent years and, New England has become increasingly dependent on natural gas

- fire d 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 created the Strategic Planning Initiative (SPI) in 2010 to address iss ues arising from being highly reliant on natural gas especially in this highly natural gas delivery constrained area. Commenters stated the importance of baseload and intermediate load generation fuel diversity for reliability purposes was observed in Janu ary and February of 2014, when the area experienced extremely cold weather and the demands for natural gas could not be met for both power production and home heating. Commenters stated that both coal

- and oil

- fired generation were needed during the cold s nap due to a lack of delivery capability to natural gas

- fired EGUs. Commenters noted this concern was specifically identified in the North American Electric Reliability Corporation's ("NERC") Initial Reliability Review of the CPP in which NERC identifies t hat 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 season. Commenters stated that, based on their experience in t his area, the EPA must preserve 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 dispatc h curve and are usually operated 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 aroun d185 10%. Commenters stated that the preservation of these 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 : S imple cycle combustion turbines are not included in state goals, and may not be used to adjust a rate. In response to addi tional 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 EG Us. 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 st art 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 reliability, fuel diversity, the need for ancillary services other regulatory 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 TSD for the CPP Fina l 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 include 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 emission rates from gas

- fired EGU's. Commenters stated that their analysis found that only 18 of a total of 583 gas

- fired EGU's had heat rates that exceeded 250 M MBtu/hour and a 5

- year average gross generation greater than 240,000 MW

- hr, which are the criteria EPA used to identify gas

- fired units included in its proposal.

Commenters stated the EPA should not include CTs that operate above 30% capacity in its calcul ations for Building Block 2. Commenters stated 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 natural 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 promote s in the Proposed Rule. Commenters stated that, since existing CT units were designed as peaking units, no data are available evaluating the ability of CT units to operate at 70% capacity, thus, it is not possible to know whether such operations are even t echnically feasible over an extended period of time.186 Commenters asserted that the EPA must revise its state goal calculations to ensure that natural gas simple

- cycle and steam boiler units are not included as part of the existing NGCC capacity. Commenters provided a table said to give examples of 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 incorrect ly included natural gas simple

- cycle and gas steam units as part of the existing NGCC capacity.

Commenters stated that conversion to simple cycle combustion 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 3 8 : Simple cycle units are not included in affected units 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 for 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 opportunities for existing simple cycle generating facilities to be converted to combined cycle and the EPA should clarify that these types of projects are creditable in state plans. Commenters stated that converting these un its 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 for peaking capacity and utilize it as a far more efficient, lower emitting combined cycle facility, thereby helping states meet their CPP targets. Commenters stat ed that, as a general matter, LS Power would expect heat rates on converted combined cycle plants to improve by 25

- 30%.

Commenters stated that, while EPA is considering the extent to which new projects should be incorporated into the CPP, it is important t o consider converted units as presenting additional and

more near

- term opportunities than greenfield projects. 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 proposal 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 from a coal facility when utilizing a mass basis; (2) the lower emission rates associated with the re

- dispatch from a coal unit to the converted NGCC unit when utilizing a rate basis; and (3) th e additional lower emission rates associated with the use of the NGCC facility as compared to the previously existing simple cycle facility when utilizing a rate basis.

Commenters stated doing so will allow states to take advantage of cost

- effective means for reducing CO2 emissions while providing ancillary benefits 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 installed in a simple

- cycle configuration, with the infrastructure in place to expand to a more efficient 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 exe cute many of these types of projects in the next few years. Commenters stated it is important that the final rule build on the NODA and remove uncertainties regarding the crediting of projects initiated prior to 2020 and grant credit for such early action.

Commenters stated the conversion of a fraction of simple cycle combustion turbines to NGCC units, where reasonable, should be encouraged and should be included in the base. Commenters indicated this should include units that are already under constructio n 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 3 9 : Commenters recommended various approaches to calculating 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% capacity assumption

. Response 3 9 : The EPA has finalized this rule and is not including new NGCC units. See s ection V and the TSD on Goal Setting for the EPA’s response 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 c apacity constructed since 2005 to replace retired coal

- fired capacity and recommended this exemption should include both existing NGCC capacity and NGCC capacity currently under construction.

Commenters requested that the EPA exempt NGCCs built 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 credit for the renewable generation investments prior to 2012. Commenters request ed that the EPA acknowledge early performance by providing credit for actions taken pursuant to an existing state program, requirement, or measure on or after 2005, the baseline year for CO2 emission levels.

Include units likely to be constructed between n ow and 2030.

Commenters recommended that the EPA consider revising 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 exi sting coal

- fired plants to co

fire less carbon intensive fuels or convert to firing natural gas. Commenters stated this would better reflect demonstrated and available practices to reduce emissions, result in greater equity188 across states, and ensure that t he effectiveness of EPA's proposal is not diluted by the construction of new NGCC plants.

Address units that came on line during, and were operational for only part of 2012.

Commenters expressed concern that the Proposal included in the baseline existing NGCC capacity for each state NGCC units that were commissioned 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 ca pacity from "under construction" units when applying Building Block 2 to calculate the proposed state goals. Commenters stated there is no legal requirement or basis for EPA to include a projection of future emissions and generation (megawatt hours) from t hese 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

- dispatch from NGCC units that had no operating history during or prior to the 201 2 baseline year. Commenters stated that, given EPA's lack of justification for predicting the hypothetical operating duty of units that were not operating in the baseline year of 2012, EPA should exclude "under 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 requirements once they be gin operation and would count towards compliance with a state's interim and final goals if they satisfy the relevant applicability criteria.

Commenters stated the EPA must address the state

- specific 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 appropri ately accounted for under construction NGCC units when calculating the state goals. According to the commenters, the EPA suggests that all states' NGCC fleets, including units under construction as of January 1, 2014, are able to achieve a 70 percent utili zation rate, and the EPA assumes that the additional generation from under construction NGCC units also will displace coal generation, thereby reducing CO2 emissions. Commenters noted that the potential for re

- dispatching 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 construction, and therefore unavailable to produce power, during the 2012 baseline year when calculating s tate goals; only units that were operational and producing power in the 2012 baseline 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 u nits that were 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 construction in 2012 significantly depresses the actual realized capacity f actor 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 had capacity factors of essentially zero for that year. Commenters stated the average capacity factor for existing NGCC generation located in North Carolina, as designated by the EPA, adjusted for I OU

- owned units in North Carolina is approximately 44.7% for calendar year 2012. Commenters stated that, when North Carolina's NGCC plants that were operational for all or the majority of 2012 (Smith 4, Smith 5, Buck, and Rosemary) are utilized, the North C arolina NGCC capacity factor rises to 64.5% (utilizing nameplate capacity) for 2012. Commenters stated that, utilizing summer net capacity values for the same four plants, the annual capacity factor rises to 71%, which is above EPA's target of 70%. Comment ers concluded that North Carolina's NGCC plants have minimal headroom for additional utilization.

Recalculate for units constructed after 2013.

Commenters specifically requested that EPA recalculate the Virginia targets excluding the emissions and megawatt hours from the Warren and Brunswick NGCC units in Building Block 2. Commenters stated that, specific to Dominion, EPA included NGCC units that were under construction as of January 8, 2014, such as Dominion's Warren and Brunswick facilities in Virginia, i n the calculation of the state goals in Building Block 2, increasing the stringency of the state targets (by almost 40 lb/MWh). Commenters stated 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 included 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 ut ility company for early actions to reduce the state's emission rate by investments in less carbon

- intensive technology.

Commenters stated that, in the goal calculations for 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 commence construction, or have yet to receive all necessary permitting and regulatory approvals. Commenters stated the EPA must revise these calculation s to exclude such units and to ensure that 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 because it assumes that such units have operated at the intended output level prior to the stated date. 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 has incorrectly accounted for NGCC EGUs that started operation just prior to January 8, 2014. Commenters stated that two major areas of conce rn include the assumptions for existing and under construction natural gas combined cycle capacity and the misrepresentation of the state's Renewable Energy and Energy Efficiency Portfolio Standard. Commenters stated that all of these comments need to be

a ddressed in order to establish an accurate and more technically sound state goal for North Carolina.

Do not agree with the 55% capacity assumption.190 Commenters stated that, to the extent EPA retains its proposed approach to include under construction NGCC u nits in the calculation of state goals, EPA should take into account the specific circumstances of under construction NGCC units 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 specific circumst ances of these units vary widely from EPA's assumed 55 percent, thereby artificially 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 expected to retire for economic or environmental reasons. Commenters noted that (1) Dominion is currently 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 utilization 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 percent utilization, even without the proposed Clean P ower 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 generating units. Commenters stated that, for purposes of calculating the state emission goals, under construction NGCC units designed and constructed to serve base load generation needs should not be

assume d to be BSER.

Commenters stated that if the EPA determines to consider under construction NGCC units when finalizing the state goals, the EPA should not assume 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 arbitrary, and that the EPA has not provided a basis in the record for applying this assumed capacity factor to all under construction units. Commenters noted that a ssuming a 55 percent capacity 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 above 55 percent, reducing the capacit y that would be available for dispatch under EPA's methodology. 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 account the specific c ircumstances of under construction NGCC units to determine the extent to which those units can increase their utilization in order to displace higher

- emitting steam generating units.

State

- specific issues.

Commenters referred to comments filed by Arkansas Electric Cooperative ("AECC") on September 30, and stated the John W. Turk Power Plant in Arkansas has not been adequately captured in EPA's 2012 baseline emissions level. Commenters stated that, in 2012, as a new coal plant just coming online, Turk was un dergoing testing and was in commercial operation for only ten days, and thus 2012 is not representative of Turk's emissions for a full year. Commenters agreed with AECC

-- the 2013 emissions from Turk must be factored into EPA's 2012 baseline emissions leve ls 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 tha t the EPA was not consistent in its approach to under

- construction NGCC units, excluding some from the state goal calculations. Commenters gave the example that, in calculating New Jersey's emission rate goals, the EPA failed to include several under
const ruction NGCC units. Commenters added that if these units are excluded, the EPA should make clear that New Jersey's compliance demonstration does not include these units, and that if EPA chooses to consider under construction units when setting the final go als, EPA should ensure that all under construction NGCC units in all 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 incorrectly lists PacifiCorp's Uta h

- based Lake Side 2 NGCC as operational in 2012 when the plant was under construction in 2012 and did not achieve commercial operation until June of 2014. The commenters 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 target should be recalculated, consistent with the intended use of the unit.

Commenters stated that, although these new units were brought into service at different times during the year, EPA's calculation assumes that they 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 produces then an artificially high amount of NGCC re

- dispatch, with the end result of a state emission rate goal that is biased low. Commenters noted two of the five existing NGCC units in Ohio were commissioned in 2012 (Dresden was commissioned January 3 1, 2012 and Fremont was commissioned on January 20, 2012).

American Electric Power (24030) comments on "under construction" units.

Commenters stated that the EPA is inconsistent, incomplete and inaccurate in its consideration of all NGCC units that were c ommissioned during and after 2012 in terms of if and how these units were classified into the "existing" or "under construction" category. Commenters asserted that it has identified numerous errors related to the scope of units considered (or not considere d), the EPA's assumptions regarding the status of these projects and the EPA's methodology for considering these units within the block 2 calculations. Commenters provided detailed discussion of these issues (summarized below), and stated that the EPA must correct these issues, which Commenters believe d to significantly diminish the NGCC capacity to be included within building block 2. Commenters added that for accuracy and completeness, the EPA should first review the scope of all NGCC units commissioned o r to be commissioned after December 31, 2011, and second treat all of these units equally as "under construction" in the building block 2 calculations. Commenters’ detailed comments about several aspects of this issue are summarized below.

Commenters state d that in the calculation of existing NGCC capacity available in 2012, the EPA incorrectly included certain NGCC projects that were not commissioned until after 2012 as part of the "existing" NGCC units that were re

- dispatched up to a 70% capacity factor i n the building block 2 calculations. Commenters identified one example 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 assert ed that the EPA must revise these192 calculations to exclude such units and to ensure that the existing NGCC units considered have actually been constructed, and provided a table said 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 where the agency determined it applied. According to the commenters, for five of these states, the units determined to be "under construction" by the EPA represent fictitious "potential" 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 co nstructed, 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 should not be co nsidered in building block 2.

Commenters further stated that for the remaining four 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 Dresde n Plant, which 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 construction. Commenters gave additional examples of units in Virginia and Wyoming.

Commenters added that not only has EPA mischaracterized the under construction NGCC capacity for nine states, but the Agency has not recognized other proposed NGCC projects that may fall into the under construction category. Commenter s indicated that its review of the spreadsheet tab marked "proposed" in the EIA860 report that has been referenced by the EPA identifies many potential NGCC projects that were ignored by EPA in building block 2. According to the commenters, potential NGCC projects have been identified for over 20 states, which may meet the definition of "under construction" as currently defined in building block 2.

Commenters noted that in determining the CO2 emissions 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 state did not have any existing units. Commenters asserted that based on significant flaws in how the state average NGCC emission ra tes were calculated, the EPA's approach for determining the future emissions from under construction units is inaccurate and inequitable. Commenters provided a table showing the emission rates that the EPA assumed for certain "under construction" NGCC faci lities that c ommenters allege are not actual projects.

Commenters asserted that the EPA must correct what c ommenters believe are errors in both the scope of "under construction" units considered and the assumptions for consistently estimating emissions fr om these units.

Commenters also stated that the EPA fails to consider certain existing NGCC units that were commissioned during or after 2012 that could be considered 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 before January 8, 2014

- the effective date that the 111(b) standards for new sources were re

- proposed by the EPA. Commenters provided a table of including examples o f such facilities.193 Commenters stated that the EPA overstates the amount of re

- dispatch available from NGCC units commissioned in 2012 because it does not weigh the commissioning date into its calculation

- when calculating re

- dispatch, the EPA assumes tha t all of these units were available to operate throughout 2012 even though some of these 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 ca pacity factor, which produces an artificially high amount of NGCC re

dispatch, with the end result being a state emission rate goal that is biased low. As an example, commenters noted that two of the five existing NGCC units in Ohio were commissioned in 20 12 (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 fa ctors 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 during 2012 remain in the calculation of the "existing" ca tegory 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 calculation that Commenters believe appropriately weighs the in

- service date into the re

- dispatch calculation.

Commenters provided an example of the use of the suggested approach for the Dresden and Fremont Plant which, along with the correction of other errors alleged by Commenters through out the comments, would reduce the amount of NGCC re

- dispatch calculated for Ohio from 5,793,981 to 439,452 MWh

- a 92% reduction from 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 available to operate for only 1 day in 2012, yet EPA's calculation assumes that the unit was available 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 represent over 20% of the total re

- dispatch calculated for the state of North Carolina

- e ven though the H.F. Lee plant had not been commissioned until the last day of the year. Commenters added that the North Carolina goal is made more unrealistic by the commissioning of another NGCC unit at the Dan River plant on December 10, 2012

- if the as sociated "re

- dispatch" capacity from Dan River is considered as well, then nearly 40% of the re

- dispatch capacity calculated for North Carolina was from units that had not been commissioned or available to operate for most of the year. Commenters provided a table of alleged other examples of this issue.

Finally, c ommenters noted that the EPA's proposed 111(b) rule for new units included a technical support document for combustion turbines that was designed to evaluate potential differences in emission rate s due to various unit

- specific factors, and that the EPA's evaluation focused on NGCC units that were commissioned from 2000 through 2010 because "[a]lthough new NGCC units came online in 2011, none are included here as they lacked sufficient data to calcu late 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 existing NGCC units to be re

- dispatched, and that these units could then be separately included in the "under construction" category of units within194 building block 2 calculation. Commenters asserted that at a minimum, the EPA must at least revise the state goal calculations to properly account f or 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 provision of the rule

. , and no response to this comment is provi ded.

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

Commenters stated that South Dakota has only one NGCC plant, Basin Electric Cooperative's Deer Creek Station which began operating late in 2012 running at about one percent of capacity, leading EPA to assume, incorrectly, that Deer Creek Station has an add itional 69% of capacity available for increased generation. Commenters stated that, had EPA treated Deer Creek Station as under construction, or had it used a different baseline year that properly reflected Deer Creek Station's status as a plant that is no t yet operational, the emission reduction target for South Dakota would have looked very different from what EPA has proposed.

Commenters suggested the EPA needs to classify the Deer Creek Station as under construction because it was in its initial startu p phase in 2012. Commenters noted that, if EPA agrees with this request, South Dakota's state goal would increase from 741 to 1,036 pounds of carbon dioxide per megawatt

- hour, which would give South Dakota more flexibility to use building block 2 as a meth od of demonstrating compliance with its state goal instead of being penalized for the construction and installation of its sole natural gas 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

- dispatch target set for South Dakota under the proposed rule is arbitrary and capricious because it is based on an erroneous exaggeration of the state's NGCC re

- dispatch capacity. Commenters stated 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 Deer Creek Station could ramp up generation by an additi onal 69% in future years. Commenters stated 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 Deer Creek Station would have to displace an equal amount of generation at Big Stone Plant, dropping Big Stone Plant's total annual output from 2,923,000 MWh to ju st 958,000 MWh. Commenters stated that, to comply with the Building Block 2 emission target EPA assigned to South Dakota, Big Stone Plant would have to operate at an annual capacity factor of just 23%

. Commenters stated that since Big Stone Plant's minimum operating load is approximately 40% of normal maximum load, running the plant at a 23% capacity would require it to be off

- line at least half the year. Commenters stated that Deer195 Creek Station does not have sufficient excess capacity to supplant such a s ignificant reduction in Big Stone Plant energy production.

Commenters stated that operating a baseload generation unit such as Big Stone Plant so infrequently would be uneconomic, particularly after 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 Plant 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 the costs to r eplace the energy. C ommenters stated it is important to remember that public utilities commissions in Minnesota and North Dakota granted advance prudence determinations for the Big Stone Plant AQCS and this approved investment to serve electric consumers a nd 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 the 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 Public Works Committee).

Commenters noted that emis sions 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 stranding 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 stated that, after placing Deer Creek Station into the under construction category, if EPA continues 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 th at following 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. Commenters stated that, because Wyoming and Kentucky had no existing NG CC units other than units that were considered under construction, EPA used a nationwide average NGCC emissions rate of 907 lb/MWh (net basis) as the assumed emission rate for these two states.

Commenters stated that, if EPA does proceed with including und er construction units in the final rule, using a nationwide average is a rational approach to determining the appropriate emissions rate. Commenters stated it is also more representative than using Deer Creek Station's 2012 CO2 emission rate average. Comme nters stated that, if EPA 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 D akota'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 coal to NGCC in South Dakota, as required by Building Block 2, is not really available.196 Comment 41 : Commenters disagreed with BB2 calculations that included 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 e xist.

Response 41 : The EPA disagrees. 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 data updated. The 111(d) final rule requires that states develop plans that establish emission standards for affected EGUs. We are providing states with substantial flexib ility 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 fr om 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 reliability, fuel diver sity, and other regulatory requirements. 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 the EPA's calculation methodology incorrectly applies its building blocks approach to non

- affected Subpart KKKK units. Commenters stated the proposed goals assume that states will regulate thes e sources, but states can only regulate existing sources to which an NSPS would apply under Section 111(b). For GHG emissions, 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 would be shifted under EPA's Proposal for building block 2 do not qualify under these capacity

- 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 can properly be regulated, EPA made various errors in calculating capacity, double

- counting some units, and counting non

- existing units. Commenters stated these mistakes are explained in more detail by UARG's consultant, James Marche tti, 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 section 111(d). Commenters stated that the success of Building Block 2 depends on the participation and compliance of units that will not be subject to the Proposed Rule. Commenters stated that the EPA cons idered ineligible EGUs in the calculation of state goals, citing the Marechetti Report. 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 proposed 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 than 73 MW (250 MMBtu/h) and was constructed for the purpose of supply ing, and supplies, one

- third 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

o n units that are not subject to regulation. Commenters stated that, because States cannot impose standards of performance on these units, the increases in NGCC capacity EPA expects them to make will necessarily have to be made by EGUs that are subject to E PA regulation, with the result that affected NGCC units will be forced to operate 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 included in its calculation of state goals emissions from and capacity for existing NGCC units that do not currently exist, that have not yet been fully developed, and that may never be completed, referencing UARG comments (Section XIV.C).

Comment 4 2 : Commenter s stated the EPA should re

- formulate its calculations for Building Block 2 to address the relationship between re

- dispatch 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 flexibility, through approaches such as trading, that will permit states to address any special concerns to IGCC plans in their state.

The following are summaries of the specif ic 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 to fill the gap. Commenters stated that could be problematic for Indiana' s IGCC units, which were specifically excluded from EPA's calculations for Building Blocks 1 and 2. Commenters stated that emissions of CO2 at IGCC plants are in line with coal

- fired power plants; however, heat rate improvements are not viable due to the i ntrinsic nature of the process. Commenters concluded that, in order for a coal

- heavy state such as Indiana to meet EPA's goals, IGCC plants will be dispatched less frequently than would otherwise be the case. Commenters suggested that, because the existing investment in IGCC plants will be effectively penalized by the proposed rule, the EPA should re

- formulate its calculations for Building Block 2 to directly address the relationship between re

- dispatch and IGCC plants in a way that takes into account those plants unique attributes.

Comment 4 3 : Recommend Allowing Credit for Conversion from Liquid Fuel to Natural Gas

. Response 4 3 : The EPA has carefully considered cofiring

-- and conversions as a 100% cofiring option

-- and determined that it is not part of BSER (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 advantage of there aspects of the rule. See sections V.D,198 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 the Proposed Rule needs to be rewritten 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 given compliance credit for the full measu re of CO2 emissions avoided by fuel conversion.

Commenters stated the Proposed Rule is unclear on how existing units that convert from liquid fuel to natural gas are to be addressed in any state plan to implement and attain the proposed CO2 emission target . Commenters stated that, in Alaska, GVEA has a combined cycle unit in North Pole that currently operates on naptha. Commenters stated that naptha is a liquid fuel, sometimes referred to as jet fuel, and thus the carbon emissions from this unit were exclud ed from the calculation of the EPA's proposed goal for Alaska. Commenters stated the North Pole combined cycle unit was designed for economic conversion to use of natural gas as fuel, should natural gas fuel become economically available in North Pole. Com menters 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 the EPA, on average use of natural gas as fuel would result in a 26.6% lower carbon dioxide emission rate than jet fuel. Commenters stated that, assuming there is no heat rate penalty in converting the North Pole combined cycle unit to natural gas, at 201 2 energy production levels such conversion would result in a net savings of 59,208 tons of carbon dioxide for a net emission rate of 850 pounds/MWh.

Commenters stated it appears that, as currently drafted, the Proposed Rule would give Alaska credit for pro ducing 423,592 MWh of energy from an affected EGU with an emission rate of 850 pounds/MWh. Commenters stated this would effectively 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 credi t for that expenditure under the Proposed Rule.

Comment 4 4 : Commenter s stated the EPA should modify the proposed rule to allow existing OCGTs to be converted to CCGTs as part of a compliance plan without making them subject to the new NSPS for CCGTs.

Response 4 4 : The EPA disagrees. These peaking units are not affected 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 provide Kentucky and OMU with significant carbon dioxide reductions more quickly than the construction 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 combine d cycle natural gas (CCGT) providing a lower carbon dioxide emitting source with a lower heat rate than either the OCGT or the coal

- fired unit it is replacing. Commenters stated the proposed rule fails to provide any relief from the NSPS for new or modifie d NGCC units despite 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 gas transmission system. Commenters stated that, in many cases the size of the natural gas pipeline feeding the OCGT is sufficient to deliver the required quantities of natural gas necessary for CCGT operation.

C omment 4 5 : Building A number of commenters stated that the EPA should not have used nameplate capacity in calculating the capacity factor in Block 2.

Response 4 5 : The EPA agrees and has modified the calculations in Building Block 2 to use net capability rather than nameplate capacity. See section 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 capacity is the nominal maximum output of a generator, assuming a particular set of ideal, often location

- specific, operating conditions, including altitude, temperature, humidity and other factors that cannot be controlled by unit operators. Commenters noted that because of a variety of technical and ambient factors, power plants never achieve their technical maximum capacity. Commenters stated that net MWh generation divided by nameplate capacity conflates a mea sure of net generation with gross capacity and is not an acceptable metric.

Commenters suggested many alternative capacity metrics.

Commenters applied a variety terms for other measures of capacity that they believe would give more realistic values, inclu ding operating capacity, net summer capacity, summer net dependable capacity, actual tested ratings, net maximum dependable capacity, net dependable capacity, dependable capacity, minimum net generating capacity, demonstrated net capacity, demonstrated

max imum net capacity, unforced capacity, yearly seasonal capacity average, average of the summer and winter capacities, net generating capacity, maximum monthly capacity, summer rated maximum net output, actual/rated capacity, and average annual capacity. Com menters stated that seasonal capability considerations, as opposed to nameplate capacity, are also consistent with regional reliability standards. Commenters 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 the state goals more stringent.200 Most commenters stated that using nameplate capacity results in EPA adding an erroneously high level of gas

- fired generation into a state's goal calculation, thereby excessively reducing the amount of coal

- fired generation included in determining a state's goal above and beyond what can reasonably be considered BSER. Commenters referred to this as "phantom" capacity and generation t hat is not available for re

- dispatch. Commenters stated the EPA's arbitrary inflation of the amount of natural gas generation available for re

- dispatch may account for as much as twice as great a difference in total generation as EPA's entire building bloc k 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, despite the fact that an accurate assessment of the existing NGCC capacity actually availabl e for re

- dispatch is essential to developing an achievable Building Block 2 re

- dispatch target. Commenters 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 that these units will actually be able to supply to the power grid. Commenters stated that, but using nameplate/gross capacity rather than actual/rated capacity, the EPA is relying on "phantom" megawatts. Commenters generally stated that the EPA should correct for this "erroneous" calculation and remove this additional gas

- fired generation from the re

- dispatched NGCC generation element o f the target in order to make its Proposal more workable. Commenters gave the following examples:

• Commenters included Table 4 to illustrate the difference in generation output using a 70 percent annual capacity factor with nameplate capacity versus summer net capacity for eight states. According to the commenters, 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 commenters characterized as both unequitable and unrealistic.

• Commenters stated that, while the proposed Rule suggests 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 Ar kansas with the nameplate ratings, the actual tested ratings and the difference between the two numbers. Commenters stated that the magnitude of this difference seriously undermines Arkansas' ability to meet its proposed 44% emissions reduction target, whi ch was overly ambitious anyway.

• Commenters stated that the use of nameplate capacity instead of net capacity results in (1) higher NGCC dilution of the CO2 emission rate goal, and (2) lower coal

- fired generation contribution to the CO2 emission 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 sustain actual utilization rates201 over 100% in ord er to functionally meet EPA's 70% goal, 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 units totals 996.9 MW, but the summer net capability rating is 8 78 MW, a 12 percent difference. Commenters included a table comparing differences in the demonstrated net capacity and the nominal nameplate descriptor for Ohio, which commenters indicated is typical for each state where NGCC capacity was identified by the EPA.

• Commenters stated that, for Missouri, the net dependable capacity of NGCC units is 1,881 MW as compared to 2,079 nameplate capacity.

• Commenters stated the EPA's use of nameplate capacity in its Building Block 2 NGCC re

- dispatch calculation means th at in order to support the levels of re

dispatch assumed in EPA's proposed state goals, NGCC units would have to operate at statewide average capacity factors of 80 percent and above when accounting for operational reality

- much higher than the already

- i nflated utilization level of 70 percent that EPA assumes, but fails to demonstrate is achievable. Commenters provided the following examples: 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 capacity of 23,784 MW versus their existing nameplate capacity of 29,485 MW is 35,054,309 MWh; the average annual capacity factor of all NGCC units in Florida would need to reach 87.0 percent to produce this amount of g eneration; and the 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 Block 2 re

- dispatch for the
state. Commenters stated that, because these values are stat ewide averages and many units cannot reach such high levels of utilization, many NGCC units would have to operate at even higher annual capacity factors, levels that simply are not sustainable.

• Commenters added that because the Proposed Rule inappropriate ly relies on nameplate capacity, it overestimates actual available 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 e stimates the annual average for the State's NGCC units (Summer Capacity and Winter Capacity) to be approximately 85% of nameplate capacity.

• Commenters stated that, in the case of New Mexico, for example, the total nameplate rated capacity of the NGCC unit s relied upon 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 requirement s, 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. Commenters 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 demonstrated capacities are reported annually to the Energy Information Agency and are summarized in the publically accessible EIA

- 860 report.

• Commenters provided Table 1, which shows the difference between the generation capacities of NGCC located within Arizona assumed by the EPA compared to the actual available capacities of these 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 ratings 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 unit's capability is overestimated b y 17% (576 MW of nameplate capacity versus 492 MW of accredited capacity); as a result, a 70% capacity factor for this unit actually results in a net capacity factor of 82%

- a significant difference.

• Commenters referenced a November 2014 James Marchetti report and stated that (1) the EPA included a number of NGCC plants that were not available in 2012; (2) some of the plants used by EPA in calculating NGCC potential were simple cycle combustion turbine s, and (3) the EPA ignored the constraints that grid operators and or state public service commissions may 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 overstated 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 ge nerate more than 300 MW at any time and adjust 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 Texas, peak power consumption occurs in the summer months; therefore, net summer capacity from NEEDS v 5.13 s hould be used in goal setting.

• Commenters stated that, in place of nameplate capacity, EPA should use an average of NGCC units' summer and winter capacity ratings (which are typically filed with the appropriate electric reliability regional entity) when c alculating 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 in a 2012 NGCC capacity factor o f 53%, rather than the 45% calculated by EPA.

• Commenters stated that, in Florida the difference between available NGCC generation from 70% utilization of the actual summer net capacity of 23,784 MW and the existing nameplate capacity of 29,485 MW is a sta ggering 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 actual summer net capacity, to meet

e nergy needs. Commenters cited the Marchetti Report and stated that, to support the levels of re

- dispatch assumed in the Proposed Rule's state goals, NGCC units in much of the nation would have to operate at capacity factors far higher than 70 percent: in A rkansas, 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 can be provided by NGCC units running at 70% capacity.

Data is available in Form 860.

Commenters stated that the EPA acknowledges that capacity data accounting for weather/temperature conditions would be preferable, but states that it relied on nameplate capacity because "adjusted capacity by the hour/minute" was u navailable 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 j ustification 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 EPA should have used these data in its evaluation of NGCC re

- dispatch opportunities instead of nameplate capacities.

Commenters stated that the Agency "properly" used 2012 summer net capacity from each state's nuclear fleet in determining each state's nuclear capacity "at risk". Commenters stated that the E PA 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 capacity is 13% less tha n the nameplate capacity (422,364 MW vs. 485,957 MW). Commenters noted that EPA's IPM model uses the data from Form 860 (IPM Documentation at 4

- 2) and that the RIA also notes that EPA analyzed net summer capacity from Form 860 in an analysis of existing el ectricity generation (RIA at 2

- 1 to 2

- 2; IPM Documentation at 4

- 4). Commenters stated that consistent with these other pieces of its analysis, the EPA should utilize Form 860 to determine state NGCC capacity. Commenters stated that the widespread recogniti on and use of net 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 foremost, be calculated correctly and it must be evaluated in context with the broad scope of other factors that may influence the pote ntial 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 overall 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 higher capacity factor, in the 80 percent or higher range, based on the use of summer net capacity and a proper c alculation of capacity factors, is adequately demonstrated or achievable and can be accomplished by 2020.

Commenters stated that the basis of the capacity factor calculations should be the average annual capacity instead of nameplate capacity, but differ ed 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 basis. Commenters noted that this recommendation is contingent on the E PA also adopting its recommendation pertaining to inclusion of new natural gas capacity in the building 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 affected NGCC plants, since these values indicate the maximum load a generator can support at the point of interconnection during the respective

season.
Net capabilities decline over time.

Commenters stated that plant capacity wi ll continually 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 new and clean conditions. According to the commenters, ne t capabilities will decline over time as a consequence of combustion and steam turbine degradation, so the EPA's analysis should focus on the net MDC rating and available dispatchable energy that has been demonstrated to be 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 duct burners can be significant. Commenters said that the EPA should use summer capacities without duct burner operation for purposes of goal setting as duct burners decrease the efficiency 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 generator's nameplate capac ity in the capacity factor Block 2 calculations. Commenters suggested the EPA should use the actually measurable net capacity instead of the theoretical nameplate capacity in calculating reductions under Block 2. Commenters stated that, when referring to c apacity, system planners and regulators refer to the real

- world, actually available capacity, not the theoretical, under

- perfect

- design

- conditions nameplate capacity used by the EPA. Commenters noted that state regulators use net capacity incorporating sum mer and winter capacity ratings when 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, EPA 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 determine 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 account all of the appropriate generation dispatch constraints such as regulation reserves, spinning 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 the summer, and that Arizona's utilities could still meet their load obligations. Commenters stated 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 adequate to displace all of the coal generation. Commenters stated this dat a also demonstrates 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 hourly dispatch, if EPA cannot perform the hourly analysis, then EPA must at least use the maximum monthly capacity factor for NGCC units. Commenters stated that monthly net energy is readily available to EPA to calculate these capacity factors, and EPA's failure to use this readily available data is unreasonable.

Commenters stated that, because the Proposed Rule inappropriately relies on nameplate capacity, it overestimates actual available net summer NGCC capacity for Pe nnsylvania by 1,374MW and net winter NGCC capacity by 999MW. Commenters stated 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 tight en causing economic impacts that EPA has not analyzed.

Suggested recalculation method.

Commenters stated the EPA should adjust the megawatts of NGCC capacity it presumes are available for re

- dispatch to account for the shortcomings in its capacity calcula tions. Commenters stated the EPA should conservatively determine 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 restrictions on operation, merchant NGCC capacity, and NGCC that is or must be available to support existing or future renewable energy.

Comment 4 6 : Commenters expressed concerns regarding availab ility and capacity factors.

Response 4 6 : The EPA disagree s and we believe address thse concerns 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) final 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 in cludes, 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 perio ds. The Building Blocks are not 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. 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 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:

Commenter s stated that an NGCC's average annual availability 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 availabilit y 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." Commenters stated annual availability can also be characterized as the "total number of ho urs in a year when the unit was in an active state." Commenters stated that, even though a technology may have a high annual availability, it may be constrained from generating by other factors, such as resource and fuel limitations, reliability needs, tra nsmission constraints, and economics. Commenters stated that a technology's capacity factor captures the other factors that may be present during certain years. Commenters stated that, for example, EPA's annual availability assumption for simple

- cycle comb ustion 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 capabilities of these units and their role in an integrated electric system. Commenters stated that, by maintaining unique operational capabilities (e.g., high annual availability coupled with quick ramping capability), NGCCs are frequently called upon to provide ancillary services and balancing areas on a moment's notice frequently requires generation f or ancillary services. Commenters stated that, although 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, while the EPA surveyed 2012 da ta for 1,800 NGCCs and concluded that the NGCC fleet had an average capacity factor between 44 and 46 percent, the EPA erred in assuming "significant potential for re

- dispatch" was available because the average capacity factor was less than the technology' 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 review to irrelevant (availability factors) and inaccurate (capacity factors) inform ation, but also ignores other more significant factors that influence the utilization of a unit. With respect to the availability factor, commenters did not agree that availability refers to the maximum amount of generation that could be expected from a gi ven source, and that more than 80% of the existing 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 indicated, in part, b y statistics on the average207 availability factor of NGCCs, which in the U.S. generally exceeds 85%, and can exceed 90% for selected groups.

Commenters stated that the availability factor is the percentage of time that a unit is available to provide energy t o 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 commenters stated the fact tha t 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 t o achieve their maximum potential output. Commenters stated the operation of every type of generation resource 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 avail able; therefore, the issue is not whether the unit has a high availability factor, as nearly all units and types of generation achieve that regularly, rather, the issue is how the unit operates when it is available, which is a more complex evaluation 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 i n 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 resour ces and stated that all have high availability factors, but for various reasons have different capacity factors. Commenters suggested that, if the EPA's goal is the re

- dispatch of low

- carbon emitting generation resources, then using the NERC table shows th at hypothetically existing combined cycle units, as well as oil steam boiler, simple cycle turbine, and hydroelectric units are all underutilized and should all be demonstrably re

dispatched at higher rates to offset higher emitting 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 that may be achievable.

Comment 4 7 : Commenter s stated that, for areas that have high in tegration 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 resources such as wind and solar.

Response 4 7 : The EPA disagrees. 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 EPA recognizes the balancing role performed by NGCC capacity. 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 those plans to achieve the 111(d) requirements. The flexibility includ es, 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 reliability, fuel diversity, the need208 for ancillary services other regulatory requirements and infrastructure. The 111(d) fi nal 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 t he 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 demonstrat e that the displacement of NGCC by wind ranges from 32.6 percent in the MISO region to 83 percent in the West, and 87 percent in ERCOT. The commenters stated the existing "head room" between historic NGCC capacity factors and their full capacity 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 solar.

Commenters added that, if EPA continues to mandate re

- dispatch, Western Farmers urged EPA to recalculate emission rate goals utilizing a 50 percent "displacement factor" in calculation of emission rate goals. Commenters suggested an estimate 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 continue operation of NGCCs in concert with renewable energy resources, and encourage the continued integration of renewable energy

resources.

Comment 4 8 : Commenters rec ommended allowing states to use multiple, representative data years, rather than 2012.

Response 4 8 : The EPA generally disagree s. 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 other specific year, selected for establishing state emission rates is not representative of normal plant operations. The commenters suggested the EPA select multiple years that reflect operational 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 operatin g 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 calculated the number of hours in Building Block 2 and should correct its calculations. Comme nters indicated that the EPA's use of a leap year to calculate the hours that must be run to achieve a 70 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 factor should be set using either a typical year or the average of hours per year over four years (8,760 or 8,766). According to the commenters, despite the theory the EPA uses to take the generation in 2012 and divide it by the hours in 2012209 (because there is only one year of data and some plants may not have been functioning normally), the extra 24 hours of data could influence a state's requirement by up to 0.002 percent compared to a normal year, which in some states co uld 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 sta ted that the only way for the EPA to solve this problem is to allow states to use multiple, representative data years. The commenters added that the Agency appears to attempt to address this in the NODA, and the commenters encouraged the EPA to allow state s to use multiple years in setting baseline requirements as a solution for this issue.

Comment 4 9 : Commenters stated that the EPA should calculate the CO2 emission impacts resulting from increased dispatch to existing NGCC power plants using different val ues than those proposed : no more stringent than a NSPS rate; equivalent to the EPA's proposed standards for new, modified or reconstructed units; multi

- year; state

- specific; incremental, or unit

- specific.

Response 4 9 : 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 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, 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 reliability, fuel diversity, the need for ancillary services 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 section s 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:

No mor e stringent than a New Source Performance Standard.

Commenters stated the EPA should assume an emission rate for re

- dispatched existing NGCC units that is no more stringent than a New Source Performance Standard emission rate. Commenters stated that, in th e 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 865 lb CO2/MWh. Commenters stated this

avera ge emission rate is significantly more stringent than the proposed greenhouse gas emission standard for new sources (79 FR 1430). Commenters stated an existing source performance standard should not be more stringent than a new source performance standard for the same210 pollutant. Commenters suggested the EPA adjust Building 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 existing NG CC units can achieve on a long

- term basis, especially when operating at much higher capacity factors and will likely need to utilize less efficient duct firing capacity to achieve these new capacity factors.

Commenters stated the existing NGCC units shoul d not be held to a performance standard more stringent that the performance standard for new NGCC units. Commenters stated that the EPA used a single year to depict the carbon emissions rates for existing NGCC units and, apparently, the EPA assumed all fut ure 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 of the equipment and (2) the sing le baseline year is not necessarily representative of future operations. 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 th e emission rates 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, modified or reconstructed units.

Commenters recommended the use of NGCC emission rates 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 specific average NGCC emission rates to calculate emi ssions 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 unrepresentative state average emission rates cause state goals to be more stringent than what would be required if EPA's proposed standards for new or modified and reconstructed sources were use d in the goal setting calculation.

Commenters stated that the EPA chose the proposed NSPS 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 stated in the preamble that t he 1,000 lbs/MWh emission rate could be met by 95 percent of all combustion turbines constructed since 2000. Commenters stated that the EPA does not present a similar 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 opera ted in 2012, 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. Commenters stated that, in Texas, EPA assumed an emission rate of 837 pounds CO2 per megawatt

- hour for re

- dispatched NGCC units, which211 implies an average heat rate of 7.17 MMBtu/MWh. Commenters 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 renewable gene ration.

Commenters stated that the EPA should assume that at least some of the displaced fossil

- steam generation is replaced by renewable generation rather than assuming that the fossil

- steam generation curtailed under Block 2 will all be replaced by exist ing NGCC capacity in the state at the current emission rates of those units. Commenters 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 b ase emission levels 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 emi ssion rate and asserted that the EPA's approach establishes 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 sign ificantly different capacity factors, the state average can be skewed by one unit with a high capacity factor. Commenters suggested that the baseline conditions used to establish the goals should be a multiyear average, which would better reflect actual op erating conditions at each NGCC using EPA's proposed approach to calculating the NGCC emission factor. Commenters added that using a multiyear average the emission rates for each NGCC produces a state NGCC emission rate that better reflects the characteris tics of the turbines in a state's NGCC fleets. Commenters requested that the EPA revise its calculation of NGCC emission rates consistent with a multiyear baseline approach and set an emission rate for all existing, affected NGCC units in the United States that is no lower than the emission limit in lbs CO2/MWh that the EPA finalizes for new NGCC units.

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 supply/power plant GHG emission performance standard and recent BACT dec isions, this 823 lbs/MWh value would be appropriate as a BACT emission limitation

- this emission rate is lower than could be expected of some, but does not reflect the capabilities of all existing NGCC units. Commenters stated that Washington State
recent ly evaluated and completed rulemaking setting an emission standard for new power plants, which determined that an emission rate of 970 lbs total 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 proposed 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 limitations of 95 0

- 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 the 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 pipeline, and convert combustion/boiler systems at Gibbons Creek, it would still not meet EPA's requirement of reducing CO2 emissions to 853 lbs/MWh b y 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 average baseline year NGCC CO2 emission rate, EPA should use the incremental NGCC CO2 emission rate. Commenters stated that using the average baseline year underestimates the additional NGCC CO2 emissions due to the re

dispatch. Commenters explained that most of the most efficient, lowest emitting units are already generating at or near the basis 70 percent capacity factor, wh ereas the units that would actually be re

- dispatched and contribute the most increase in net generation are the less efficient, higher

emitting units. Commenters stated the incremental emission rates of these higher

- emitting units must be used to estimate the additional CO2 emissions 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 required. Commenters stated that after appropriatel y determining the generator net capacity 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 compute the state average NGCC re

dispatch incremental CO2 emission rate and noted that, based on this computation, the incremental NGCC CO2 emission rate for Florida is 996 lb/MWh

- net, as opposed to the average rate EPA used of 864.

• For each NGCC generat or, calculate the baseline year net capacity factor using the eGRID net generation and newly determined net capacity rating. Subtract this number from 70 percent to determine the net capacity factor increase (or decrease) available. If a generator was oper ating above a 70 percent net capacity factor in the baseline year, the FCG

- EC believes that it is appropriate to adjust this downward to the 70 percent target for the purpose of calculating the goal. For each NGCC generator, calculate the baseline year ave rage CO2 emission rate by dividing the CO2 emissions (in tons) by the net generation MWh, times 2,000 to convert to pounds. Some due consideration is needed with respect to how representative the baseline period is for low capacity factor generators. For u nits operating at a low capacity factor, efficiency can be poor due to unit cycling,213 operating at low load points, and accumulated off

- line reserve auxiliary power. Some of the NGCC generators in the eGRID baseline data have calculated CO2 emission rates a s high as 3000+ lb/MWh

- net at a three percent to five percent capacity factor. It is reasonable to assume that such high CO2 emission rates would improve drastically if the unit was actually operated at 70 percent capacity factor. Therefore, the FCG

- EC sug gests a capacity factor test to determine whether the baseline CO2 emission rate should be limited. The suggested test is: (1) if the baseline year net capacity factor is greater 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 unit 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 limit the baseline year CO2 emission rate to a maximum of 1,250 lb/MWh

- net; this 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 annual net generation MWh available for r e

- dispatch using the net capacity factor 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 NGC C 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 available for re

- dispatch (again, increase or decrease). For each state, accumulate the total number of annual net generation MWh available for re

- dispatch from all NGCC generators, and the total annual CO2 emissions changed from all NGCC generators.

• For each state, divide the accumulated annual CO2 emissions by the accumulated annual generation a vailable. This is the incremental 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 rates.

Commenters did not agree with the use of the average NGCC emission rate for each state, based on actual 2012 operation, for all NGCC re

- dispatching. Commenters noted that the average emissions rate following re

- dispatching would be different 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 significant availability also have higher emission rates. Commenters st ated this means that, should the EPA require them to operate more by re

dispatching to these under

- utilized existing NGCC, the average emissions rate would necessarily increase. Commenters noted the table uses operating hours reported through Clean Air Mar kets Database (CAMD) to calculate availability (with 8,784 total hours in calendar year 2012) and the emission rate values are referenced from EPA's calculations (20140602tsd

- plant

- level

- date

- unit

level

- inventory_0.xls). Commenters stated this is not a uni que component of Florida's 2012 operation, rather it is a logical outgrowth of re

- dispatching. Commenters stated that, as the EPA acknowledges, "electricity generation conforms to the principle of least

- cost economic dispatch",214 this means that those NGCC w ith better heat rates will be dispatched first. Commenters stated that, if EPA is requiring more generation from NGCCs, the under

- utilized units will be those with poorer heat rates, and correspondingly higher CO2 emission rates.

Commenters stated the chal lenge with basing a future limit (a potential to emit constraint) on past actual emissions from a sampling of sources, is that the understanding of all potential impacts to actual emissions must be fully understood and considered. Commenters stated that, i n the development of standards that represent the emissions limit "achieved in practice" under Section 112 of the Clean Air Act, the EPA justifiably adds "variability" to actual emissions data. Commenters stated that, in the development of this rule, it ap pears 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. Commenters stated the EPA must consider whether or not the units relied upon repre sented modern, low

- emitting designs, or where their generation profile fit within the industry. Commenters stated that, even unit

- specific information that impacts efficiency and emissions rates for which EPA already has data were overlooked. Commenters st ated the EPA must evaluate which units utilized add on pollution controls (e.g., selective catalytic reduction), which can significantly lower oxides of nitrogen (NOx) emissions, albeit at the expense of a slightly poorer heat rate (and higher CO2 emission s rate).

Commenters stated the EPA's heat rate assumption for 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 under cons truction can achieve on a net basis. EPA should have used historical net heat rates of the actual units that will be dispatched to meet the target in determining the level of emission reductions possible under Building Block 2, similar to the procedures us ed 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 treatment of useful thermal output. Useful thermal output is not included in the final rule in determining goals. 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 M easures TSD for the CPP Final Rule supporting the final CPP.

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

According to c ommenters, the CO2 emission rates for 82 other NGCC units were calculated using the UTO

- related energ y output, and the commenters 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 emission rates that were even lower than the value EP A calculated for Pine Bluff, which the commenters summarized in a table included in the comments. Commenters also noted that while a single co

- generation facility reduced the overall state NGCC fleet CO2 rate in Arkansas by 8 percent, other states have mul tiple co

generation units that may have much more significant impact. As an example, c ommenters 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 energy output ; commenters summarized these results in a table in the comments.

Commenters stated that the Building Block 2 calculations for 24 states included the addition of UTO related energy output when determining the baseline NGCC CO2 emission rate. According
to the commenters, the impact of the added UTO energy output can be significant as is most evident in the reduction in the baseline NGCC CO2 emission rates for Louisiana (

- 21%), Michigan (

- 19%), Washington (

- 17%), and Texas (

- 14%).

Commenters reviewed the EPA's adjustment made for cogeneration units to determine useful thermal output (UTO) and stated the results of these calculations indicate that the EPA has over

estimated the UTO available from these units for re

- dispatching as electricity generation. . C ommenters stated the calculated emission rate based on net energy output for some of these units is extremely low; e.g., Auburndale Power Partners and Orange Cogeneration Facility have calculated emission rates of 724 lb/MWh and 755 lb/MWh, respectively. C ommenters stated the EPA is calculating an emissions rate from 20 year old facilities that is significantly better than what the newest, most efficient greenfield NGCC's can achieve under GHG BACT. Commenters stated that, compared to other facilities ident ified as cogeneration facilities in Florida that produced only electricity in 2012 (net electric generation was equal to net energy generation), it appears that EPA's estimate of UTO is inappropriate. Commenters stated that cogeneration facilities much new er 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 generation.

Commenters suggested that it is inappropriate to consider 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 r ates. Commenters stated the EPA should not default the NGCC emission rate to the "Emission Rate (lb/MWh) net electric" which EPA calculated to result in a value of 868 lb/MWh for Florida based on 2012 data. Commenters stated that, if the EPA considers addi tional 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 faciliti es are able to improve heat rate). Commenters stated the EPA actually included a state goal calculation 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 use ful thermal output plays. Commenters stated that the EPA appears to be claiming that UTO has very little impact in the calculated state goal, as the no

- UTO state goals presented in the docket are nearly identical to those proposed that do include UTO. Comm enters stated the EPA claims in this spreadsheet

-- that the rates in the 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 changing the NGCC emission rate to ignore UTO, it also changes the adjusted coal emission rate and significantly lowers the emissions and generation from "other" sources, among other possible changes.

Commenters stated the thermal energy produced at NGCC units should be converted into equivalent MWh and be included in the calculation for Building Block 2.216 Comment 51 : Commenters expressed concern that Building Block 2 strongly impacts some certain stat es, but not others.

Response 51 : The EPA disagrees. 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 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 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 reliability, fuel diversity, the need for an cillary services 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 r ate. 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:

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 existing 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 capaci ty factors but must have all capacity available to meet peak generation demands and to fill in generation when 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 variable 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 further stated that the target

- setting process embeds me chanisms (some of which may have been unintentional) 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 gas 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 negatively impacting the delivery of re liable, cost

competitive electricity to its consumers. Commenters stated t he EPA's analysis of NGCC re

dispatch 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 region as a whole. Commenters stated that, since this building block represents the bulk of the reduction required in New Hampshire, it is not reasonable to expect New Hamp shire to be able to recover 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 decad e in New Hampshire: the average consumption of coal and oil for power generation during the period between 2005 and 2012 represent decreases of 15, and 86 percent respectively, when compared to the average coal and oil consumption during the period betwee n 1990 and 2005; natural gas consumption in New Hampshire between 2005 and 2012 has increased by 450 percent, when compared to the average natural gas consumption between 1990 and 2005. Commenters stated these values illustrate the implementation of Buildi ng Block 2 that occurred prior to 2012 in New Hampshire. Commenters stated that, according to a separate analysis by the EIA, natural gas accounted for 21 percent of New Hampshire's net electricity generation in 2013, down from a record

- high of 37 percent in 2012. Commenters stated that, due to various factors including the exceptionally mild weather in 2012, the record

- high natural gas generation in 2012 has proven difficult to repeat and nearly impossible to exceed.

Commenters stated the Proposed Rule Bui lding Block 2 approach would result in excessive disparity in stringency among the states, penalizing states who have invested in natural gas combined cycle units to improve reliability (via reserve margin). Commenters asserted the EPA's analysis does not provide a reasonable basis for goals predicated on 70 percent NGCC utilization rates nor does it provide a reasonable basis for operating existing steam EGU's at an unsustainably low capacity factor.

States with limited NGCC

Commenters recommended that EP A generally provide for consistency between target

- setting and reasonably

- foreseeable compliance options so as to maintain the integrity and effectiveness of the program. Commenters stated that, as currently proposed, building block 2 requires little to

no reductions from states that have limited or no existing natural gas capacity, despite the fact that new NGCC and co

- firing of natural gas in heavily coal

- dependent states would result in significant reductions in state CO2 emission rates. Commenters state d 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 towards compliance with its state goal, omitting such potential in the goal computati on methodology could set less stringent state goals than some states could cost

- effectively and reasonably 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 uncommitted NGCC unit dispatch opportunity to accommodate the EPA's assignment of a 70 percent capacity factor level of operation.

States with lim ited coal218 Commenters asserted that there is ample fossil generation to displace with NGCC generation in historically coal

- dependent states, however, in states 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 coal 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 California 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 disproportionately targets states with underutilized NGCC capacity without any analysis concerning why the capacity is under

- utilized. Commenters stated, in Arkansas' case, the Union Power Partners Station is under

- utili zed due to transmission constraints among other reasons, issues that no amount of re

- dispatch, as contemplated by the proposed Rule, can address.

Commenters stated the inclusion of BB2 is one of the 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 inequitable results among the states. Commenters stated that Texas, Louisiana, and Arkansas have large amounts of natural gas fired generation, and as such, under EPA's methodology, a larger burden has been imposed upon these states to reduce CO2 emissions. Commenters asserted that states that have a prevalence of natural gas

fired generating capacity are required to reduce their CO2 emissions more than other states. Commenters stated that the State of Texas, with a current CO2 emissions rate (1,2 84 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% versus 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 required reductions of 20% or less, which is clearly an inequitable result.

Commenters stated Building Block 2 portends significant negative consequences for the Texas elect ricity market and the Texas economy and is patently unfair to the state of Texas. Commenters stated that, because Texas has invested heavily in NGCC capacity, existing coal

fired units are unfairly penalized. Commenters stated that states that rely primari ly 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 Block 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 allowed 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, efficient natural gas

- fired generation. Commenters219 noted that ERCOT has added substantial new efficient natural gas combined cycle generating plants over the last decade (14,775 MW of NGCC generating capacity since 2001) an d currently has more installed natural gas capacity than any other state. Commenters asserted that because of the existing base of natural gas fired generation capacity, Building Block 2 effectively requires a 52% reduction, or 72 million megawatt hours, i n Texas's utilization of coal fired electricity, which is more than the total coal generation in all but six other states. Commenters believe d that the EPA's methodology inappropriately discriminates against Texas because of the existing base of natural ga s fired generation capacity, noting that 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 impact to Texas.

State

- s pecific 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 experienced 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 presuming a 70% capacity factor can be achieved while serving as a base load resource is inappropriate. The commenters asserted that EPA needs to consider the measures and costs that would be incurred to replace the intermittent renewable resource reliability, peak power generation resource service electric and natural gas transmission support that the NGCC units currently provide.

Commenters stated the proposed Rule disproportionately burdens states with perceived underutilized NGCC capacity with higher emissions reduction. Commenters stated that, as a result, Arkansas Electric Cooperative Corporation and Arkansas are disproportiona tely affected by the emission reduction targets, a result that penalizes early adoption of a diverse portfolio.

Commenters expressed concern that, despite the current 57% level of emissions

- free power generation supplied by MEAG to the communities, result ing in an overall lb CO2/MWH emission rate well below EPA's proposed goals for Georgia, 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, becau se Florida's ESPS Building 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 st ated that the CPP fails to recognize the significant carbon emissions reductions already made by Louisiana through an increase in NGCC dispatch over the past several years. Commenters stated that Louisiana's natural gas heat rates have fallen 9.7 percent i n the last 10 years and natural gas

- fired emissions have fallen 11.2 percent.

Commenters expressed concern that, since pipeline companies that serve South Carolina have reported that their pipelines are "essentially full" and are fully subscribed, this me ans that additional pipeline facilities or system modifications 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 as serted that other states that have better220 gas pipeline capacity but no existing NGCC do not have their state goal affected by the re

dispatch of their coal units to natural gas. Commenters stated that the failure of this proposed rule to capture and accoun t for natural gas pipeline capacity presents practical problems on the achievability of the goals that are set for our state and, as a result, South Carolinians are being asked to bear a burden that is not commensurate with our current carbon intensity. Co mmenters concluded that the Clean Power Plan results in the inequitable treatment of South Carolina and other states as the national goal is derived from an inconsistent methodology.

Commenters asserted the EPA's Proposed Rule fails to consider that the r egions in which Heartland's customers are located, including portions of eastern South Dakota, southwestern Minnesota, and Iowa, are very rural and feature enormous distances between service territories. Commenters stated cooperative and municipal electric utilities were created in these regions partially because of these geographic challenges and 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 n atural gas infrastructure is severely limited in the Heartland footprint, making a build

- out of those resources cost

- prohibitive. Commenters stated that to now penalize our region because of the large distances between customers is unreasonable and discrim inatory.

Commenters stated that the underlying design elements 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 generation in Texa s. 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'. Commenters noted that states like Kentucky (1 percent) and Indiana (5 percent) exper ience very little impact to their coal fleets. Commenters stated this disparity and inequity is not allowed by 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 i n states like West Virginia 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 amount of West Virginia coal that can be sold to nei ghboring states. Commenters stated that because West Virginia does not have any NGCC units, its budget calculated by the EPA does not factor in Building Block 2. Despite this, the commenters believe d that West Virginia and the members of the West Virginia Coal Association will still suffer as the demand for coal plummets in favor of natural gas as a result of the EPA's assumption that all NGCCs could increase their capacity factor to 70%. Commenters indicated that arbitrary and dangerous assumptions underli e Building Block 2. Commenters stated that Building Block 2 would significantly reduce coal generation in many states and eliminate it entirely in 12 states.

Comment 5 2 : Commenters stated the EPA should favor mechanisms that don't create "winners and los ers."221 Response 5 2 : The EPA disagrees that the final rule has the impact 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 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, 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 reliability, fuel diversity, the need for an cillary services 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 r ate. 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 which 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 Blocks) and start again with a rule that complies with the CAA. The commenters stated the EPA's attempt to force re

- dispatch in states with little or no existing NGCC illustrates clearly that Building Block 2 arbitrarily creates winners and losers by punishing states that burn m ore natural gas for electricity generation and rewarding states that burn less. Commenters stated the EPA now seeks to fix this serious error by forcing

re

- dispatch to NGCC units that do not exist. Commenters opined this type of requirement is even

more ar bitrary and unreasonable than the existing Building Block 2.

Commenters stated that re

- dispatching to natural gas from coal will create winners and losers since not all utilities and/or generators in Utah own both types of plants. Commenters stated, for

e xample, one Utah utility operates the three largest NGCC plants in the state and, thus, re

dispatching 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 5 3 : Commenter s asserted that, in assessing the emissions reductions that Building Block 2 can achieve state

- by

- state, the proposal fails to account for the existing trend of the retiring role of the high

- emissions fossil

- fired plants, primarily coal, in favor of new lower zero

emission resources.

Response 5 3 : The EPA disagrees . We believe the rule sets achievable, but not maximum goals, and that the flexibility we provide allows states to 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 of CO2 emission reduction standards is regionally based. The 111(d) final rule requires that states develop plans that establish emission222 stan dards for affected EGUs. We are providing states with substantial flexibility as to how they structure those plans to achieve the 111(d) requirements. The EPA believes the approach is achievable and sound. 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:

According to the commenters, this means that the EPA has set 2030 as a goal that some states can easily achieve, particularly states that are coal

- dominated and coal

- intensive. The commenters stated that, to ensure that this block in the proposal has achieved additive reductions in carbon pollution, it should be adjusted to account 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, the EPA should ensure that block t wo will drive additional emissions reductions, and that all states should be expected to transition from hot coal, high

- emitting coal and gas plants to cleaner resources over time.

Comment 5 4 : Commenters stated that the EPA's re

- dispatch calculations con tain numerous fundamental calculation errors and data quality issues that result in the amount of potential re

dispatch to be substantially overstated.

Response 5 4 : EPA has reviewed calculations and data quality comments 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 calculations contain numerous fundamental calculation errors and data quality issues that result in the amount of potential re

- dispatch to be substantially overstated, including (1) incorrect data inputs; (2) inappropriate use of nominal nameplate capacity instead of the actual net demonstrated capacity; (3) incorrect inclu sion of units that do not meet the definition of an "affected source" subject to the proposed rule; (4) incorrect inclusion of NGCC units that were never constructed; along with (5) incorrect and inconsistent assumptions on units that were commissioned in 2012 or later. Commenters indicated that he data quality issues and methodological errors are not limited in scope, but are present in the building block 2 calculations for every state with NGCC capacity. Commenters asserted that the impact of these concer ns is significant, stating that correcting the errors would reduce the amount of NGCC re

- dispatch that EPA calculated by 51% in Louisiana and 92% in Ohio. Commenters provided a table highlighting the scope of building block 2 calculation issues that have b een identified for each state with NGCC capacity.

Commenters stated that any attempt to correct the commenters’ identified concerns or determine how these corrections impact state goal calculations, "flexible" compliance strategies, reliability evaluations and cost

- benefit analyses is too complex to complete within the public comment period. The commenters asserted that given the nature 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 NGCC capacity in Arkansas is currently 5,588 MW, but stated that Arkansas Electric Cooperative Corporation's analysis shows there is a maximum of 5,114 M W of NGCC capacity in the state.

Commenters noted that the NEEDS Version 5.13 database underestimated the capacity for the Warren facility at 570 MW. The design capacity of the facility is 1,358 MW. Including the correct capacity of the Warren facility would actually 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 and natural gas units: According to th e commenters, the EPA used the incorrect maximum capacity values for NGCC units, included some NGCC units that do not serve the power grid, and some units that are neither in operation nor under

- construction.

Comment 5 5 : Commenter s pointed out what the c ommenter s characterized as inconsistencies in the EPA's analyses and asked for clarifications.

Response 5 5 : The EPA agrees that data sets and calculations from the proposal can be updated. The EPA has modified its calculations for these building block issues. See the GHG Mitigation Measures TSD, Preamble V.D for Building Block 2 calculations, 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:

C ommenters raised the following issues about specific pages in the GHG Abatement Measures TSD:

Page 3

- 11: "Adding in the existing sources that were not yet online in 2012 (under construction) increases total NGCC generation calculated in the goal 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 power production in 2030 will be 1,743TWh, which is 178% of the 2012 value. That implies a significant increase in natural gas consumption versus today. For 2020 EPA predicts NGCC power production will be 1,369 TWh, which shows a mismatch between what is in this reference document and what is in the cost

benefit calculation memo. Page 3

- 12: "F or comparison, NGCC generation growth of 450TWh (calculated in goal setting) would result in increased 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 Btu/kWhr

- Commenters believe d 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 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 would224 increase by 50%. Although the amount of power produced by simple cycles mig ht be large enough to account for this discrepancy, the modeling results in the cost

- benefits memo show only a very small amount of power being generated by simple cycles. Table 3

- 6: The base case has an NGCC capacity factor of 52% which is significantly h igher 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: At the top of the page it is stated: "This is because only 29 state goals a re premised on the existing 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 confusin g and should be clarified.

3.2.3 Natural Gas Supply

This section discusses the supply of natural gas, including transmission and distribution systems and energy markets, to meet the needs of EGU’s as there 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 to this subsection which are organized by topics (comments) below. Responses are provided for these topics.

Comment 1: Alth ough natural gas may be cheap and plentiful now and production increases are projected, g eneral concerns were expressed about the effect of increased demand on energy markets, the adequacy of supply during extreme weather events, the lack of certainty of f uture supply and reliance on any single source of supply.

Response 1: The EPA agrees that natural gas prices have demonstrated historical variability. 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 supporting the final CPP for the EPA’s response to this
comment.

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

Commenter s noted that natural gas is cheap and plentiful 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.

Commenter s stated that since many chemistry processes require large amounts of electricity and natural gas, both as a r aw material and as an energy source, the U.S. chemical industry is highly attuned to how EPA's regulation for the electricity sector could affect energy markets. Commenter s agreed that natural gas production is increasing overall, but asked whether the inc reased production will be enough to offset the huge increase that will be required for power generation by switching to natural gas.225 Commenter s stated that although natural gas today appears to be plentiful and the cheaper alternative for power generation, that may not always be the case given the desire of many companies to export liquefied natural gas from the United States to other countries. Commenter s added that considering the historic volatility of natural gas prices, it seems likely that a reliance on natural gas will result in increased costs for electricity generation in coming years.

Commenter s stated that while re

- dispatch will ultimately reduce GHG emissions, reliance on this Building Block will increase the usage of natural gas. Commenter s asse rted that if this Building Block remains a component of BSER, options for mitigating this increased natural gas usage should be considered.

Commenter s stated that there are many critical issues and questions with a large

- scale fuel switch to natural gas f or power electrical generation purposes including, among others addressed in other sections of this document: What is the real long

- term U.S. natural gas supply? How does that projected natural gas supply balance with the new much larger increase in fuel s ource demand?

Commenter s stated that the nation's natural gas system 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 l ack of natural gas. Commenter s asked what changes in drilling rates and trenching for new natural 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. Commenter s also asked what economic and environmental impacts those shifts will have on those who use natural gas for other purposes such as residential heating.

Commenter s also expressed concern over the availability of natural gas and the tra nsportation of natural gas during extreme weather events. Commenter s 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. Commenter s referred t o the 2013

- 2014 winter which posed unique natural gas delivery and operational flexibility challenges for Brazos Electric, when the four natural gas pipelines servings its generation units placed restrictions on non

- ratable consumption that were mainly due to unrelenting consistently cold days. Commenter s stated that during a normal winter, a cold blast will last a few days before fading to warmer weather, which allows pipelines to recover. Commenter s stated that the consistent cold of the 2013

- 2014 winter did not allow sufficient time the natural gas pipelines to recover for the next cold period, so operational flexibility was limited

on non

- extreme days. Commenter s stated that the assumption of readily available natural gas is inaccurate in the Brazos Elec tric's experience and for the nation as a whole.

Commenter s stated that analysts at the Center for Strategic and International Studies and the Rhodium Group report that natural gas demand for compliance with the CPP may be three times greater than the EPA projects in the absence of aggressive energy efficiency programs. Commenter s indicated that the CPP will lead America to greater dependence on natural gas as a main source of electric generation, and that CSIS forecasts that natural gas use could more than double as a percent of total electric generation, rising from 19% in 2010 to 43% in 2020 (CSIS at226 17, national scenario without energy efficiency) with the share of coal generation declining from 46% to 21% over this period due to higher demand for natura l gas.

To develop a stable natural gas supply market to support stable electric power production, Commenter s recommended that the EPA establish firm, clear and predictable environmental rules on natural gas development, transportation and 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 future. Unlike coal, which has locked in long

- term cost certainty, according to the commenters, natural gas produc tion is subject to market and regulatory uncertainty which could create substantial price increases. Historically, the commenters noted natural gas markets have been extremely volatile and this is likely to continue, particularly if proponents of LNG expor t are successful.

Commenter s 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 price

- not to mention the specter of additional en vironmental and drilling regulations, which could have a serious impact on future production and price levels.

Comment 2: The U.S. possesses abundant natural gas supplies capable of meeting greater demand from the electric sector and other industries; com petitive markets must remain liquid to aid efficient delivery of natural gas to customers, adequate infrastructure (including pipeline capacity) and an efficient and predictable siting and 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 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 indicat ed that the U.S. possesses abundant natural gas supplies capable of meeting greater demand from the electric sector and other industries. Commenters agreed that natural gas supplies are adequate at reasonable prices. Commenter s noted he has been involved i n 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 rule relatively easy, or easier than we would have thought a few years ago.

Commenter s stated that to facilitate the greater use of natural gas

- fired generation, and its corresponding emissions benefits, competitive natural gas markets must remain liquid to aid efficient delivery of natural gas to customers. Commenter s opined that a critica l component of a healthy and liquid natural gas market is adequate infrastructure and an efficient and predictable siting and permitting process for the new infrastructure that will be needed in response to shifts in the sources of natural gas supply and d emand. Commenter s stated that new pipeline capacity will play an essential role in transporting gas to market. According to the commenter s , the227 natural gas industry has shown its ability to quickly expand and improve natural gas infrastructure in the past and can continue to do so given clear market signals prompting investment. Commenter s added that regulators, including the FERC, should remove any structural barriers that inhibit the construction of new natural gas pipelines and should support market stak eholders as they seek to ensure adequate and timely infrastructure is in place to support the greater use of natural gas.

Commenter s stated that the natural gas market features a wide array of contracting tools that facilitate efficient and timely natural gas use

- asset management agreements, pipeline park and loan services, storage contracts, and no notice service are a few options at the disposal of customers. Commenter s indicated that these tools, when secured in advance as part of a diverse procurement strategy, can assist generators in reliably meeting their obligations, while physical and financial hedging tools can help mitigate price swings and exposure to the spot market. Commenter s concluded that taken together, these procurement tools can assist power market participants in accessing robust and reliable supplies of natural gas for their needs.

Commenter s stated that it has long advocated for EPA to update its assumptions regarding the supply and availability of natural gas, citing comments made on the proposed MATS and 2012 GHG power plant NSPS and praising the EPA's approach to evaluating and updating its projections on natural gas production based on the EIA's AEOs. Commenter s asked the EPA to continue to use up

- to

- date assessments of natural gas supply and availability in this and future regulatory actions. Commenter s encouraged the Agency to further review EIA's AEO 2014, the final release of which projects increased production of natural gas and increased natural gas

- fired generation relative t o EIA's AEO 2013 used by EPA to calibrate the IPM modeling platform used to evaluate the potential impact of the proposed rule.

Commenter s stated that a recent analysis by Bentek supports the conclusion that natural gas production is expected to grow signi ficantly across the country

. Commenter s indicated that such production growth has driven, and is driving, large investments in infrastructure to move gas from supply basins to demand markets. Commenter s added that because much of this increased production will originate from the Northeast producing region, many infrastructure projects are adding bi

- directional capability to existing pipelines to increase their operational capacity. According to the commenter s , this bi

- directional feed relieves pipeline cap acity constraints and hence creates new pipeline flexibility. The commenter s said this benefit was recognized when MISO completed the third and last phase of its evaluation of the ability of Midwestern pipeline infrastructure to support significant replace ment of retiring coal capacity.

Comment 3: Neither the Proposed Rule nor its Technical Support Documents address concerns about the historic variations of EIA projections of natural gas supply.

Response 3: The EPA disagrees. In response to additional analysis 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 Mitigation Measures TSD for the CPP F inal 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.

Commenter s noted that for the RIA, the EPA uses forecasts of natural gas demand from the EIA, which acknowledges that its historical record on forecasting natural gas prices is poor (see the latest EIA retrospective review). In addition, Commenter s believe d that EIA 's methodology underestimates industrial demand for natural gas. Commenter s stated the belief that industrial demand for natural gas is increasing beyond EIA's predictions and the demand will continue to increase in 2017

- 2020 with the construction of the a nnounced projects in the chemical industry.

Commenter s stated that projections of the future natural gas supply are uncertain because shale gas reserves are more difficult to project than conventional gas reserves. Commenter s noted that the EIA's projects U.S. natural gas production to increase from 23 trillion cubic feet in 2011 to 33.1 trillion cubic feet in 2040, a 44% increase, almost all of which is from projected increases in shale gas production. Commenter s indicated that due to the fact that shale g as 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. Commenter s asserted that nothing in the Proposed Rule or TSDs acknowledges these downward projections or what that could mean for long

- term supply

- without new natural gas production from shale gas (and oil) formations, it would be extremely difficult to achieve the CO2 emissions reductions required by the Proposal. Commenter s stated that natu ral gas production from conventional supplies (found in reservoirs) has decreased over the last thirty years and is expected to continue to do so. According to the
commenter s , various sources have made widely divergent predictions, so it remains an open
qu estion just how much shale gas exists in the U.S., and more fundamentally, what the production rate will be. Commenter s indicated that all conventional gas wells tended to have lower production after 10, 20, or 30 years and that available shale gas product ion records from a few states (predominantly the Texas Railroad Commission 131) show shale gas wells tend to deplete significantly after about three years.

Commenter s stated that insufficient information exists thus far to predict whether the dry shale
nat ural gas plays in the Utica, Marcellus, and other formations will be as lucrative as those in the Williston Basin and the Eagle Ford Shale formation. Commenter s added that the availability and timeliness of drilling reports varies among states, further com plicating 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 or wet and dry data when reporting on annual drilling and production reco rds. According to the commenter s , such commingling can inadvertently provide an overly optimistic picture of shale gas production.

According to commenter s , estimates regarding production from shale gas formations have varied widely, and had to be adjusted downward several times due to a variety of factors, including poor methodology and inaccurate or untimely information, among others. Commenter s said that the EPA appears to take it on faith that EIA's current long

- term estimates of low

- cost, plentiful dome stic natural gas supply are accurate. Commenter s urged the EPA to examine these projections carefully and to incorporate analyses from other respected sources to arrive at a more balanced assumption about future supply. Commenter s 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 commenter s , records are mi nimal for dry gas production from the Marcellus and Utica formations. Commenter s stated 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 prem ature to assume these formations will be able to produce the gas needed for large

- scale and long

- term fuel switching.

Commenter s stated that, while the EPA relies on EIA natural gas forecasts in determining, under BB2, that redispatching large amounts of c oal

- fueled electricity to NGCC units is economically viable (79 FR 34857), it has become increasingly apparent that EIA forecasts for natural gas differ substantially from outcomes. Commenter s provided the following additional information :

• As EPRI reports, "history has demonstrated the price of natural to be highly volatile, and multi

- year forecasts have consistently been inaccurate." A striking example of this difference is in 2002, when EIA projected the cost of natural gas to electric utilities in 2006 w ould be $3.85 per thousand cubic feet (Mcf) (2006 dollars). The actual cost was $7.56. Further, in 2003, 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 1998 to 2006 revealed that:

1. On average, a one

- year ahead

- average percentage forecast error for wellhead natural gas prices of 16%, with the errors steadily increasing to more than 45% with the four

year

- ahead forecast. More than 54% of the errors for the one

- year

- ahead forecasts can be attributed to systematic bias;

2. Natural gas consumption in electric generation is consistently b elow actual observations. The absolute error for the one

- year

- ahead forecast was more than 900 bcf

- more than 15 percent of consumption in the electric sector for that year;

3. Dry natural

- gas production is consistently over

- predicted. The absolute errors ar e quite sizeable. The two

- through four

- year

- ahead forecast 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 coming from the NEMS model. These biases emerge over a much shorter period (4

- year horizons) than the 10

- year plus scenarios that EPA is conducting for this rulemaking.

• 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 bre ached $7.46/MMBtu and during February reached $7.78/MMBtu

-230 well above EIA's previously forecasted price for that same time period. AEO 2013 did not project delivered natural gas prices to the power sector to reach $7.00 until 2035

- a projection that was prov en inaccurate 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 earlier than EIA forecasts.

• Both the AEO 2013 and AEO 2014 reference cases contain dubious and unsustainable projections. These include:

− The projected demand for natural gas is significantly underestimated. EIP predicts that natural gas demand will increase substantially to replace the lost generation from current and projected coal plant retirements and higher consumption from the industrial sector as additional 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 forecast a natural gas demand increase of 7 percent between 2013 and 2022. NMA's analysis indicates that the combination of increased power and industrial sector consumption will increase demand in that period by 15 perce nt

- a 1.83 Tcf difference from the EIA estimate. NMA's analysis and EIA's forecast begin 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 2020. At a minim um, EPA must look at the retirements of coal

- fired EGUs that are known and forecasted and calculate the natural gas requirement to replace 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 industrial sector consumption;

− The forecasted natural gas prices are to o low to support the supply growth rate AEO 2014 forecasts, and are well below levels necessary to sustain the supply growth other analysts peg at twice the level forecasted by EIA. With shale gas comprising a greater share of overall supply in all forecas ts, neither AEO 2013 nor 2014 account for the steep decline rates for shale wells and the impact on ultimate recovery. The steep decline rates require a constant drilling treadmill of more expensive wells at a faster pace just to maintain current productio n levels. The recent shift of drill rig deployment 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 concluded that gas prices in the range of $8.00 to $9.0 0/Mcf are required to break even on a full

- cycle basis. Notably, the growth rate of dry gas production has slowed since 2011 with lower pricing. In 2013, the growth rate was less than 1 percent.231 Comment 4: T he EPA failed to support its claims that suffic ient natural gas will be available to fuel all of the additional NGCC generation.

Response 4: The EPA disagrees. The EPA has decided not to include 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 support the calculations for the establishment of CO2 emission performance rate s. See section V.D of the final rule preamble of the CPP, Chapter 3 of the GHG Mitigation Measures TS D 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:

Commenter s stated that the EPA's analysis of the ability of the country to sh arply 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. Commenter s noted that, while the EPA recognizes that it took twelve years, from 2000 to 2012, to increase natural gas production by 32 percent, that is the same level of increase in natural gas production that would be needed to satisfy EPA's building block two 70 percent NGCC capacity factor assumption only this time that increase would have to occur much more quickly and from a higher baseline. Commenter s stated that, even if those efforts began today, they would have to be completed by 2020, which is just over five years away. Commenter s 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 be left before the significant amount of additional natural gas supply would be needed to support EPA's proposal. Commenter s stated that the EPA has no basis for assuming that the unprecedented growth in natural gas supplies from 2000 to 2012 can be similarly replicated in half of that time or less, particularly since each additional cubic f oot of gas is likely to come at incrementally higher price than the previous one and given the large pipeline infrastructure investments which must be planned, permitted and constructed in that same time period.

Comment 5: T he EPA needs to address compet ing demands for natural gas, such as LNG exports, Canadian gas, compressed natural gas and U.S. manufacturing.

Response 5: The EPA disagrees. EPA believes that estimates of natural gas supply are more than adequate to support the calculations for the establishment of CO2 emission performance rate s. See section 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 analysis of the CPP

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

Some commenters stated that to determine whether the 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 facilities which have recently been approved. As an example, Commenter s estimated that 3.6 trillion cubic feet (TCF) per year have already been approved and another 3.6 TCF is under review by DOE (citing t able of proposed LNG export projects in N. Powell and S. Sullivan, "How LNG export projects could slot into DOE's reshuffled queue", SNL Data Dispatch, June 2, 2014). Commenter s recommended that the EPA clarify its assumptions for the potential magnitude o f LNG exports to the potential price of natural gas.

Commenter s stated that in recent years, there have been a significant number of proposals to bring large industrial facilities and LNG export terminals 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, c ommenter s noted that the Industrial 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 would represent a significant increased industrial demand for natural gas. Commenter s 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 such applications to export L NG, and has more than 20 additional applications pending for review. Commenter s 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 n atural gas demand could have on natural gas prices, and consequently the ability for natural gas power plants to achieve the target capacity factor used to calculate the state emissions rate in the proposed guidelines.

Commenters stated that the EPA has fa iled to consider the impact exports of LNG and non

electric utility demand will have on natural gas supply and prices. Regarding LNG exports,

c ommenter s indicated that given the recent applications to the DOE for approval to construct new LNG export termin als, U.S. producers will begin exporting natural gas to European and Asian markets where demand for gas is also increasing and prices are higher than in the U.S. Commenter s added that the domestic demand for natural gas is also projected to increase for us e by manufacturers as feedstock and by the transportation sector as a fuel source. According to
commenter s , the EPA apparently has not examined any of these issues that could impact the supply available for electric utilities or the price they would pay fo r the gas. Commenter s asserted that the Agency needs to look at these issues 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.

Commenter s stated that shale gas production has increased domestic supply significantly and reduced prices, which, along with international demand for natural gas, have led to recent efforts by domestic producers to export their gas as LNG. Commenter s added that Euro pean 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 commenter s , while it is still unclear how much domestic natural gas may be exported, it is very likely that exports would pu t upward pressure on domestic prices, which would impact electricity rates. Commenter s asserted that the EPA needs to factor this real possibility into its assumptions about how much fuel switching from coal to natural gas can occur to reduce CO 2 emissions from the utility sector.233 Commenter s stated that more than 25 applications for LNG export terminals have been filed with DOE, and several have been approved. Commenter s conceded that it is unclear how much natural gas will be exported, but indicated that g iven the great demand for natural gas in Europe and Asia, where prices are much higher than they are in the U.S., it is very likely the U.S. will start exporting LNG, which will impact domestic prices, 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 substantial construction time, c ommenter s pointed out that the Sabine

- Golden Pass project that was approved in late September is curre ntly an LNG import terminal, whose owners plan to change the directional flow to enable the export of an amount of gas that is approximately three percent of all U.S. natural gas production per day, so that the facility will begin exports in the near futur e.

Commenter s 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. Commenter s added that if Canada exports some of its natural gas that it currently supplies to the United States, which will also put upward pressure on gas prices. Commenter s also pointed out that U.S. shale gas can be exported through Canadian LNG terminals to other international markets.

Commenter s stated that Asia petrochemicals manufacturers 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. Commenter s indicated that this LPG would replace costlier naphtha, a byproduct from oil and gas wells, as a raw material for the manufacturing of chemical products and p lastics. Commenter s said that such Asian imports of LPG will reduce U.S. domestic supply of shale gas.

Commenter s stated that many transportation companies have announced plans to move to compressed natural gas (CNG), some of citing the lower price of natu ral gas and others citing meeting other environmental regulations. Commenter s 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 P roposed Rule. According to the commenter s , 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 c urrent (2014) British gas demand (approximately 3 million barrels of oil). Commenter s concluded that with international CNG running at about double the price of U.S. natural gas in Europe ($10 Mcf) and almost four times the price of U.S. natural gas in Asi an import markets (approximately $20 Mcf), the export of CNG for transportation markets is not implausible.

Commenter s stated the EPA failed to assess the economic effects on other economic sectors from higher natural gas prices or potential gaps in the i ncremental natural gas supply. Commenter s noted that many sectors of the economy rely on natural gas and have increased natural gas consumption since pre

- recession levels, including the power, industrial, and transportation sectors. Commenter s stated that natural gas exports will begin to coincide with the accelerated retirement of coal generators. Commenter s noted that (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 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. Commenter s 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 depe nd upon natural gas.

Commenter s stated that recent history provides more than ample experience on the scope and depth of the consequences of over

- relying on natural gas. Commenter s stated that, between 1997 and 2009, the natural gas market experienced fiv e significant 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. Commenter s stated this occurred even when natural gas demand fell

- but p rices increased by 160%. Commenter s 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 growth in natural gas demand by all se ctors. Commenter s concluded that there is little question of the direct correlation between manufacturing job losses and higher and more volatile natural gas prices during this period

. illustrates a decline in employment in the manufacturing sector from 1995 to 2005 (a reduction of over 3,000 jobs)

. Commenter s stated that Nick Akins, 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 be tween 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 14 months, we face a real possibility that we wil l have to make that choice more often in the future."

Comment 6: The IPM ignores important effects and feedbacks outside the electric sector, the electricity sector represents a only a portion of natural gas consumption, and as a result, the EPA

must reas sess its proposal in order to more fully estimate and reflect the significant effects and feedbacks it has on the U.S. economy.

Response 6: The EPA disagrees. This comment is not correct about the IPM model. The natural gas component of the model includes all natural gas consumption, not just the power sector. See http://www.epa.gov/airmarkets/powersectormodeling.html http:epa.gov/powersectormodeling for documentation.

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

Commenter s stated that IPM is a multi

- regional model limited to analyzing the U.S. electric power sector that ignores important effects and feedbacks outside the electric sector, which include: (1) significant changes in the use and trade 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. Commenter s asserted that as sessing these effects is important because the electric sector represents only a portion of the natural gas consumption in Alabama, Florida, and Georgia.235 Commenter s stated that nationally, the electricity sector represents even less of a share of total

na tural gas consumption

- approximately 34 percent in 2013. Commenter s concluded that the EPA must reassess its proposal in order to more fully 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 consumption from the electricity sector by 2020 in Alabama, Florida, and Georgia, and expressed concern about the adequacy of the natural gas supply

.

Comment 7: T he EPA's assessment of energy requirements and available natural gas supply reflects a fundamental misunderstanding about the distinction 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 section s V.D , VIII.A and VIII.C of the final rule preamble of the CPP, Chapter 3

o f the GHG Mitigation Measures TSD for the CPP Final 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 the CPP Final Rule supporting the final CPP

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

Commenter s stated the EPA uses EIA's AEO 2012 estimates that the U.S. possesses 2,214 Tcf of technically recoverable resources (TRR) of natural gas an d then asserts that at current rates of consumption, the resources are enough to supply over 90 years of use (RIA at 2

- 23). Commenter s stated that only a small subset of the TRR can be considered "reserves" (about 24 years currently of potential supply) re asonably available for consumption. Commenter s stated this distinction is especially important in the context of the proposed rule because EPA policies will drive increased reliance on natural gas for power generation and preclude the deployment of the nat ion's enormous coal reserves

- the most cost

- effective fuel for base load power generation.

Commenter s stated that, while the TRR are divided into three categories, speculative, possible and probable, only the probable TRR have been tested by drilling and k nown to be, in fact, technically recoverable. Commenter s stated that approximately 30 percent of the TRR is classified as probable, only about half of the probable TRR is likely to become reserves, and, thus, only 15 percent of the entire TRR are likely to be considered as consumption reserves. Commenter s 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 over the past two years (26.60 Tcf) and converting the probable TRR to res erves equals about 332 Tcf that can be added to the already proved reserve base of 305 Tcf. Commenter s concluded that the combined total of 635 Tcf leaves 24 years of supply at current consumption rates.

Commenter s 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 carry consequences for the other sectors236 consuming natural gas and the economy as a whole. Commenter s stated the EPA's assessment lacks any analysis of the economic effects of the likely prospects of either higher natural gas prices or a gap in incremental natural gas supply. Commenter s stated that less than a quarter century of nat ural gas reserves is a thin supply margin to risk on a policy that will have profound effects on the economy but not make any material difference in direct global temperature changes.

3.2.4 Technical Considerations

This section discusses technical considerations pertinent 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 EGUs, and coordination of the natural gas and electric systems.

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

Comment 1: Some commenters agreed that the natural gas delivery infrastructure will support the level of re

- dispatch proposed under building block 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 the CPP Final Rule supporting the final CPP.

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

Analysis indicates ad equate infrastructure.

Commenter s stated that the availability of transport capacity is illustrated by the mapped results from the draft Eastern Interconnection Planning Collaborative (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 electric generation customers over 5

- year and 10

- year planning horizons. According to the com menter s , two EIPC maps showing pipeline capacity conditions during a peak winter day, one under a reference gas demand scenario and the second under a high gas demand scenario in modeled year 2023, indicate that the extent of fully utilized pipeline segmen ts is not dramatically different between the two Winter 2023 scenarios and that there are natural gas pipeline systems not fully utilized under either set of Winter peak day conditions. Commenter s also stated that a second set of EIPC maps shows EIPC's mod eled peak summer day pipeline conditions and that when compared 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 pipeline sys tems in the summer months under either scenario.

Commenter s stated that the limiting factor to a sustained increase in generation of FPL's NGCC units would be the availability of natural gas supply, including both commodity and transportation, in that new natural gas infrastructure would be needed throughout FPL's service territory to meet this need. Commenter s believe d , however, 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 positioned to continue and, if necessary, expand its pursuit of additional natural gas capacity and future natural gas generation. Commenter s noted that in December 2012 FPL issued a Request for Propos als 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 commenter s , the Sabal Trail Transmission and Florida Southeast Connection pi pelines are progressing through the development process

- a certification application for the Florida Southeast Connection pipeline has been filed with the Federal Energy Regulatory Commission and an application for Sabal will be filed by the end of Novemb er 2014. Commenter s indicated that construction of the proposed 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.

Commenter s r eferenced several infrastructure studies and stated that, when looking across regions broadly, these studies support the significant availability of delivered gas supplies for electric power generation. Commenter s stated that, while these studies address n atural gas availability for gas

- fired electric generators on natural gas peak demand days, they do not directly assess annual natural gas availability for gas

- fired electric generators. Commenter s stated that, given the often significant availability of de livered natural gas for electric power generation on peak gas demand days, one can infer an even greater amount of gas available for electric power generation throughout the year. Commenter s stated that recent pipeline capacity have been significant and pi peline capacity will continue to grow. Commenter s also stated there are several factors that make New England unique and an inappropriate example to use for comparison with other regions of the U.S. Commenter s stated that natural gas infrastructure additio ns have been significant since 2007. Commenter s provided a Figure 4 ( titled: “ U.S. Pipeline Capacity Additions, EIA Pipeline Data ” ) and stated that the cumulative infrastructure additions more than doubled between 2007 and 2013 when compared to the 2000 th rough 2006 timeframe. Commenter s referenced Appendix A of their 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 onl ine by 2018.

Commenter s stated that, even absent EPA's proposed section 111(d) rule, analysts predict increased reliance on natural gas within the electric power sector as older, less efficient generating facilities are retired from the system. Commenter s 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 the EIA as part of its AEO series. Commenter s stated that the AEO 2008 project ed 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 projected 25 percent increase in AEO 2013.238 Comme nter s 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 for natural gas price and supply.

Commenter s noted that the height of natural gas consumption occurs during winte r months mainly due to residential and commercial seasonal heating needs. Commenter s provided a Figure 6 ( titled: “ Average U.S. Monthly Natural Gas Consumption ”) and stated that since 2001, U.S. natural gas consumption during non

- winter months is 64 percen t of the annual maximum consumption, on average. Commenter s noted that, while New York and New England's pipeline infrastructure is constrained to serve daily peak natural gas demand during winter months, the rest of the U.S. does not suffer such infrastru cture constraints. Commenter s stated that, as with all systems delivering energy to consumers during extreme weather events, the system can be stressed; however, these events are infrequent across the years and relatively short in duration. Commenter s stat ed 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 curtailments. Commenter s stated that, when looking across regions more broadly, the following studies support the significant availability of delivered gas supplies for electric power generation:

• The FERC determined that if similar conditions to last winter emerged this winter, Mid

- Atlantic d emand would be slightly higher; however, natural gas spot prices at certain liquid trading points would likely not be as severe due to new pipeline capacity coming online by the start of winter.

• The "Natural Gas Infrastructure Adequacy in the Western Inte rconnection: An Electric System Perspective" interim report for the Western Interstate Energy Board found that "existing gas transportation infrastructure will generally be adequate to meet the regional needs of the electric sector except under extreme win ter 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 generators' gas supply capacity "is well in excess of their peak natural gas needs."

• The Midcontinent Independent Transmission System Operator ("MISO") commissioned a study to examine the availability of pipeline capacity to serve natural gas

- fired generation in its footprint. The stud y found that, "[o]verall, pipeline capacity in the MISO Midwest is positive and continually improving due to shale gas developments and accommodating pipeline expansions, contract expirations and the benefits of increased pipeline reticulation underway in the Eastern Interconnect."

Commenter s stated the existing NGCCs in Arkansas have sufficient gas supply to run at 100% capacity now under most conditions. Commenter s stated the EPA's Air Permits Program Database shows each of Arkansas NGCC operating at or above its rated capacity in some hours of each year, so they clearly have adequate connections to the gas pipeline system. Commenter s stated that, considering the enormous supplies available from the Arkansas wellheads and239 pipelines, no additional infrastr ucture is likely to be necessary for Arkansas NGCCs to operate at 70% capacity factors. Commenter s stated Arkansas produces 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 ha s only a total of about 5,100 MW of coal plants subject to reduced usage or retirement, and had only about 700 MW of underutilized NGCC capacity in the average hour of 2012. Commenter s noted Arkansas also lies on a massive pipeline corridor from the gas fi elds of Oklahoma, Texas, and Louisiana to the Midwest 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 ave rage allows states to comply.

Commenter s stated that the proposed rule provides flexibility for states to comply by allowing them to average the CO2 emissions rate associated with affected units across a state, within a year, for each year during the 2020 to 2029 period. Commenter s 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 (which c ommenter s recommended as discussed elsewhere in this document). Commenter s concluded that all of this suggests that the existence of a current infrastructure constraint need not preclude CO2 reduction through re

- dispatch.

Commenter s stated that the seasonal pattern of demand 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. Commenter s disagreed wit h some other commenters' suggestions that the EPA's building block 2 assumptions are unrealistic due to existing constraints in natural gas supply. While conceding that transport constraints exist during some peak demand days in some regions of the country

, c ommenter s stated that transport capacity is still available for re

- dispatch in unconstrained regions and off peak times of the year. Commenter s indicated that natural gas consumption in the United States peaks during the winter home heating season and i nterstate gas pipeline capacity is often fully utilized during at least some of that season, but in other times of the year pipeline capacity is often available unless it is used to fill market

- area storage or for other purposes. Commenter s stated that thi s capacity could allow existing NGCC units to increase generating output without infrastructure expansion.

Commenter s stated that certain stakeholders' concerns regarding the adequacy of natural gas pipeline infrastructure to accommodate the increased uti lization of existing NGCC units appear to be unfounded and provide no justification for reducing the utilization rate assumption in Building Block 2. Commenter s referenced the NODA (79 FR 64543, 64546) and noted that some stakeholders have challenged the 7 0% utilization factor that provided the basis for Block 2 by pointing to alleged deficiencies in natural gas pipeline infrastructure. Commenter s 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 may not be able to achieve a 70% capacity factor today, due to their geographic location and existing pipeline constrai nts, does not provide a basis for applying a lower capacity factor in the calculation of Block 2. The commenter s stated that, in the event there are existing NGCC units that cannot increase their utilization due to existing pipeline constraints, the projec ted expansion of the natural gas pipeline system leading up to240 2020 should be more than sufficient to ensure additional pipeline capacity and flexibility in meeting any increased demand for natural gas caused by the Clean Power Plan. The commenter s referen ced EIA and FERC reports and stated this is underscored by the significant number of natural gas pipeline projects under development (including expansions, new pipelines, laterals, and reversals) that will collectively provide the capacity 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/indus

- a ct/pipelines/horizon

- pipe.pdf (indicating that 21.96 BCF/d of new interstate pipeline capacity is in development). Commenter s stated that, accordingly, claims about insufficient natural gas pipeline capacity provide no basis for EPA to amend its Block 2 be nchmark.

New England's infrastructure is not representative of the U.S.

Commenter s indicated that concerns regarding gas deliverability and electric supply in New England are not representative of electric

- gas conditions across the country, illustrating this with a figure from EIPC's Target 1 Report, titled "Baseline Existing Natural Ga s

- Electric System Interfaces" (EIPC, Target 1 Report, Table 7, available at: http://www.eipconline.com/Gas

Electric_Documents.html). Commenter s went on to note that the gas and electric industries, along with federal and state regulators, are engaged in mu ltiple efforts to assess and, where needed, bolster the adequacy of fuel transport and storage systems. Commenter s believe d that for this reason, it is likely that any critical infrastructure constraints can be addressed.

Commenter s stated there are sever al factors that make 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 support geologic gas storage like the rest of the U.S. Due to this issue, liquefied natural 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; hence, if market rules do n ot allow for cost recovery, it is difficult for customers to afford such services.

• Second, New England demand is highly seasonal. Because the total gas consumption swings greatly between summer and winter, significant amounts of pipeline capacity are av ailable for electric generators during non

- winter months. This seasonal demand profile, coupled with cost recovery challenges in the region's electric market rules reduces the incentive for electric generators to commit to firm pipeline capacity.

• Third, New England ISO electricity market scheduling differs from that of New York ISO, thus creating a disadvantage for New England 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, the incremental pipeline capacity provided by the Algonquin Incremental Market Project ("AIM") is241 expected to greatly reduce volatility in the region. This pr oject is scheduled to come online in November 2016.

FERC actions are enhancing the infrastructure.

Commenter s stated that improvements to gas market design such as those currently being considered by FERC will considerably enhance gas supply and deliverabi lity 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. Commenter s stated that while some additions to today's natural gas delivery infrast ructure may be necessary before 2030, the current natural gas delivery infrastructure is robust and is capable of delivering significantly more natural gas to the power fleet than it does today. Commenter s indicated that this is particularly true on an

ann ual basis, but is also true even during peak periods of demand. According to the commenter s , even during extreme cold weather conditions when aggregate 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 deliver more gas. Commenter s 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 ma rket design better serves natural gas

- fired electricity generators. Commenter s stated that FERC issued a Notice of Proposed Rulemaking on March 20, 2014, regarding proposed revisions to the scheduling practices used by interstate natural gas pipelines to s chedule natural gas transportation services (79 Fed. Reg. 18, 223). According to the
commenter s , FERC proposed, as part of a series of orders, to revise its regulations to better coordinate the scheduling of natural gas and electricity markets "in light of increased reliance on natural gas for electric generation..." because "this trend is expected to continue, resulting in greater interdependence between the natural gas and electric industries" (79 Fed. Reg. 18, 224).

Commenter s stated that beginning in 20 12, FERC hosted 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. Commenter s noted that in its April 2013 technical conference, market participants 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 the most efficient s cheduling systems for both industries (citing "Staff Report on Gas

- Electric Coordination Technical Conferences," Docket No. AD12

- 12

- 000, available at http://elibrary.ferc.gov/idmws/File_List.asp). Commenter s stated that the FERC proposal was issued in resp onse 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 natural gas to power plants.

According to c ommenter s , the FERC action proposes to align the timing for gas pipeline scheduling and delivery to the timetables and utilization patterns prevalent in the electricity markets (e.g., the morning ramp up), and also proposes to increase flexibility for gas

- fired generators by requiring pipelines to provide additional delivery scheduling opportunities so that power grid operators and power plants can better adjust to contemporaneous market and operational conditions. Commenter s indicated that in the proposal, FERC presented spe cific proposed reforms to existing natural gas industry scheduling practices and also provided market participants within the natural gas and electricity industries an opportunity to collaboratively develop alternatives for changes in scheduling practices, through a consensus standards

-242 development process at NAESB. Commenter s stated that after a series of meetings and votes over the summer 2014, representatives of the two industries reached a series of agreements to enhance coordination and NAESB subsequent ly filed a series of consensus standards with the Commission on September 29, 2014. Commenter s added that while there remains an open issue regarding the start of the gas day, it is highly likely that FERC's final order, when issued, will include a series of new scheduling and delivery standards which will enhance the operational capabilities of natural gas

- fired power plants and the deliverability of natural gas.

Comment 2: Commenter s stated that, if additional pipeline capacity is needed to support compl iance with the Clean Power Plan, INGAA is confident that the industry will be able to respond to this demand, although the ability to respond in a timely manner depends on several factors including making improvements in the permitting process

.

Commenters referenced a 2014 NYISO reliability study and stated that, because of this constraint, it is not possible to access all the installed NGCC capability that is located in UPNY (NYISO's 2014 Reliability Needs Assessment at pp. 24 and 28, available at http://w ww.nyiso.com/public/webdocs/markets_operations/services/planning/Planning_Studies/ Reliability_Planning_Studies/Reliability_Assessment_Documents/2014%20RNA_final_091620 14.pdf.)

Response 2: 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 Measures 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:

Commenter s stated that pipeline companies do not build 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 creditworthy shippers commit to long

- term (e.g., 15

- year) contracts for firm transpor tation service. In connection with this point and in order to ensure that there is no confusion regarding the process for developing new pipeline capacity,

c ommenter s provided some context and clarification to a statement in EPA's analysis.

EPA states: Th e third consideration supporting the conclusion regarding the adequacy of the infrastructure is that pipeline and transmission planners have repeatedly demonstrated the ability to methodically relieve bottlenecks and expand pipeline capacity. Natural gas
p ipeline capacity has been regularly added in response to increased gas demand and supply, such as the large amounts of new NGCC capacity from 2001 to 2003, or the delivery to market of unconventional gas supplies since 2008 (79 FR 34829, 34864).

While EPA refers to "pipeline planners," it should be understood that, unlike electric transmission lines, interstate natural gas pipelines are not "planned" in a centralized manner or on a regional basis. Pipelines are developed competitively in response to the mar ket demand that243 manifests itself in the willingness of shippers to commit to long

- term contracts for firm pipeline service. Often more than one pipeline competes for a market opportunity. It is the market that determines the winners in this competition, i. e., which of the competing proposals receives sufficient shipper commitments enabling it to proceed. While pipeline developers are aware of forecasted increases in supply and demand, this alone 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 demand for additional pipeline capacity, those pipelines were not developed until shippers (typically natural gas producers or natur al gas marketers) contracted for the capacity to transport their supply to the market. Similarly, while the addition of new NGCC capacity created additional demand for pipeline capacity, pipelines were not developed until shippers committed to long

- term fi rm contracts for the pipeline capacity that would be used to satisfy that demand. In fact, developing pipeline capacity to serve the demand created by NGCCs in organized wholesale power markets (and, in particular, the markets in which generation has been divested by incumbent utilities) has been problematic. Rules in those markets create little incentive or ability for merchant generators to contract for firm pipeline capacity. According to the commenter s , this is an important point in connection with sati sfying the need for new interstate natural gas pipeline capacity that may be created by implementation of the Clean Power Plan.

Commenter s stated the legal and regulatory process for siting and permitting new pipelines and adding capacity on existing pipelines is a very complex multi

- year process, in which the time between the inception of a pipeline project and an in

- service pipeline histor ically has averaged about three years, depending on the size and complexity of the project and issues encountered in the permitting process. Commenter s stated that, while it can be significantly shorter if mainline pipeline capacity is available and only a lateral pipeline is needed to connect the new customer, the process can be significantly longer if the proposed 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 becoming more challenging and continued performance at this rate should not be taken for granted.

Commenter s stated the state implementation plans must allow sufficient time to (1) identify the instances in w hich incremental pipeline capacity will be needed, (2) ensure that a creditworthy entity has the ability to contract for long

- term, firm 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, permit and construct the needed facilities. Commenter s stated that, while pipeline operators can work with generators and with state authorities to explore some of these questions prior to the finalization of state implementation plans, actual commitments by 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.

Commenter s stated that the part o f this process with perhaps the greatest potential for improvement is the permitting that must occur in conjunction with the certificate of public convenience and necessity issued by FERC pursuant to the Natural Gas Act. Commenter s stated these permits ens ure compliance with other federal resource and environmental laws, such as the Endangered Species Act and the Migratory Bird Treaty Act. Commenter s stated that delays in processing and issuing these permits can add significantly to the time needed to const ruct a pipeline project. Commenter s suggested the EPA should 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 facilitate compliance with the Clean Power Plan.

Commenter s suggested the EPA support the Obama Administration in its efforts to improve the efficiency of the federal permitting process for infrastructure that contributes to economic growth and the achievement of oth er public policy objectives, since Interstate natural gas pipelines fit squarely within this category. Commenter s suggested the administration should work constructively with the Congress on statutory reforms that will make it possible to increase the effi ciency and predictability of pipeline permitting. Commenter s noted that any deterioration in the efficiency of this process at the federal and state levels will impair the ability to add pipeline capacity in a timely manner, which would frustrate implement ation of the Clean Power Plan by creating uncertainty about the ability to add pipeline capacity in a timely and predictable manner and thereby support the increased utilization of NGCCs.

Comment 3: Commenter s stated the advantages of clean

- burning natura l gas

- fired generation consistently outweigh other alternatives, even during extreme weather events.

Response 3: The EPA agrees to the extent that natural gas supply is adequate to allow for establishment of CO2 emission standard rates , and that generation shifting is an appropriate approach . See section V.D of the final rule preamble of the CCP, Chapter 3 of the GHG Mitigation Measures TSD supporting the final CPP, and the regulatory impact analysis of the final CPP.

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

Commenter s stated that, although the winter of 2013/2014 created multiple challenges for grid operators, the majority of problems encountered during these extreme conditions were not an issue of natural gas availabi lity. Commenter s cited a letter from PJM in response to questions about the polar vortex from members of the U.S. House Committee on Energy and Commerce:

Although there has been much focus on gas issues associated with interruptible transportation, overall the gas interruptions were not the major driver of the high forced outage rates experienced in the PJM region. Natural gas interruptions, 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 made 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 other problems related to operating generating facilities in extremely cold temperatures. These problems impacted all generation types, including 14,000 MW of coal capacity, 9,700 MW of natural gas capacity, 1,400 MW of nuclear capacity, and 6,100 MW of o ther capacity (including hydropower and oil). An increased focus on cold weather preparedness should help to mitigate these problems in the future.

Commenter s stated these "interruptions" were a function of the gas delivery contracts generators had with t he pipelines. Commenter s stated that, in times of high demand, generators holding a lower

- cost, interruptible contract will see that service interrupted

- that is wholly consistent with245 the contractual agreement and not a function of natural gas availabili ty. Commenter s stated this aspect is acknowledged in a separate communication where PJM noted that, "the gas supply problems experienced last winter were primarily contractual and economic, not physical constraints, meaning that for many gas

- fired generato rs, fuel firmness can be achieved through new arrangements with marketers even without expansion of the gas pipeline system" which further demonstrates that natural gas availability was not the source of problems encountered during the polar vortex.

Comme nter s stated existing NGCC resources have the ability to operate at high utilization levels, at or above 70 percent, without sacrificing the ability to fill other needs; specifically, NGCC units running at high capacity factors may still operate as load fo llowing units and retain the ability to quickly ramp up or down in response to fluctuations in renewable energy supply and electricity demand throughout the day. Commenter s stated the operating characteristics of natural
gas

- fired power plants enable the e xpansion of intermittent resources, like solar and wind, allowing grid operators to keep supply and demand of electricity in balance. Commenter s stated the presence of natural gas generation provides grid operators the freedom to accept capacity from renew able energy sources without putting electric system reliability at risk. Commenter s cited a number of studies that have affirmed the important role of natural gas

- fired power plants in enabling renewable power.

Commenter s described a number of benefits related to using natural gas for electric generation, including low

- cost technology, reliable baseload, peaking or intermediate power, ability to ramp up quickly, increased grid diversity, reduced air pollution, and ability to accommodate intermittent electricity sources such as wind and solar generation. Commenter s stated the capacity of natural gas to meet growing energy demands is particularly significant in light of the resurgence in U.S. manufacturing and noted natural g as facilities are scalable and require only minimal lead time as compared with other traditional power sources. Commenter s referenced EIA data and stated that, in light of the continued positive outlook for natural gas supply and availability, the electric ity sector's use of natural 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. Commenter s stated that NGCCs can effectively and

e fficiently supply baseload power to the electric power system. Commenter s noted that, in 2013, natural gas

- fired power plants accounted for over 50 percent of new utility

- scale generating capacity 7 with about half of that capacity in the form of NGCC power plants that provide intermediate and baseload power. Commenter s stated that, over the first six months of 2014, natural gas

- fired power plants again made up more than half of the utility

- scale capacity additions in the United States and almost all of thes e plants were NGCC, the majority of which are designed to serve baseload power in the regions in which they operate. Commenter s stated there is a recognition in the industry that current price and regulatory dynamics have created an opportunity for existin g NGCCs to increase utilization and act as a baseload resource.

Comment 4: Commenters expressed concern regarding extreme weather events impact on the electric system and failure of pipeline infrastructure to keep pace with demands.246 Response 4: The EPA dis agrees that these considerations prevent 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 develop plans that establish emission standard s 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 t ime 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 states may consi der local circumstances as they develop their plans, including system reliability, fuel diversity, the possibility 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 when electric power companies up and down the eastern and southern United States scrambled to deploy all generating assets. Commenter s 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 gas

fired generation during extreme weather events. Commenters stated that, in an integrated natural gas/electric power market following implementation under the proposed rule, where gas delivery syst ems will be further strained as more gas

- fired electric generating units displace coal

- fired units, a similar polar vortex event could cause major interruptions in meeting peak heating demand. Commenter s noted that the current natural gas pipeline system i s not equipped to accommodate greater utilization of natural gas

- fired generation, and since natural gas pipelines are only built after customers have subscribed to the majority of the pipeline's capacity, there is not sufficient time to build addition nat ural gas infrastructure to support expanded natural gas

fired generation as a result of the timing of the proposed CPP.

Commenter s noted that natural gas delivery restrictions to power plants during the 2014 winter resulted in an increase in prices over 1 ,000 times greater than normal prices. Commenter s questioned how the EPA proposes that states mitigate increased exposure to extended electrical power outages caused by natural disasters when pipelines are severed and pipeline pump stations are closed down . Commenter s noted that natural gas plants only have seconds of onsite storage, but, as noted by commenters, coal

- fired power plants have a 45

- day supply of resources onsite, which allows for greater reliability of energy supply and price volatility. Comme nter s 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 natural gas plants.

Commenter s urged the EPA, in its finalization of this rulemaking, to factor into its BB2 analysis a more refined consideration of the impacts of extreme weather events on the ability of gas

- fired generation in the PJM region to manage increased dispatch under extreme cold weather events. Commenter s stated this would require a clos er consultation by EPA with entities such as NERC, INGAA and PJM. Commenter s stated the EPA's sole reliance on traditional historic EIA and247 INGAA reports fail to account for the impacts of extreme weather events and the stressors these events place on the system.

Commenter s stated the EPA relies on EIA and industry publications, primarily INGAA's Midstream Infrastructure Report through 2035, to support its assertion that the industry can currently manage intermittent gas pipeline constraints, relieve bottl enecks and expand capacity. Commenter s stated the INGAA Report's principal findings indicate that significant infrastructure will be needed to support growing gas use. Commenter s stated the base case assumes $100 per barrel of oil and shows gas prices risi ng from $4 per MMBtu to an average of $6 per MMBtu in the longer term. Commenter s stated the base case projects significant supply development and growth in gas production, primarily from shale resources. Commenter s stated producers are likely to develop s hale resources with large quantities of oil and gas, which also have significant needs for new pipeline infrastructure. Commenter s stated the base case projects substantial gas production growth, especially from the Marcellus and Utica shale regions in the northeastern United States and also from other shale regions in the U.S. and Canada. Commenter s stated a significant number of gas processing, pipeline, and fractionation facilities will also be required to accommodate growing gas production.

Commenter s s tated that, as last winter's "polar vortex" demonstrated, pipeline capacity failures during extreme weather conditions and general breakdown of pipeline infrastructure is a continuing reality. Commenter s stated that on January 8

- 9, 2014, PJM experienced a 22% forced outage rate during an extreme cold weather event with gas supply failure a major contributing factor. Commenter s stated the breakdown of forced outages by primary fuel type shows that natural

- gas

- fired generators accounted for 47 percent of the unavailable megawatts. Commenter s stated the 9,300 MW of generation that was unavailable due to natural gas interruptions was a larger amount than PJM reported immediately after January 7. Commenter s stated that, subsequent to January, PJM worked with gene ration owners 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 generation fuel types being dependent on natural gas and the natural g as infrastructure. Commenter s stated an example is a generator that burns oil but that needs natural gas to start up. Commenter s referenced the 2014 NERC Report on the Polar Vortex and stated this report highlighted the contribution of gas supply shortfall s as follows:

• One of the largest issues impacting gas

- fired generation was the curtailment or interruption of fuel supply. Unlike other fuel sources, natural gas is not typically stored on site. As a result, generators rely on real

- time delivery of natural gas from their suppliers. Often, as units are not confident that they will be dispatched, the fuel is obtained on the spot market as an interruptible fuel supply.

Comment 5: Commenters agreed the EPA should seek to lower CO2 emissions by re

dispatching the electric generating fleet, but the commenters expressed concern that the necessary infrastructure for this re

- dispatch to occur may not be available in time.

Response 5: The EPA agrees that shifting generation is an effective means to reduce CO2 emissions. EPA disagrees that natural gas infrastructure 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 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 substantial flexibility as to how they structure those plans to achieve th e 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 r ate achievement between performance periods. Neither 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 requirem ents 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 speci fic public comments under this comment:

Commenter s stated its belief that most NGCC facilities have the technical capability to operate at an average annual capacity factor of 65 or 70 percent, and noted that several plants owned by member of the commenter s ' trade association have operated above these levels for extended periods of time. Commenter s indicated that whether the system as a whole can operate with most states' NGCC fleets averaging this utilization level by the early part of the compliance period (as implied by the goal computation) is less clear. According to the commenter s , many states would be able to rapidly increase the utilization of existing NGCC facilities, but others may require additional time because of infrastructure constraints, characteristics of existing in

- state generation facilities or because of their load centers' locat ions in the electric or gas transmission system. Commenter s stated that procuring adequate natural gas supplies to sustain a high level of utilization year round could mean, in the case of some states, building new pipelines or increasing the capacity of e xisting ones, while in others getting the electricity to consumers currently served by steam units without expanding transmission may be a challenge.

Based on these types of uncertainties, c ommenter s recommended that the EPA establish a more strategic app roach to Building Block 2. While agreeing 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 comply with the emission guide lines without increasing NGCC utilization to 70 percent, c ommenter s would support changes to the rate at which Building Block 2 is deployed as part of the goal

- setting process. Commenter s added that as much as the shift EPA has proposed as a part of Buildi ng Block 2 is about increasing NGCC utilization, it is also about decreasing boiler steam generation and replacing the services that boiler steam capacity currently provides to the grid.

Comment 6: Commenters disagreed on the feasibility of EPA’s capacity 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 was feasible.249 Response 6: The EPA disagrees that we have inadequately considered technical and regulatory constraints on the utility power system

. 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 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 wi th 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 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 states may consider local circumstances as they develop their p lans, including system reliability, fuel diversity, the “useful life” of generation assets, 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 G HG 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 proposed rule incorrectly assumes in building block 2 that there is sufficient generating capability from Oregon's existing 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 EGUs in 2012 and the hypothetical generation from the state's NGCC units constantly operating at a 70 percent capacity factor. Commenters stated that the months when the green line 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 a nnual fossil generation and annual NGCC generation at 70 percent capacity factor, but this analysis misrepresents the actual amount of additional capacity available in the northwest. Commenters said the majority of fossil generating capacity in the northwe st does not operate in the spring, when load is relatively low and hydropower and wind resources are relatively high. Commenters said the lack of fossil generation during the spring creates the illusion that the state has available NGCC capacity to fully d isplace coal, when in reality it does not. Commenters added that the proposal's use of 2012 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

- year historic average. Commenters noted that high hydropower production, such as what was observed in 2012, displaces fossil generation in the Northwest, and conversely, in average and low water 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 India na will be able to operate at a 70% capacity factor as proposed by the application of BSER under Building Block 2. Commenters explained that based on consultation with electric utilities in Indiana and surrounding states that run NGCCs, there is concern wh ether older facilities will be able to run at 70% capacity factor250 due to the age of the equipment and the required maintenance. Also, commenters said some NGCCs have been built using equipment from older coal units and as a result are not as efficient

as n ewer units.

Commenters' general concerns are identified below and cover several issues, including contractual obligations, transmission capacity constraints, pipeline availability, security considerations, and air quality limitations. Many of these issues are addressed in more detail in other portions of section 3.2.4.

Contracts and costs

Commenter s stressed that assumptions regarding 70 percent capacity factors for NGCC units do not consider market prices or firm pipeline capacity. Commenter s asked the EP A to carefully consider the assumptions that underlie the proposed rule.

Commenter s stated that an indication of where increased natural gas demand may signal some risk for the power sector is if demand in the area has already experienced pricing pressure. Commenter s stated that empirical analyses of spot prices identify those regions of the interstate pipeline network that are sensitive to constraints. Commenter s identified pipelines and market areas that showed sustained price spreads (basis differentials ) between the pipeline

- based trading hubs and the reference Henry Hub market. Commenter s noted that a hub was considered to be constrained on a trading day if its closing price was double the price at Henry Hub; if the hub was constrained more than 250 tim es between June 1, 2009 and October 6, 2014 then it was classified as congested. Commenters provided a table (titled: “Historically

- Congested Pipelines / Trading Areas"), which listed ten natural gas pipeline hubs, including: Texas Eastern Transmission (TE TCO) M3, Transcontinental Pipeline (Transco) Zone 6 Non NY, Dominion South, Maritimes & Northeast Pipeline, Iroquois Zone 2, North East Dracut, Boston / New England City Gate, El Paso, Northeast Transco Zone 6, Tennessee Gas Pipeline Zone 6.

Commenter s st ated that Building Block 2 is not a viable option because natural gas is not an available fuel without limitations. Commenter s stated that SCANA, like many utilities, has insufficient firm capacity on the interstate pipelines to increase natural gas usage for many of its units. Commenter s stated SCANA would need additional firm pipeline capacity on Carolina Gas Transmission Corporation (CGT) and an upstream interstate pipeline

- either Transcontinental Gas Pipeline (Transco) or Southern Natural Gas Company (SNG). Commenter s noted that for the past several years, CGT has reported that its pipeline is "essentially full," and Transco and SNG are also fully subscribed. Commenter s stated this means that additional pipeline facilities or system modifications would be required for SCANA to obtain additional natural gas capacity. Commenter s stated that, pursuant to FERC regulations, projects to add capacity to natural gas pipelines are subject to a lengthy approval process. Commenter s stated that, it may sound easy t o

re

- dispatch from coal to natural gas, but this cannot be done if there is a shortage of natural gas available to use as fuel.

Commenters stated that in Building Block 2, EPA projects that coal

- fired electricity generation can be reduced significantly by prioritizing the dispatch 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 ensuring the reliable supply of low

- cost251 electricity throughout the United States and does not dispute that many NGCC facilities are capable of operating at an average capacit y 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 existing NGCC units in its BSER analysis. Commenters continued, stating that while it is only a function of time until infrastruc ture and supply constraints, EPA must evaluate existing NGCC facilities within the context of the existing infrastructure in the States in which they are operated, and, when viewed in that context, there are a number of challenges that must be considered w hen 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 pot ential impact of those additional real

- world factors on States

- ability to achieve EPA's Building Block 2 projections in the time frame contemplated by the Agency. Commenters provided 6 supporting statements for their position.

1. Commenters said even if EP A is correct that, as a technical 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 existing NGCC facilities operate pursuant to State

- issued p ermits, 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 fuel

firing rates to mai ntain its status as a minor source with respect to the Clean Air Act's PSD permitting program. Commenters said such a facility would effectively be barred from operating at the capacity envisioned by EPA. Commenters 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 economic 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 analysis. At a minimum, commenters suggested that EPA must provide a mechanism for States 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 capacity of NGCC facilities on an annual basis, EPA's analysis may mask seasonal variations that limit the amount of coal

fired electricity generating capacity that can be redispatched to NGCC fac ilities. 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% capacity 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. Commenters stated, as a result of these seasonal variations, existing and under construction NGCC facilities may not be capable of displacing as much coal

- fired electricity generation as EPA projects, even if NGCCs operate at 70% capacity. Rather than relying on annual generation data, commenters252 suggested that EPA must incorporate seasonal variation to more accurately e stimate the effect of increasing capacity at NGCC facilities.

3. Commenters said EPA's proposal assumes that electricity produced by different EGUs is completely fungible and that existing and under construction 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. Commenters said, for example, coal

- fired EGUs may be located st rategically to provide voltage support and other grid reliability benefits. Commenters said existing and under construction NGCC facilities at other locations may not be capable of replacing these functions. Commenters said, likewise, certain coal

- fired EG Us may be designated as "black start" facilities that are capable of restarting without any electricity input or for other reasons may be designated as "must run" facilities by FERC or RTOs. Commenters noted that 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 sug gested that EPA's BSER analysis 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 n ot give adequate consideration to infrastructure changes that may be needed to accommodate the increase 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 rely 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 additiona l infrastructure investments. Commenters said, likewise, because existing NGCC facilities are not co

- located with the coal

- fired EGUs whose generation they would displace, additional investments in transmission infrastructure may be needed to ensure that t he electricity generated by existing and under construction NGCC facilities can reach consumers currently supplied by coal

- fired EGUs. Commenters stated that the same challenges related to transmission infrastructure apply to increased renewable energy gen eration under Building Block 3. Commenters noted, in fact, renewable energy generation may pose even more challenges, as locations with renewable energy generation potential may be far removed from population centers that demand electricity. Commenters sta ted that EPA glosses over these challenges by suggesting that any necessary infrastructure can be constructed to accommodate increased NGCC and renewable capacity. Commenters said it may prove challenging to finance, plan, and complete infrastructure proje cts by 2020, when Building Block 2 will be implemented under the interim compliance schedule proposed by EPA. Commenters asserted that the challenges presented by EPA's compliance schedule will be exacerbated by complex and, at times, inefficient federal p ermitting systems and the opposition efforts that are often mounted against these large

- scale infrastructure projects. Commenters said it is arbitrary and capricious for EPA to not consider the degree to which new infrastructure investments will be needed to displace coal

- fired electricity generating capacity and the time that such projects will take.253 5. Commenters stated that EPA simply assumes in its calculation of State emission reduction targets, without support, that all NGCC facilities that are currentl y under construction will actually be completed and operated. 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 could cause an NGCC project to be stalled, delayed, postponed, or canceled. Nor, commenters remarked, does EPA provide a contingency plan to adjust a State's emission reduction targets in the event that construction of a facility is postponed or cancelled.

6. Commenters said in the NODA E PA requests comment on "whether to establish a minimum value as a floor for the amount of generation shift for purposes of building block 2" which could be achieved, in part, though co

- firing natural gas at existing co

fired EGUs. 79 Fed. Reg. at 64,550. C ommenters said, as an initial matter, EPA explicitly rejected co

- firing natural gas as BSER in the proposed rule, 79 Fed. Reg. 34,875, and provides no facts in the NODA or elsewhere in the record that would provide a reasoned basis for the Agency to revers e course in a final rule. Further, commenters noted that EPA does not offer any analysis of a number of potential challenges to co

- firing natural gas, including that (1) natural gas igniters installed at coal

- fired EGUs should not be run continuously becau se they are intended to operate during 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 continuous or long

- term co

- firing of natural gas ca n cause problems with ash accumulation, and (4) at lower loads, co

- firing natural gas can increase emissions of NOx and CO and reduce efficiency by forcing other units offline at the facility. Commenters suggested that EPA must more fully explore these pot ential challenges before relying on co

- firing 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 whet her they would trigger a modification 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 per metric ton of CO2 depending on the proportion of natu ral gas generation after modification. 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 in EPA's cost analysis, it would be arbitrary and capricio us for EPA to rely on co

- firing

Infrastructure

Commenter s stated that building block 2 increases the utilization of combined cycle natural gas fire and presupposes that pipeline infrastructure is adequate or that it can be built to enable plants to operat e at 70 percent capacity factors. Commenter s noted that these are questionable assumptions on which to build building block 2.

Commenter s stated that the EPA has not fully evaluated the transmission and gas supply infrastructure issues that may significant ly impact the feasibility and amount of potential re

dispatch. Commenter s stated the EPA failed to support its claims that sufficient natural gas supply and pipeline capacity and electricity transmission will be available, devoting only a single page of a 224 page technical support document to the issue.254 Commenter s stated the EPA has not addressed what additional natural gas infrastructure will be needed to supply the natural gas required for dramatic increases in natural gas power generation. Commenter s s tated that the re

- dispatch of natural gas for base load will likely require construction of new natural gas facilities and infrastructure in order to track demand and maintain system reserve requirements. Commenter s stated that, in the West, this likely me ans significant additional environmental reviews to permit infrastructure projects on public lands.

Commenter s stated that greater reliance on variable resources and gas

- fired generation is expected: The CPP will accelerate the ongoing shift toward greate r use of natural

- gas

- fired generation and variable energy resources (renewable generation). Commenter s 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). Commenter s added that increased natural gas use will require pipeline expansion to maintain a reliable source of fuel, particularly during the peak winter heating season. Commenter s stated that pipeline const raints and growing gas and electric interdependency challenges impede the electric industry's ability to obtain needed natural gas services, especially during high

- use horizons.

Commenter s stated that the Proposed Rule assumes without support that the gas distribution infrastructure needed to support increased reliance on gas generation exists or will soon be built. Commenter s stated this may be true in certain parts of the country, but not others. Commenter s (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 commit to the long

- term contracts unless they know how they will be dispatched in the long

- term; (3) gas 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 further complicated if generator s are in organized markets that serve multiple States: under the Proposed Rule, generators may be dispatched at different levels (and require different levels of fuel) depending on the location of their loads and their state's specific environmental dispat ch requirements. Commenter s stated that, for these reasons, the Proposed Rule may actually be dis

- incentivizing the development of the natural gas infrastructure that EPA assumes exists. Commenter s noted that institutional considerations that affect the development of new pipelines include permitting of new interstate pipelines by the FERC; willingness of shippers to support new interstate pipelines by entering into long

- term capacity contracts; the needs for such long

- term contracts to secure financing; and mechanisms by which shippers' capacity rights trade in a secondary market. Commenter s included the following description, analysis and findings :
The interstate pipeline system in the United State s represents firm delivery capacity that was largely built to serve, and almost completely underwritten by, natural gas distributors and their connected users. Traditional firm services were tailor

- made for the requirements of natural gas distributors, and the types of pricing of those services (including straight

- fixed

- variable and incremental pricing) have been key parts of the foundation for the highly competitive deregulated capacity release market. Any new pipeline services or prices targeted at power generators would have to take into consideration their effect both on traditional services for natural gas distributors and on the working of the successful deregulated interstate pipeline capacity market. Electricity generators in competitive 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. Competitive electricity generators, operating in organized regional markets, have not yet h ad the need to plan for storage, alternative fuels, or firm delivery service on interstate pipelines. These costly services would reduce their earnings. NERA does not expect new interstate pipeline capacity 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

- regulated, vertically

- integrated utility will be able to lock in pipeline capacity for durations sufficient to suppor t financing and construction of interstate pipeline capacity. However, merchant generators 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 generators are more likely to face constraints in achieving the infrastructure build needed to accommodate 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 quadr ant including and to the northeast of Michigan, Ohio, and Maryland) plus Illinois, Texas, and Oregon. Whether these states are actually at risk 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 that 2012 (the most recent peak year for natural gas consumption in much of the U.S.) provides a good indication of the proven capacity to deliver natural gas to various states.

Commen ter s stated the significant resource adequacy and reliability risks arising from such a wholesale change in dispatching of the generation fleet under the proposed rule are unacceptably accounted for by EPA. Commenter s stated the ability to transport much l arger 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. Commenter s referred to a ScottMadden re port 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 needed. Commenters stated ScottMadden refers to a March 2014 st udy by the INGAA that reported an average of about 1,650 miles of new gas transmission line is added per year (mainline miles and lateral connections). , and added that a bout 15,500 miles of new pipe per year will be needed in the future, with most of this being gathering line. Commenters also added n ew 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 should rules limiting utility emissions of carbon or other pollutants result in a shift away from coal towards using more natural gas to generate electricity. Commenters’ document stated that if substantially more gas is needed, then a number of changes will need to b e made by both the gas and electricity industries: changes such as massive infrastructure additions, changes to nominating and balancing services, changes to curtailment rules, and changes to subscription levels on interstate pipelines.

Insufficient demon stration

Commenter s 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 transmission capacity available to sufficiently increase256 NGCC generators' historical performance. Commenter s noted that cooperatives across the nation own 12,000 MW NGCC capacity with NGCC plant capacity averaging 35% in 2012 and 27% in 2013. Commenter s noted that, during the same time period, only 5 co

- op NGCC facilities, representing 30% of the NGCC capacity, operated at 60% capacity when natural gas was priced historically low. Commenter s stated the EPA has not demonstrated that the NGCC fleet is capable of almost doubling its average performance in o rder to take on the demands of coal

- fired

re

- dispatch.

Commenter s stated the notion that BSER includes operation of gas units in sufficient number and at a 70% capacity factor to partially offset the lost generation from shuttered coal plants is undemonstr ated both as a matter of history and in the record. Commenter s stated that, by EPA's own account this country required 12 years to increase natural gas production by 32%, which is approximately the same rate of increase in natural gas

- fired unit capacity n ecessary to satisfy building block 2, albeit over a much shorter period if the 2020 deadline is maintained. Commenter s stated the pipeline infrastructure build

- up necessary for building block 2 cannot simply be wished into existence as a matter of capital investment, permitting, or construction. Commenter s referenced FERC Commissioner Moeller testimony that EPA's assumptions that there will be sufficient pipeline expansion to meet this new gas demand may prove "faulty." Commenter s 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 regional issues associated with expanding interstate natural gas transportation capacity, contractual issues associated with pipeline capacity, environmental permitting issues associated with increasing 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 incorporate into many states' plans because regional market rules do not necessarily accommodate the expansion of interstate pipeline capacity that such re

- dispatch will require. Commenters stated the process of applying for a certifica te of public convenience and necessity is quite cumbersome and generally requires a three

- to five

- year period from the date the application is submitted until the date the pipeline begins construction. Commenter s stated that, to the extent a pipeline const ructs 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 risk" for any cost under

- recoveries associated with underutilized facilities. Commenters sta ted that, as 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, because of the regulatory requirements and significant expense associated with constructing and operating a new interstate natural gas facility, the applicant generally requires long

- term, 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 market 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 for the forward capacity market only permit a maximum seven

- year commitment period for a new capacity resource and one

- year commitment period for existing capacity resource (see ISO

- NE Transmission, Market and Services Tariff section III.13.1.1.2.2.4). Commenters noted that FERC j urisdictional rates for firm interstate257 pipeline services require customers to pay all of the pipeline's fixed costs associated with the capacity under contract through a "reservation charge," which is payable even if the customer rarely uses most of the c apacity. Commenters concluded that the mismatches between electric market rules and gas pipeline rates and contracts make pipeline transportation capacity expansion for electric generation purposes extremely difficult.

State

- specific

Commenter s expressed c oncern that the re

- dispatch would force the state to run down nearly all of its coal plants. Commenter s noted that Arizona has a large amount of natural gas generation, but only 50 percent of those facilities are owned by state utilities. Commenter s also n oted that most of the facilities are located in one general area west of Phoenix. Commenter s are concerned that the EPA fails to consider existing contractual obligations, transmission capacity constraints, pipeline availability, security considerations, a nd air quality limitations.

Commenter s stated that, with limited pipeline capacity in Florida, the magnitude of this increase in natural gas consumption is a concern.

Commenter s expressed that Hoosier Energy has experienced a lack of natural gas availability in times of extreme weather and under other conditions. Commenter s noted that this occurred at both combined cycle and peaking facilities. Commenter s stated that setting a go al does not diminish the issue of inadequate pipelines and storage facilities since electric utilities such as Hoosier Energy do not have control over the lack of natural gas infrastructure. Commenter s stated that the EPA must examine these constraints and adjust state goals if gas availability cannot be assured. Commenter s also noted that many combine cycle facilities were not built to run such a high capacity factor and that the constraints of the units themselves must be considered.

Commenter s expressed concern regarding the amount of electrical generation that can be re

dispatched to NGCC units based on the current natural gas supply and infrastructure in Illinois. Commenter s stated that, during the polar vortex period last winter, affected EGUs were sev erely restricted in purchasing gas because the supply was prioritized for other sources, such as home heating. Commenter s noted that, while actions are being taken to improve infrastructure, estimated completion dates are several years away and may not ent irely address the situation.

Commenters expressed concern regarding the adequacy of pipeline capacity in Missouri. Commenter s stated it is important to examine the potential risks associated with an increased dependence on natural gas. Commenter s stated that, unlike coal and fuel oil, natural gas is not typically stored on site and, as a result, real

- time delivery of natural gas through a network of pipelines and bulk storage is critical for Building Block 2. Commenter s noted that other states alo ng interstate transmission pipelines presumably would also need additional capacity to meet Building Block 2, including Kansas, Illinois, Indiana, Ohio and Michigan. Commenter s stated that natural gas pipelines serving Missouri were designed for winter hea ting load and they do not have the capacity to serve winter natural gas heating load while simultaneously providing natural gas capacity to off

- set displaced coal

- fired generation. Commenters noted that, during the winter of 2014, demand for natural gas in creased, resulting in a significant amount of gas

- fired generation being unavailable due to curtailments. Commenter s 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 needs. Commenter s stated the EPA's assumption ignores the complex interrelationship between the electric sector and natural gas supply and pipeline capacity. Commenter s stated the EPA is relying on the natural gas sup ply 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. Commenter s stated that there is currently not sufficien t gas capacity to support an NGCC plant in Missouri during the winter heating season. Commenter s stated that Westar Energy was unable to acquire natural gas at any price for a period of time this past winter at its Spring Creek generation facility in Oklah oma due to the severely cold weather and a lack of sufficient capacity to transport additional supplies of natural gas.

Commenter s stated that Nebraska does not have adequate 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 compliance timeline of the proposed Clean Power Plan.

Commenter s expressed concern regarding the lack of a major gas pipeline in the lower half of South Carolina. Commenter s noted that the EPA seems to believe that natural gas is readily available and affordable in all parts of the country. Commenter s noted that natural gas is not available to certain areas. Commenter s stated that lack of a major gas pipeline in the lower half of South Carolina puts the state at a very high disadvantage. Commenter s stated the increased natural gas target fails to recognize that South Car olina's two interstate gas pipelines are at full capacity. Commenters stated that although EPA claims 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 infras tructure constraints and supply limitations of South Carolina particularly for natural gas.

Commenter s stated that is MRES built in states where it has load, it would face similar infrastructure issues as if it built in Wyoming. Commenter s noted that the MISO Gas and Electric Infrastructure Interdependency Analysis found that a new natural gas pipeline would cost $870 million to $1.1 billion. Commenter s noted that this cost estimate is for lateral pipeline development and does not include mainline constru ction costs. Commenter s stated that pipelines would not be built overnight, and sufficient time is required to plan and build sufficient pipeline to supply the new NGCC units. Commenter s noted that the construction of any natural gas line or extension may face opposition or delays which could result in increased costs and require additional time for permitting and construction. Commenter s also noted that the cost associated with building of sufficient natural gas infrastructure should be considered in the c ost assessment of the BSER in the proposed rule.

Storage

Commenter s further stated that the Proposed Rule does not examine whether sufficient natural gas storage exists to support large

- scale fuel switching

- many states do not have adequate geologic forma tions to store gas that is needed by electric utilities for generation as baseload power, to back up intermittent renewables, or provide peaking power. Commenter s asserted that259 the Agency needs to look at these issues and adjust its assumptions about the t imetables by which states and the electric utility industry can meet the requirements of building block 2.

Commenter s 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, and as a hedge against price volatility of natural gas.

Timing

Commenter s stated that according to the EIA, currently there are approximately 300,000 miles of interstate and intrastate natural gas pipeline capacity in the U.S. Commenter s alleged that the EPA asserts that pipeline ca pacity can be added to enable the large

- scale fuel switching the Proposed Rule envisions is needed to reduce CO2 emissions, but the EPA's analysis fails to examine whether this significant expansion can happen by 2020 or even 2030 given the impediments the pipeline industry faces in constructing and expanding pipelines, barriers posed by certain restructured wholesale electricity markets, and differences in the business models for the electricity and gas pipeline industries. Commenter s 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 miles of pipeline each year or a total of 300,000 miles of pipelines (interstate and intrast ate) 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

Commenter s stated that, while the natural gas supply/delivery analysis under the proposed rule only discusses averages, actual utility planning and installed infrastructure must deliver under peak dema nd scenarios. Commenter s referred to the NERC's initial reliability review (Potential Reliability Impacts of EPA's Proposed Clean Power Plan, Nov. 2014). Commenter s stated the NERC's review (1) challenged the CPP's gas pipeline infrastructure assumption th at no major investments would be necessary; (2) cited current constraints in the Arizona/Nevada and New England markets; (3) raised concerns that wide displacement/retirements of coal

- fired EGUs with gas

- fired units would cause further potential bottleneck s; and (4) stated concerns that the CPP's timelines provide little time to add required pipeline or related resource capacity. Commenter s added that the Department of Energy (DOE) is funding a study of gas supply adequacy by the Eastern Interconnect Planni ng Collaborative (EIPC) and stated that study is designed to provide analysis in sufficient detail to 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 exist in certain areas.

Response 7: The EPA dis agrees that these issues prevent achievement of goals. In response to additional analysis and many comments, we have modified 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 providing states with substantial flexibility as to how they structure tho se 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. Neither the Building Blocks nor the IPM analyses are prescriptive, and states may consider local circumstances as they develop their plans , in cluding 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 Measures TSD for the CPP Final Rul e supporting the final CPP

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

Commenter s 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. Commenter s stated this assumption is not valid when capacity is unavailable for base

- load generation use because of competing purchasers and inadequate existing infrastructure. Comm enter s stated that, additional study specific to the natural gas transmission system in Arizona would be needed to determine what would be required to support using existing NGCC generation for base

- load generation. Commenter s stated that, while the EPA provides EIA data on current pipeline capacities in the U.S., the Agency provides no information on the amount of residual capacity available in the current system or the capacity projected as needed to meet EPA's assumptions re garding utilization of the current NGCC fleet at a 70% capacity factor. Commenter s suggested that actual available capacity may be far below 100% of nameplate capacity due to bottlenecks in the system. Commenter s referenced a November 2014 NERC report whic h stated that current and planned pipeline infrastructures in Arizona and Nevada are inadequate for handling increased natural gas demand due to the Clean Power Plan.

Commenter s 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. Commenter s stated that as a result, for any existing NGCC in the Southeast needing firm transportation capacity to increase generation, additional pipeline capacity will be neede d. Commenter s added that not all NGCCs currently maintain year

- round, 24 hours a day, seven days a week firm natural gas delivery for base

- load operation. Commenter s asserted that highlighting 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.

Commenter s stated that transmission constraints preclude 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% capacity factor.

Commenter s stated the EPA did not consider transmission constraints unique to New York, which limit the system's ability to transmit NGCC capacity located upst ate to high load areas in and around New York City. Commenter s stated the proposal appears to assume that both gas delivery and electric transmission infrastructure will be in place to support that NGCC capacity261 without adequately considering economic, rel iability, and technical concerns. Commenter s explained that southeast New York, which includes New York City and Long Island has specific electric constraints that preclude the transfer of the increased output of NGCC units located "above" the constraint. Commenter s stated that one major electric system constraint is referred to as the Upstate New York/ Southeast New York or "UPNY/SENY" interface and noted that approximately 62% of New York's NGCC fleet is located in UPNY with the remainder in SENY. Comment er s referenced a 2014 NYISO reliability study and stated that, because of this constraint, it is not possible to access all the installed NGCC capability that is located in UPNY (NYISO's 2014 Reliability Needs Assessment at pp. 24 and 28, available at http ://www.nyiso.com/public/webdocs/markets_operations/services/planning/Planning_Studies/ Reliability_Planning_Studies/Reliability_Assessment_Documents/2014%20RNA_final_091620 14.pdf.)

Commenter s stated that, because natural gas demand in downstate New York fo r space heating will increase due to a recent New York City local law that requires the phase

- out of residential and commercial boilers that currently use heavy fuel oil, and other factors, additional natural gas supply infrastructure will be needed. Comme nter s stated this raises concern about how gas infrastructure investments that are required to meet electric load requirements may be financed, and when such financing is needed. Commenter s stated that, given the relative size of New York City and its over all impact on the State's electricity system, the EPA should consider future projections of natural gas supply and demand, and uncertainties associated with gas infrastructure development, when evaluating the State's ability to achieve 70% NGCC re

dispatch

.

Commenter s stated that both SPP and the NERC have analyzed the Proposed Rule and concluded that existing transmission is not sufficient to maintain grid stability. Commenter s stated that SPP concluded, based on the generator retirements anticipated by t he Proposed Rule, that it is "very clear that new generation and transmission expansion will be necessary to maintain reliability during summer peak conditions." Commenter s stated that, particularly important for Western Farmers, and EPA's Building Block 2 analysis for Oklahoma, SPP found the most significant transmission deficiencies in the SPP system exist in Texas and Oklahoma.

Commenter s stated that, while Missouri River Energy Services would need to replace the lost generation from the retired unit and would presumably do so by constructing an NGCC plant, the LRS plant site in particular, and Wyoming in general, lack the necessary natural gas infrastructure to replace a lost coal unit with NGCC, not to mention the lack of electric transmission availa bility.

Comment 8: Commenter s stated that Building Block 2 is technically infeasible for two NGCCs it owns and operates, McWilliams and Vann.

Response 8: The EPA disagrees. 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 substantial flexibility as to how they262 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 2020 until 2022), and the ability to shift emission rate achievement between performance periods. T he Building Blocks are not prescriptive, and states may consider local circumstances as they develop their plans, including system reliabilit y, 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 CP P.

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

Commenter s stated its NGCCs are primarily used to regulate load, and neither of the units can support a 70 percent capacity factor year

- round. Commenter s stated that, whil e, 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. Commenter s stated the gas pipeline ser ving the two plants is a shared resource between PowerSouth and the Southeast Alabama Gas District (SEAGD) and, while the pipeline may be capable of delivering 95,000 mmBtu of natural gas per day, PowerSouth does not have access to this additional gas beca use SEAGD uses this capacity to supply heating needs for its low

- income, rural residential customers. As such, Building Block 2 is technically infeasible for McWilliams and Vann.

Comment 9: Commenter s stated RTO scheduling procedures limit the ability to achieve a specific capacity factor.

Response 9: The EPA disagrees that this comment reflects the intent and requirements of the rule, which does not require specific EGU’s to achieve specific capacity factors

. 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. The rule applies to states, not to balancing authorities, utilities, or units. 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 start of the interim performance period (postponed from 2020 until 2022), and the ability to shift emission rate achievement between performance periods. T he Building Blocks are not prescriptive, and states may consider local c ircumstances 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 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:263 Commenter s stated two factors impede the ability of an NGCC unit to achieve a specific capacity factor: (1) natural gas pipeline and RTO scheduling procedures are not in sync and (2), if NGCC generation is bid into either the day

- ahead or the reliability unit commi t (RUC) markets, the bid might not be accepted by SPP if the offer price is higher than the market clearing price. Commenter s stated that, in NPPD's case, current Southwest Power Pool (SPP) offer/award schedules for generation bid into the market occur aft er the points in time when NPPD must nominate gas supply needs under pipeline timely or Evening deadlines. Commenter s stated that NPPD's only option in that situation would be to nominate gas in the Intraday market, but, even assuming available firm transp ortation capacity for the nomination, gas may not be available intraday during periods of high demand, when the pipeline declares System Over

- run Limit ("SOL") conditions. Commenter s stated this latter situation remains likely despite recent drops in the c ost of natural gas because gas still remains an expensive fuel for NPPD. Commenter s stated that, given current delivered fuel prices, the energy cost for NPPD's NGCC Beatrice Power Station is approximately three times that of NPPD's coal

- fired Gerald Gentl eman Station on a dollar per megawatt hour basis and, in these pricing conditions, to achieve the desired 70% capacity factor, a utility would have to put NGCC units in what is referred to as a 'self

- scheduled' status, meaning it is a price taker in the ma rket. Commenter s stated that, as a price taker in a market where all accepted bids clear at the same price, 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 NGCC units would clear at prices lower than the cost of generation. Commenter s stated that, even as a price taker, an NGCC unit may still not be dispatched by the RTO due to bulk electric system reliability concerns. Commente r s stated that, in such cases, if the natural gas nominated by the curtailed utility is sold by the gas supplier, or is cashed out by the pipeline (possibly at a loss), the utility could be subject to penalties for not taking nominated gas under System Und er

- run Limit ("SUL") conditions.

Comment 10: Commenter s stated the EPA should indicate that states are allowed, in so far as concerns ESPS compliance programs, to create incentive mechanisms to offset the cost of firm pipeline capacity or other measures to secure natural gas deliverability.

Response 10: The E PA has provided considerable flexibility in implementation. 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 p lans 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 summar ies of the specific public comments under this comment:

Commenter s stated these measures could be considered as part of a fuel

- neutral pool of credits to address market failures that have impaired the reliable, cost

- effective provision of low

- carbon electr icity.264 Comment 11: Commenters expressed concern that a funding mechanism does not exist to support the infrastructure necessary for the CPP.

Response 11: The EPA disagrees that natural gas markets will prevent 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 standards is regionally based. The 111(d) final rule requires that states develop plans that establish emission stand ards 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, additiona l 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 states may co nsider local circumstances as they develop their plans, including system reliability, fuel diversity, other regulatory requirements and natural gas 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:

Commenter s stated that, without a funding mechanism to align the regulatory requirements to build new capacity with the market rules that govern a resource's ability to recover the transportation costs on that new capacity, Building Block 2 of the proposed rule's BS ER cannot be effectively implemented. Commenters stated that Congress has not vested EPA with the authority to create a regulatory program that effectuates this objective.

Commenters stated that funding for the increase in generation and the infrastructur e 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 best, given the existing US energy market.

Commenter s stated that financing adequate pipeline infrastr ucture to support the demand that will remain and ultimately grow, even after the retirement of coal

- fired electric generating units occurs, is a challenge that has been neither addressed nor considered by EPA's proposed rule. Commenter s stated that, tradi tionally, pipelines have been financed with 20

- 30 year contracts with natural

- gas distribution companies and cited the following: "Simply put, if plant owners don't know on a daily basis whether and to what extent their power plants will be called upon to run or not, they will be reluctant to sign a 20

- year 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 Commission

, 227 Ark. 436, 441, 299 S. W.2d 208, 211 (1957)]

Comment 12: Commenter s proposed that the EPA modify the methodology used in Building Block 2 to re

- dispatch coal

- fired EGUs to natural gas combined cycle EGUs such that re

dispatch does not occur until the latter of 2020, the end of initial book life, the end of 20

- ye ar pollution control project book life, or, for EGUs subject 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 propos al 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 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, 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. Neither 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 “useful life” of generation assets, other re gulatory 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:

Commenter s emphasized that this proposal is specifically intended to promote the calculation of more reasonable and achievable carbon dioxide intensity targets and is not intended to suggest a d ate by which EGUs could or should be retired or cease burning coal. Commenter s noted they were amending their recommended assumption adjustments under Building Block 2, consistent with comments filed by the Arizona Utilities Group on December 1, 2014. Comm enter s 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 initial com mencement 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 at any EGU if installation occurred prior to issuance of the final 11 1(d) rule, or after commencement 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 installation occurred prior to the first year of the compliance period (i.e., 2020).

Commenter s explained that provision (a) establishes the earliest re

- dispatch date as January 1, 2020, which is the first day of the compliance period; this date applies if the date under provisions 1.b or 1.c is before J anuary 1, 2020. Commenter s 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
t ypical amortization schedule for these EGUs, as the Environmental Protection Agency (EPA) acknowledged in the NODA (79 FR 64549). Commenter s added that, as a practical matter, most coal

- fired EGUs are more than 40 years old, so provision 1.b affects only a few EGUs in total throughout the United States.

Commenter s explained that provision (c) establishes the proposition that re

- dispatch from a coal

fired 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 c ontrol retrofit, including selective catalytic reduction, flue gas desulfurization or baghouses, for any coal

- fired EGU, as long as installation occurred prior to issuance of the final 111(d) rule. Commenter s stated that,266 for small utilities (defined under the Federal Power 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 treated as occurring no earlier than the 20th year f rom initial operation post installation of a major air pollution control retrofit, which would include for such small utilities not only the controls specified above but also selective non

catalytic reduction or electrostatic precipitators for any coal

- fir ed EGU, as long as installation occurred prior to 2020. Commenter s added that, as EPA acknowledged in the NODA, 20 years is the typical amortization schedule for large pollution control equipment retrofits (79 FR 64549). Commenter s stated this proposal pro vides some relief, consistent with both Section 111(d), 42 U.S.C. section 7411(d), and its implementing regulations, 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 entiti es 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: Commenter s stated that while RGGI is currently o perating 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 dis agrees that the final rule does not give states sufficient time develop their plans, and the EPA does not require any state to develop a sy s tem 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 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 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 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 Measures TSD for the CPP Final Rule supporting the final CPP.
The following are summaries of the specific public comments under this comment:

Commenter s said that starting up a new system similar 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 achieving the 2020 schedule for re

dispatch as well as the final implementation deadline

.267 Response 14 : The E PA dis agrees the final rule does not provide states with time to develop their plans ; the start of the performance period has b e e n 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 affected EGUs. We are providing states with substantial flexibility as to how they structure those plans t o 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 shif t emission rate achievement between performance periods. Neither 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

an d 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:

General

Commenter s stated there are significant problems with 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 economic impact on consumers. Commenter s supported the concerns expressed in the joint comments of the Arkansas Department of Environmental Quality and Arkansas Public Service Commission, includ ing accounting for the Pine Bluff Energy Center, EPA's use of nameplate capacity instead of summer

- rated capacity, air permit limitations, natural gas delivery constraints, and electric transmission limitations. Commenter s stated that all of these issues n eed to be fully reviewed and addressed by EPA in the final rule.

Commenter s stated the EPA has not sufficiently considered barriers, which include operating constraints, permit limitations, contractual commitments to out

- of

- state service, the need for NGC C availability to support RE, and infrastructure limitations and the EPA's failure to consider these factors renders its Building Block Two analysis insupportable.

2020 is too aggressive

Commenters generally stated the Proposal's schedule for re

- dispatch by 2020 is unreasonable.

Commenter s stated that, while AEPCO could seek to build 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.

Commenter s stated the EPA failed to adequately consider 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 assumed by the agency. Commenter s stated the impacts associated with retiring 70,000 MW of generation as projected by EPA are significant268 and will severely affect the reliability of electric service in this country. Commenter s stated that sufficient replacement capacity cannot be built in time to meet the 2020 interim targets.

Commenter s stated that achieving such dramatic increases in NGCC utilization effectively would require a fundamental redesign of the entire electric grid. Commenter s stated that meeting EPA's state goals through incr eased 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 take a much longer time frame to be completed than EPA allows for, particularly given that the interim compliance period begins in 2020, only three years, at the most, after a state could have a final, approved compliance plan. Commenter s stated that making the appropriate infrastructure and system changes that will be necessary to ac hieve increased utilization of existing NGCC units in certain areas will take longer than EPA's proposed guidelines currently allow.

Commenter s stated that a significant increase in generation from existing NGCCs is needed in each of the four states South ern Company maintains retail operations, which will likely need to occur by 2020 and in a seamless manner. Commenter s maintained that achieving a 70 percent capacity factor from existing NGCCs in Alabama, Florida, Georgia and Mississippi will require an in crease in natural gas consumption of approximately 600 billion cubic feet ("Bcf") by 2020. Commenter s noted that the Southern Company was the third largest electric generation user of natural gas in the country in 2012, utilizing approximately 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 natural gas consumption. Commenter s said that the EPA has ignored the significant natural gas pipeline infrastructure expansion needed to support implementation of Building Block 2. Commenter s indicated that Southern Company currently holds about 2.5 Bcf/day of firm natural gas transportation to manage its natural gas

fired resources, and that to s ecure that firm transportation, Southern Company participated in almost 20 pipeline expansion projects, with each one taking an average of 3 years to complete with the longest one taking 5 years. Commenter s stated that Alabama, Florida, Georgia and Mississ ippi will need approximately 2.5 Bcf/day of additional firm transportation to achieve EPA's 70 percent capacity factor goal, and that this additional pipeline infrastructure will be costly and cannot be constructed in the required timeframe. Commenter s add ed that these expansions will be complicated by the increase in natural gas demand from LNG exports and the industrial and transportation sectors. Commenter s asserted that the EPA did not acknowledge the fact that significant additional pipeline capacity w ould be needed, nor did it factor in the cost of the additional pipeline infrastructure.

Commenter s discussed the amount of time required to complete new pipeline projects. Commenter s referenced an ICF International effort which compiled a list of gas pipe line projects for the years 2005

- 2014. Commenter s noted that since 2005 there were 331 expansion, lateral, or reversal (ELR) projects completed. Commenter s noted that projects took a maximum of 10 years to complete with a mean of 1.37 years. Commenter s noted that there are 71 completed new pipeline projects that took a maximum of 10 years to complete and a mean of 2.32 years.

Commenter s stated the EPA's assumption that the power 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. Commenter s stated the infrastructure and supply issues cannot be corrected be tween now and 2020 or 2030. Commenter s stated that EPA has 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.

Commenter s recommended that changes be ma de to the rate at which Building Block 2 is deployed as part of the goal

- setting process. Commenter s stated that, while many states would be able to rapidly increase the utilization of existing NGCC facilities, others may require additional time because of infrastructure constraints, characteristics of existing in

- state generation facilities, or because of their load centers' locations in the electric or gas transmission system. Commenter s stated that procuring adequate natural gas supplies to sustain a hig h level of utilization year round could mean, in the case of some states, building new pipelines or increasing the capacity of existing ones. Commenter s stated that, because of 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 final goal in 2029. Commenter s stated that, in contrast, the two other building blocks, have no impact on annual rates between 2020 and 2029 because the g oal computation formula raises efficiency levels of coal plants and utilization of NGCC facilities to their final target levels in 2020. Commenter s stated that, by this approach, the EPA implicitly "front loads" emission rate reductions associated with Bui lding Blocks 1 and 2 under the proposed rule. Commenter s 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 commen ter s agreed with EPA's conclusion that, over time, existing fleets have the technical capability of reaching a 70 percent capacity factor, commenter s agreed with stakeholders who are recommending to EPA that changes be made to the rate at which Building Bl ock 2 is deployed as part of the goal

- setting process.

Commenter s stated that such a large increase in natural gas usage would also require vast expansion of Florida's natural gas pipeline infrastructure, which could not be completed as quickly as EPA's mo del projects natural gas demand increasing. Commenters stated i nadequate pipeline infrastructure, coupled with the retirement of practically all coal

- fired generation, also produces significant reliability concerns for Florida.

Commenter s stated the EPA's Regulatory Impact Analysis, which projects a four to eight percent increase in pipeline capacity by 2020, fails to consider increased natural gas demand for local distribution companies for residential use and consumption to support the commercial and indu strial sectors. Commenter s stated that, while it is feasible for additional infrastructure to be built, this will require appropriate time that is not sufficiently provided for in EPA's proposal especially with respect to the interim goal that begins in 20 20, further supporting the need for additional time to facilitate planning for an orderly transition.

Commenter s stated that, even if it was determined to be cost effective and provide a lower carbon footprint, gas supplies and the infrastructure to bring it to new Nebraska natural gas generation facilities cannot be added in a timely manner to comply with the Plan as proposed.

Commenter s stated the Clean Power Plan provides inadequate time to add required pipeline or related resource capacity by 2020. Commenter s stated the EPA did not analyze the effect of increased use of natural gas nationally. Commenter s stated t hat such national use for baseload270 electricity generation could lead to increased market dislocations, such as seen in the winter of 2013

- 2014. Commenter s referred to a NERC report which indicated that increased natural gas use will require pipeline expans ion and that additional pipeline capacity will be needed in Arizona, Nevada and the New England states.

Commenter s stated that, in order to replace the load formerly served by displaced generation from all of its coal

- fired EGUs, Tri

- State will be forced t o purchase power from other generators at great cost or to construct new generating capacity altogether (which would not be possible in the timeframe set by the Proposal), despite Tri

- State's significant investments in its current generating fleet. Comment er s stated the EPA's assumption 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 power system economics, physics, and operations.

Commenter s referred to the NODA (79 FR 64548) and stated the Proposed revisions affecting the "2020 to 2029 Glide Path" for Block 2 requirements provide little relief from the stringency of EPA's interim standards. Commenter s supported consideration of nat ural gas pipeline expansion or transmission improvements that are needed to support more use of existing natural
gas

- fired generation, but stated this does not address 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 have the CAA authority to implement this Block to begin with.

Commenter s stated the EPA should examine whether additional pipeline capacity would be needed for a state to meet the high utilization rates of NGCC units by the start of the program in 2020, and by what date new or expanded pipelines could reasonably be permitted, sited, and constructed. Commenter s 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. Commenter s 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 utilization of the state's coal

- fired units. Commenter s stated that building ou t the transmission grid is a very lengthy, costly effort and the Proposed Rule imposes building block 2 at the start of the compliance program.

Commenter s added that increasing generation from existing NGCC units also may require electric transmission upgr ades 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). Commenter s indicated that it may take e ven longer if a project crosses federal or tribal lands. Commenter s asserted that these infrastructure constraints will challenge states' ability to achieve significant changes in dispatch before

- and even after

- 2020. Commenter s noted that recognizing i nfrastructure challenges and the need to make investments, the EPA provides some time for other reductions measures, namely RE and EE to ramp up, but provides no such flexibility for equally important changes in dispatch. Commenter s stated that as more nat ural gas goes into the production of electricity, the natural gas infrastructure may not be able to meet the natural gas demand during periods of high energy demand (winter heating season). Noting that additional natural gas pipeline infrastructure is271 curr ently being built, Commenter s pointed out that there is growing public opposition to new natural gas pipelines. As an example, Commenter s stated that Spectra Energy has proposed a 465

- mile, $3.5 billion pipeline and compressor station (the Sabal Trail Pipe line) 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 challenged Spectra Energy and FERC officials on the proposed route and site for the pipeline and p umping station, with scores of negative comments from standing room only public information meetings. Commenter s concluded that growing public opposition and obstruction to new natural gas pipelines and pumping stations may prevent adequate natural gas inf rastructure from being built within the time frame proposed in the CPP to meet a 70% dispatch rate for NGCC by 2020.

Commenter s disagreed with the Proposal regarding pipeline capacity expansion in South Carolina. Commenter s referenced the GHG Abatement Me asures TSD (at 3

- 18) and stated the proposal assumes that pipeline capacity in the Southeast can be increased by 61 percent based on the Southeast Energy Information Administration (EIA) estimate of pipeline capacity expansion in the region. Commenter s sta ted this expansion is not possible in South Carolina during the time frame given by the EPA for compliance. Commenter s stated 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 in South Carolina were zero. Commenter s stated that, because South Carolina has two interstate gas pipelines which are both at full capacity, to achieve the targeted increase in natural gas utilization, add itional pipelines or expansion of existing pipelines would be necessary. Commenter s stated that typical planning, permitting and construction schedules for new pipelines are approximately 5 years, a time frame which would be beyond the initial compliance p eriod as proposed by the EPA. Commenter s noted that Duke Energy, Piedmont Natural Gas, and Dominion recently announced a joint project to build a 550

- mile natural gas pipeline from West Virginia to North Carolina which is not expected to be operational for a full 4 years and which still requires FERC approval. Commenter s stated the EPA has not given adequate consideration to the cost of such expansion and indicated the Duke pipeline project will cost between $4.5 and $5 billion. Commenter s stated the Propos al's implementation date of 2020 is arbitrary, 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.

Commenter s stated that it is not clear, and the administrative record does not demonstrate, that the states in which SCPPA's generation and transmission assets are located will be able to develop sufficient additional transmission and pipeline capacity by 2020, the year in which the EPA a ssumes Building Block Two will be fully implemented. Commenter s stated that increasing NGCC capacity factors to the levels assumed by the EPA will likely require additional investments in transmission infrastructure and natural gas pipeline capacity in man y parts of the West. Commenter s stated that these kinds of investments in transmission and pipeline infrastructure, which typically require numerous, significant federal and state permits, rights

- of

way, and other regulatory approvals, will be costly and l engthy. Commenter s cited a NERC estimate that it takes three to five years to plan, permit, and build additional pipeline capacity. Commenter s added that environmental permits to address water and endangered species issues, in particular, could prove diffi cult to obtain in some parts of the West.272 Commenter s stated the EPA needs to account for the timeframes to develop and permit the necessary infrastructure for new NGCC. Commenter s expressed concern that the 70% utilization rate calls into question the cos ts and time associated 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 infrastructure built. Commenter s requested the EP A to examine the current state of infrastructure and realistic projections of the time and cost to upgrade or construct natural gas pipeline and transmission facilities needed to eliminate or reduce specific state and regional constraints that impact the 7 0% assumption.

Commenter s expressed concern about the aggressive compliance timetables established by the Proposed Rule and the implicit assumptions about the feasibility of an unprecedented expansion in construction and generation from NGCC facilities and associated natural gas infrastructure. Commenter s stated it is not realistic to expect that sufficient natural gas transportation and distribution systems would be in place by 2020 to accommodate the substantial shift in generation envisioned by the Propo sed Rule. Commenter s stated that, though companies like Caterpillar certainly would respond to increased natural gas infrastructure demand, the EPA fails to account for non

- market delays that are likely to arise as this infrastructure is advanced. Commente r s stated that permitting requirements across 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 dema nd created by the Proposed Rule.

Commenter s stated the assumptions in the block 2 analysis 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 t he customers. Commenter s added that Minnesota's "Buy the Farm" law requires that when utilities cross agricultural land, the utility must buy the entire tract of land if the farmer wants out of the land. Commenter s stated this cost adds onto to the typical $1.5 million to $2 million per mile investment in a transmission line.

Commenter s stated that, in the case of Nevada, a transition to 70% utilization of natural gas resources and shutdown or retirement of large am ounts of existing baseload capacity is not feasible by 2020. Commenter s stated that, in Nevada, the assumption that there is "unused gas capacity" available to replace the coal/fossil generation is inaccurate and is a direct result of EPA's utilization of an annual capacity factor, instead of a peak capacity factor. Commenter s stated this scenario is a reason for EPA to consider the elimination of the proposed interim glide path goals, or at a minimum, allowing all Building Blocks to be phased in over the f ull compliance period. Commenter s 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 ensure relia bility and minimize consumer impacts.

Commenter s stated that infrastructure and supply issues cannot be corrected between now and 2020 or even 2030.

Commenter s agreed with stakeholders who suggested to EPA during the comment period that the

re

- dispatch of NGCC units contemplated under Building Block 2 cannot reasonably be expected273 to occur on day one and supported the recommendation put forth in the October 28th NODA that Building Block 2 should be phased in similar to Building Blocks 3 and 4.

Commenter s s tated, that, in addition to the development of new transmission, the permitting and construction of natural gas pipelines that are necessary for re

- dispatch to NGCCs could take many years. Commenter s stated that new pipeline construction takes, on average, three to five years, although it can take more time if the project faces environmental permitting challenges or public opposition. Commenter s stated the EPA has not adequately considered the impact of these infrastructure constraints on states' abilities to increase NGCC utilization to 70 percent.

Commenter s stated the EPA should consider infrastructure 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. Commenter s stated these constraints include plant

- level infrastructure constraints, lack of transmission lines, and inadequate gas supply, transport, and storage. Commenter s noted the EPA also must consider the costs of overcoming these infrastructure

con straints and stated that new 345 KV transmission lines cost $2.3 million per mile, without substation costs. Commenters stated n ew natural gas pipelines cost nearly $4 million per mile (See Christopher E. Smith, US pipeline operators sink revenue growth in to expansion, Oil & Gas Journal (Sept. 2, 2013), available at http://www.ogj.com/articles/print/volume

- 111/issue

9/special

- report

- pipeline

- economics/us

- pipeline

- operators

- sink

- revenue

- growth

- into

expansion.html). Commenter s stated that, despite the signifi cance of these costs, EPA has not considered them in its BSER analysis. Commenter s stated, for example, one Class of '85 member cannot increase the utilization of one of its efficient NGCCs because the transmission will not disperse all of the surrounding wind energy. Commenter s stated that, if the owner attempted to run the plant more, it would violate the Federal Energy Regulatory Commission's market power rules prohibiting uneconomic production. Commenter s cited a NERC report stating that significant tra nsmission constraints must be overcome 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 construction require long

- term system planni ng

- typically a 10

- 15

- year outlook.... Given the significant changes and locations anticipated to occur in the resource mix [as a result of EPA's Proposal], it is likely that additional new transmission, or transmission enhancements, will be necessary in so me areas. New transmission lines will be required to transport the amount of renewable generation coming online, particularly in remote areas, and that creates additional timing considerations. Further, as replacement generation is constructed, new transmi ssion may be needed to interconnect new generation. Mitigating transmission constraints identified from the proposed EPA regulations in a timely way, consistent with [the Proposal's] targets, presents a potential reliability concern.

Commenter s stated the EPA's Building Block 2 analysis 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. Commenter s stated that natural gas is sus ceptible to supply constraints and extreme weather conditions such as the 2014 polar vortex. Commenter s stated a NERC reliability study found higher than usual forced electric outages during the vortex, with outages concentrated at natural gas

- fired units. Commenter s stated re

- dispatch could exacerbate these grid disruptions. Commenter s stated that a NERC study found that increased reliance on natural gas

- fired generation (1) would require greater electric transmission from NGCC units to274 distribution networ ks and end

- users, (2) would likely necessitate development of new transmission lines or transmission line enhancements in certain areas, (3) would require permits from several state and federal agencies, and (4) could take anywhere from 5 to 15 years to

co nstruct, depending on voltage class, location, and labor availability. Commenter s stated these realities collide with the interim targets beginning in 2020.

Commenter s suggested more time is needed than the proposal allows for necessary pipeline and
transm ission upgrades in Arizona. Commenter s stated that, while the Proposed Rule would provide little time to add required pipeline or related resource capacity by 2020, the lead time to permit, design, and construct new transmission lines in Arizona is approxi mately 10 to 12 years based on recent APS experience. Commenter s provided the following statements supporting their position.

• Comments sent by the Southwest Power Pool to the Missouri Public Service Commission stated that the planning and construction of transmission upgrades can take up to eight and a half years and cost up to approximately $2.3 million per mile for new 345 kilovolt transmission lines, excluding substation costs.

• NERC stated that a construction timeline for a new high

- voltage transmissio n 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 handl ing 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 fro m displacing the retired units (coal) with the existing NGCC units.

• According to NERC, building additional pipeline infrastructure investments can take three to five years to plan, permit, sign contract capacity, finance, and build.

• APS also referred to the comments by FERC Commissioners, as summarized in UARG's comments, which argue that the EPA inadequately accounted for economic and physical limitations on capacity expansions and transmission.

Commenter s stated that, because it generally takes three t o five years to permit, finance and build additional pipeline capacity, the first interim emissions reduction goals in 2020 may be too ambitious.

Commenter s stated the EPA's presumption that building block 2 can be implemented by 2020 is unrealistic and s uggested Building Block 2 be phased in over the compliance timeframe. Commenter s stated that, without further evaluating the implications on reliability, it must be assumed that additional natural gas capacity will be needed to comply with the rule. Commen ter s stated the need for new natural gas generation can be estimated by looking at the difference275 between the maximum three

- year annual average capacity factor of 37% and the fleet average since 2005 of 28%, which is equivalent to approximately 260 MW of c apacity. Commenter s stated that, assuming this capacity was used to fill rapid and short

- term load needs, new NGCC or simple cycle combustion turbine (CT) capacity will have to be built as replacement capacity; this is equivalent to approximately 13 new 10 0 MW CTs operating at 20% capacity factor. Commenter s stated that, since building any new CT or NGCC capacity will require at least five to seven years, it is clearly impossible for this capacity to be operational by 2020

-- given that it is very unlikely th e state will have an approvable plan prior to 2019. Commenter s stated that EGU outages for equipment installations have to be coordinated by the independent system operator (ISO) and this planning and approval process, along with any necessary permitting, also cannot occur by 2020.

Commenter s stated that, given the high cost, complicated siting and permitting processes for natural gas pipeline, storage and other necessary infrastructure, the timeline proposed in the CPP for increasing reliance on NGCC units is unrealistic.

Commenter s stated the EPA's proposed schedule is too aggressive to allow the most optimal solutions to emerge. Commenter s stated that the EPA failed to consider that the development of incremental infrastructure projects can have adverse socio

- economic, environmental, and land use impacts. Commenter s stated this development will take many years to complete. Commenter s sugges ted the EPA work with states develop a measured and reasonable implementation schedule, and minimize overreliance on natural gas.

Commenter s stated that the EPA's historical examples of increased dispatch to NGCC generation do not support its conclusion that full implementation of BB2 by 2020 is feasible. Commenter s 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 primarily on historical experience with NGCC generation increases. Commenter s stated the EPA is calculating that NGCC generation in 2020 could increase by approximately 47 percent from today's levels. Commenter s stated the 81 percent historic ramp rate (2005

- 2012), however, should not be measured against today's levels. Commenter s stated that, because State plans will not be approved until the middle of 2017, at the earliest, it is not reasonable to as sume that the entities responsible for compliance with state plans will undertake the substantial investments required for compliance until those plans are finalized. Commenter s stated that, if full implementation of Building Block 2 by 2020 is assumed, st ates will have at most 2.5 years to achieve re

- dispatch. Commenter s stated that, measured against the appropriate time frame, the ramp rate EPA is proposing is much higher than the historical rate it cites in support: while the historical increase of 81 p ercent 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 amounts to a ramp rate of 18.8 percent per year. Commenter s added that, in Arizona, where a 95 percent increase in NGCC generation is assumed under BB2, the ramp rate would be higher still: at least 38 percent per year. Commenter s stated that, because the NGCC starting point is now higher than it was in 2005, the amount of the increase in NGCC gener ation corresponding to any particular percentage increase will be higher now than it was then. Commenter s stated that the amount, rather than the percentage, of the increase provides a better point of comparison for purposes of determining the system's cap acity for change based on historical experience: 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, over three times higher

.

Commenter s did not agree that the proposal's compliance schedule provides flexibility and time for investment in additional natural gas and electric industry infrastructure if needed (79 FR 34857). Commenter s referenced a November 2014 NERC report and stated that in Arizona current and planned pipeline infrastructures are inadequate for handling increased natural gas demand due to the CPP. Commenter s stated that past shifts from coal to NGCC generation may have reflected low hanging fruit since the principle of least

- cost dispatch dictates that operators would have shifted generation to NGCC where the costs of transmission and gas delivery system upgrades were lowest. Commenter s stated that the first shifts therefore would have occurred where the existing transmission and fuel delivery infrastructure was already adequate. Commenter s stated that infrastructure improvements, such as natural gas pipelines, will be needed to meet future project requirements, which will be costly and require 10 to 15 years to develop. As an example of infrastructure needs, c ommenter s described two EGUs that were converted from coal to natural gas with nameplate capacity of 1,100 MW that currently cannot operate because the gas transmission line that serviced them in the past is no longer in gas service but is now in petroleum service (citing information obtained during a verbal conversation with representatives of Consumer's Energy). Commenter s stated that significant infrastructure development will likely be required and will require capital and an extensive time frame, and that the EPA proposal does not allow adequate time for these infrastructure improvements.

Commenter s expressed concern that new infrastructure will require up to 4 or more years (for generation) to 10 or more years (for t ransmission) to complete grid and utility system planning, engineering, permitting, environmental and public reviews, construction, and startup timelines. Commenter s noted that Intermountain West and Great Plains have numerous large baseload coal

fired po wer plants sited in remote locations served by dedicated mines as fuel sources and stated many facilities have limited or no access to natural gas infrastructure. Commenter s stated this brings new infrastructure challenges in terms of greater need for acce ss to natural gas pipelines and new or expanded transmission lines, as well as increasing amounts of renewable generation.

Commenter s asserted that there is far too little existing natural gas infrastructure in South Dakota to make the development of addi tional natural gas

- fired power plants feasible in the time allowed under the Proposed Rule. Commenter s stated the build

- out of such pipelines and transmission lines is still extremely slow and expensive and there are numerous obstacles to such development, including obtaining proper rights

- of

- way, clearing state and local permitting hurdles, overcoming local opposition, etc.

Commenter s requested that the EPA remove the 2020 interim target from any final standard because the necessary time for potential modi fications and additions to the existing natural gas infrastructure is not present in the CPP proposal. Commenter s encouraged the EPA to recognize that Michigan's infrastructure must support electric generation and still provide its citizens with natural ga s for home heating purposes. Commenter s described a recently completed natural gas pipeline project, stated that it is likely that other projects of this nature will be necessary to support a high NGCC dispatch scenario, noted that projects that need to ac quire 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 proposed timeline simply does not allow for the277 proper build out of the infrastructu re to accommodate EPA's accelerated dispatch of NGCC plants. Commenter s referred to Consumers Energy's recently completed natural gas pipeline project where 24 miles of 36 inch pipe was installed next to an existing natural gas pipeline. Commenter s state t he "1200B Project" was undertaken in order to complete a 90 mile pipeline corridor that better allows Consumers Energy to support our gas storage fields and provide our customers with affordable gas and also supports pipeline integrity and safety requireme nts. Commenter s stated this 24 mile project, representing ~ 0.1% of the Consumers Energy distribution pipeline, took over 400,000 person hours 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.

Commenter s recommended that EPA extend the start of the compliance period (e.g., 5 years after EPA approval of a state's compliance plan) to mitigate the constraints of building block 2. Commenter s stated that the timeframe that EPA has allowed 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. Commenter s referred to the Pace Glo bal Study and stated that, in order to make the necessary new capacity additions by 2020, the siting and air permitting activity would have to be completed by 2017 so as to allow construction to begin. Commenter s stated that affirmative commitments cannot 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

- risk will not be resolved until at least 2017 (and possibly later) when state plans under the CPP are to be finalized. Commenter s stated this means that it may simply be infeasible to add the required capacity to compensate for derates and at

- risk units by 2020. Commenter s stated it is unlikely that new infrastructure would be avail able to support the 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 comply with the interim average emissions goal.

Commenter s stated that, in order for the City's two natural gas combined cycle (NGCC) units to achieve and maintain a 70 percent capacity factor under Building Block #2, the City would be required to sell a significant portion of their output off

- system. Commenter s 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 system and it is doubtful that this level of transmission could be constructed in time to su pport the interim CO2 targets.

Commenter s stated that the major shift in generation to NGCC over the next five years is infeasible for many existing units because of technical limitations, gas pipeline infrastructure constraints, and/or regulatory limits. Commenter s stated that gas pipeline construction and upgrades require permits and approvals at the federal, 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 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 comply with the interim average emission s goal. Commenter s referenced a 2014 Energy Ventures Analysis, Re

- dispatching Gas Combined Cycle Units, and stated the pipeline infrastructure in the Western United 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.

Commenter s stated that, by requiring the transition from coal to NGCC, utilities will need to upgrade the existing pipeline infrastructu re and construct new NGCC generation facilities. Commenter s stated that, since the construction projects could have environmental impacts based on the sites and scope of facilities requiring construction, the CPP should be required to address these impacts from an environmental and economic basis and determine if the reductions in CO2 emissions off

- set or are justified based on the impacts and costs. Commenter s stated that, while the CPP has modeled plant closures and the amount of natural gas generation th at 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 economic impact of the projects.

Commenter s stated the EPA has not addressed the concerns that have been raised by FERC that gas pipeline adequacy should be considered from a regional perspective, not just a national perspective, due to existing constrains on this system (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 Representatives (July 29, 2014), at p. 4).

Commenter s stated that building block 2 has not been adequately demonstrated because re

dispatch from coal

- fired units to NGCC units in order 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. Commenter s indicated that this problem is not hypothetical; it is a reality, as evidenced b y the events that took place this past winter, when natural gas

- fired facilities experienced significant problems obtaining a consistent, affordable supply of natural gas to run their units. Commenter s asserted that increasing the capacity factor of NGCC u nits to 70 percent will only exacerbate the problem. According to the commenter s , the EPA acknowledges 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 flexibility 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 n ot allow for enough time to build the infrastructure needed to implement building block 2.

Commenter s asserted that the EPA has not adequately addressed in the record these significant barriers that exist to ramping up the use of natural gas and renewables in the electricity generating sector by 2020 and 2030. Commenter s noted that in order to meet the EPA's interim goals between 2020 and 2030, this capacity realistically needs to be in place by 2020. Commenter s 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 build the infrastructure to support these forms of generation.279 Commenters stated that the Agency suggests that pipeline infrastructure will have sufficient time to expand if necessary to accommodate Building Block 2 because the Proposed Guidelines "provide for flexible implementation that will permit efficient scheduling of infrastruc ture upgrades as needed" (GHG Abatement Measures TSD at 3

- 16). Commenters presume that the EPA is suggesting that states may delay full implementation of Building Block 2 because compliance with the proposed state interim goals is based on average emission s from 2020 to 2029; however commenters stated that the "flexible implementation" timeline the EPA claims to have provided states is largely illusory, particularly with respect to Building Block 2.

Commenter s noted that tor most states, re

- dispatch under Building Block 2 accounts for the most significant emission reductions of any building block, and EPA calculated the proposed state goals with the assumption that Building Blocks 1 and 2 would be fully implemented by 2020 (79 Fed. Reg. at 34905

- 06; Goal Co mputation TSD at 18 (noting that in calculating state goals, only "the RE and EE assumptions change for each year from 2020 through 2029")). Commenter s stated that delaying full implementation of Building Block 2 in order to allow for necessary infrastruct ure development would significantly increase a state's emissions in early years of the 2020 to 2029 compliance period, forcing the state to achieve more drastic emission reductions in later years in order to comply with the interim goal on average. Thus, t he commenter s believe d that most states will need to implement necessary infrastructure improvements to accommodate Building Block 2 by 2020 or very soon thereafter. According to the commenter s , this timeline is likely infeasible, given that gas pipeline projects often require a decade to complete, in part because the timeline for environmental permitting can be lengthy.

Commenter s stated that although significant gains have been made in the past several years in locating new sources of natural gas, littl e has been done to improve the infrastructure needed to connect this new gas to power plants. According to the commenter s , INGAA predicts that the natural gas industry will need to construct 2,000 miles per year for the next 20 years of new gas transmissio n mainlines and laterals to meet demand (citing The INGAA Foundation, Inc., "Jobs& Economic Benefits of Midstream Infrastructure Development: US Economic Impacts Through 2035," at ES

- 1 (Feb. 15, 2012), availab le at http://www.ingaa.org/ File.aspx?id=17744 ; also The INGAA Foundation, Inc., "North American Midstream Infrastructure through 2035: Capitalizing on Our Energy Abundance," at 38 (Mar. 18, 2014), available at http://www.ingaa.org/Foundation/Found ation

- Reports/2035Report.aspx). Commenter s stated that INGAA and other industry groups also stated recently that more than 338,000 miles of pipeline will need to be constructed between 2014 and 2035 (citing Comments of American Petroleum Institute, Associa tion 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. Fi sh and Wildlife Service and the National Marine Fisheries Service Published on May 12, 2014, at 5 (Oct. 9, 2014), available at http://www.ingaa.org/File.aspx?id=22680). For perspective,

c ommenter s added that there were about 306,000 miles of gas pipeline i n 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).

Commenter s st ated the pipeline and infrastructure availability assumptions by EPA are unrealistic and the time frames set forth in the Proposal will not allow for the development of280 pipeline infrastructure needed to meet the high capacity demand necessary for baseload generation.

Commenter s stated that, in addition to the development of new electric transmission, the permitting and construction of natural gas pipelines that are necessary for re

- dispatch to NGCCs could take many years. Commenter s referenced the NERC Ini tial Reliability Review and stated that new natural gas pipeline construction takes, on average, three to five years.

Commenter s stated the EPA has failed to adequately evaluate the redirection of power given the current grid availability and resource loca tion, consequences of such a significant increase in natural gas consumption, and the timeframe that necessary infrastructure improvements will require. Commenter s stated that increased transportation capacity also requires compression and pumping infrastr ucture and working gas storage capacity. Commenter s stated that, with the Proposed Rule's projected increase in demand for natural gas from 25

- 32 states, the current infrastructure upgrades and increased capacity will only increase more. Commenter s 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. Commenter s concluded that building this volume of new natural g as is not feasible by the Interim Goal, possibly not even before the Final Goal.

Commenter s stated that, while the EPA has assumed that sufficient natural gas pipeline infrastructure is available to deliver the fuel needed for NGCC units to ramp up to a 70 percent capacity factor, there is no support for this assumption in the record. Commenter s 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. Commenter s stated these infrastructure limitations are exacerbated by th e fact that the proposed state goals are calculated assuming that states will fully implement Building Block 2 by 2020, giving states and utilities only a few years or less in which to expand gas and transmission infrastructure as needed to reach the targe t level. Commenter s noted that, with 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 case during the winter. Com menter s noted that during past winters, pipelines were fully subscribed and experienced winter constraints.

Commenter s stated that, while interstate natural gas pipelines are permitted by FERC based on "firm" demand for natural gas, power plants typically purchase natural gas on an "interruptible" basis. Commenter s 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. Commenter s stated the EPA failed to adequately consider the time it takes to build the additional natural gas infrastructure necessary to achieve the target capacity factors set in Building Block 2. Commenter s stated that, according to the current schedule, EPA will be approvi ng, or disapproving, state plans between 2017 and 2019 and compliance with the proposed guidelines begins in 2020. Commenter s stated that, presuming a state plan is approved, there will be one to three years to come into compliance with the state plans. Co mmenter s stated EIA estimates that an interstate natural gas pipeline takes approximately three years to complete between announcement and completion. Commenter s 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.

Commenter s stated there is not enough existing NGCC in this country to make up for t he forced reductions in coal generation. Commenter s stated the gas supply and infrastructure in this country are not available or reliable enough to serve all gas generation that will be needed. Commenter s stated this leaves a significant gap between energ y that can be generated and remain in compliance with the CO2 goals and energy that must be generated to continue to supply reliable electricity to the population.

Commenter s stated that, by the summer of 2017 pipelines will have the capacity to deliver in to Peninsular Florida approximately 5.6 billion cubic feet per day, although not all this capacity is deliverable to all major load centers and generation locations. Commenter s stated that the siting and construction of incremental pipeline capacity and de livery laterals will be necessary to accommodate dispatch of these resources. Commenter s stated this development will take many years to complete, cost Floridians hundreds of millions of dollars, and place Florida in a dubious position with an overreliance on a single fuel which creates reliability deterioration and cost increases.

Commenter s stated that the natural gas infrastructure is not adequate in Georgia to support current demand and a 70 percent dispatch rate for NGCC. Commenter s indicated that alth ough 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 available amount of standby, peak demand, and emergency based power. Commenter s noted that this proposal 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 ti me that natural gas demand for residential heating peaked. Commenter s 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 nat ural gas residential heating supplies.

Commenter s stated that, without any certainty as to whether the necessary pipeline capacity exists or will exist, EPA should reconsider Building Block 2. Commenter s stated that, not only is gas pipeline capacity alrea dy strained during peak demand periods, but it remains uncertain whether additional, sufficient gas pipeline infrastructure will be built, either in the near or long

term future, to allow the levels of re

- dispatch projected by EPA. Commenter s stated the EP A has not adequately evaluated whether the current national gas pipeline capacity is sufficient to handle the increased supply of gas that this Building Block would require. Commenter s referred to NRECA's comments that the EPA has failed to properly accoun t for the substantial growth that will be required in the existing gas pipeline infrastructure 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. Commenter s stated the EPA has failed to account for the FERC process, or the myriad of other federal, state and local environmental statutes that affect the ability to permit such facilities. Commenter s concluded that the notion that282 all of this new capacity can be planned, designed, permitted and installed by 2020 is arbitrary and capricious.

Commenter s stated the EPA failed to give adequate consideration to potential infrastructure challenges from significantly increasing NGCC utilization. Commenter s stated natural gas pipelines have limited carrying capa city and in many parts of the country natural gas is utilized for both electricity generation and home heating. Commenter s stated substantial, coincident increases in natural gas utilization in the power sector could strain limited pipeline capacity. Comme nter s stated that, because existing NGCC facilities 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 re ach consumers.

Commenter s 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 commenter s , assuming additional output as a result of a 70 percent CF from these units during another event of this magnitude would most certainly put large swaths of the United States at risk of unmet electricity demand, potentially creating brownouts or blackouts. Commenter s asserted that a more appropriate target would be in the low 40 percent range for CF of NGCC units.

Commenter s stated the CPP requires significant projects not available in 2012 or before, and cannot be considered "adequately demonstrated". Commenter s stated it is inaccurate to assume that permitting a new pipeline can occur over a short time frame since pipeline expansions take years to plan, engineer, procure, and approve through federal, state, and local agencies/jurisdictions. Commenter s stated the proposed rule is essentially requiring expansion projects which have not yet been proposed or permitted.

Commenter s expressed concern that the EPA analysis does not address the length of the regulatory approval process for the siting of new pipelines.

Co mmenter s 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, especially in the s hort term before additional infrastructure can be built. Commenter s stated the lack of available natural gas infrastructure will limit the availability of natural gas for all consumers, including NGCC power plants and will make it difficult for NGCC power plants to achieve the capacity factors EPA assumes.

Commenter s stated the proposed rule does not recognize the significantly long lead

- time that permitting and building new natural gas pipeline capacity can take. Commenter s stated that most interstate pipe line projects arc severely capital intensive, require ten years or more long

- term contracts and can routinely take more than five years to permit and build. Commenter s stated that, in order for pipeline capacity constrained states such as Arizona to utiliz e more gas, new pipeline projects would need to be constructed. Commenter s 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 capacity

.283 Commenter s 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. Commenter s stated there are many moving parts in this plan to ass uring sufficient gas pipeline and supply to gas turbines and sufficient transmission from generators that need to fall into place without a hitch to meet EPA's timeline. Even with sufficient gas supplies, commenter s stated the EPA timelines are too tight t o assure adequate transportation 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 customers on a firm basis.

Infrastructure

-- transm ission

Commenters suggested the EPA's timeline does not take into account the time required to address infrastructure concerns.

Commenter s stated that officials at the Southwest Power Pool have noted that major new transmission projects can take up to 8 1 /2 years . Commenters stated g rid operator urges EPA to delay carbon plan implementation by 5 years

.

Commenter s stated the EPA should allow for time to study existing generation mixes and transmission constraints anticipated by the final rule in order to modify the transmission system to eliminate the need to operate higher emitting generation to maintain system st ability. Commenter s stated the CPP will displace coal generation 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. Commenter s stated that the emission rates of simple cycle natural gas generation are significantly higher than NGCC and rival that of base loaded coal. Commenter s stated that frequent Transmission Load Reduction (T LR) events have required the reduction of generation from renewable generation sources, NGCC and coal to stabilize the system. Commenter s stated the requirement of the CPP to generate electricity using NGCC and renewable sources without time to study the i mpacts to the transmission system will create even more reliability and system efficiency problems.

Commenter s stated the EPA should allow that, upon a demonstration that significant transmission upgrades are reasonably necessary for a state to operate it s 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 reductions, its goal or interim goal should be adjusted to account for the time needed fo r such upgrades. Commenter s noted that the dispatch of EGUs within Arkansas is controlled by two regional transmission organizations which plan transmission systems to ensure reliability, and that this planning requires complex modeling studies, regional c ost allocation proceedings, state approval proceedings, and ultimately, construction, a process which can take four to seven years in order to plan, approve, and construct significant transmission facilities.

Commenter s , quoting EPRI's comment letter, arg ued that changes in the change in generation will almost certainly require development of new transmission 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 commissioning of new transmission facilities may be delayed.

Commenter s 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 th e 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 oil

- fired generation throughout the U.S., will strain the ability of natural gas suppl iers and pipelines to meet this growing demand. Commenter s stated the result will be an increase in natural gas price volatility and a decrease in availability, ultimately leading to substantially higher commodity costs and electric rates for Floridians.

Commenter s stated the EPA has conducted a limited analysis of whether the current system can handle any changes that become necessary as a result of changes in the amounts and locations of generation. Commenter s stated that transmission systems 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 retirements will cause power flow changes that could negatively impact the transmission system . Commenter s stated that mitigating any system problems caused by these power flow changes could require constructing new substation(s), transmission line(s), and/or transmission line(s) improvements. Commenter s noted a recent example on the Georgia Integr ated Transmission System ("ITS") involved a coal plant retirement that caused thermal overloads of a transmission line and low voltages; addressing these issues required a new 230/115 kV substation and transmission line upgrade that cost approximately $20 million. Commenter s stated that, in addition to the high costs for such projects, they often have long lead times, due to planning, design and construction requirements, including necessary environmental reviews. Commenter s stated the EPA has not adequatel y accounted for and addressed these considerations in its proposed 2020 start date for state interim goals.

Commenter s stated the EPA failed to account for logistical issues, including: how transmission costs will be divided among producers and consumers; acquiring rights

- of

- way from landowners to increase transmission capacity; and receiving land and environmental permits to implement these changes. Commenter s stated that each of these issues requires a substantial amount of time, making it questionable t hat transmission (and pipeline) capacities will be sufficient to meet the schedules set forth in the Proposal. Commenter s stated that delays can be particularly acute for changes in cooperative

- based distribution and transmission facilities, as the provisi ons of the National Environmental Policy Act are often triggered due to the enhanced Federal connections.

Commenter s expressed concern that, even after a plant is constructed, there is no assurance that the natural gas transmission and distribution and ele ctric transmission infrastructure required to properly distribute power from the plant would be available. Commenter s stated that, in the past, independent power producers in Louisiana experienced unfavorable results when they sited generation prior to est ablishing necessary transmission, and it is unlikely that LUS or any other municipal entity could receive sufficient project financing if transmission was not guaranteed.

Commenter s stated that the analysis the EPA conducted of the existing electric transm ission networks is procedurally inadequate and significantly underestimates the time required to modify transmission systems and the complexities involved. Commenter s stated the targets and timelines285 required in the Proposed Rule do not accommodate the tim elines and regulatory realities involved in expanding electric transmission capacity. Commenter s 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. Commenter s stated that, due to cost, entities are unlikely to risk the expense of expanding electricity transmission capacity if the electricity is required to be displaced by energy efficiency in a few years.

Commenter s stated that, once the EPA accepts state implementation plans under the proposed rule, it will take about two or more years for generation and transmission entities to analyze the potential requirements of their systems due to all the different possible c ombinations under the EPA's proposal and subsequently plans for additional electric transmission must be developed and analyzed in an open regional planning process that usually takes an additional two years. Commenter s stated that every change requires ne w analysis, and the building resources market can change while the analysis is being conducted.

Commenter s 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. Commenter s stated some projects take 10 years to build, while others never get built, such as the Potomac

- Appala chian Transmission Highline (PATH) project, which was proposed to address numerous electric reliability concerns forecast for the Mid

Atlantic region in the mid

- 2000s but was suspended in 2011. Commenter s 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 chosen while less controversial and smaller pipeline capacity can be built within a year or so if transportation costs justify construction and
p ermits 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 approvals, often at federal, state and local levels. Commenters believe d 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, consultations and approvals are needed from multiple government bodies to get a new transmission line permitted and constructed

- the timeline for a transmission project depends on real estate availability (negotiating rights

- of

- way or exercising eminent domain authority), environmental permitt ing requirements, public opposition and regulatory approval. According to commenters, 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 to 3 years prior to construction, and more complicated projects that will traverse federal lands, environmentally sensitive areas, or will generate public opposition may take as much as 10 years to complete.

Commenter s stated that the EPA must all ow for construction of new generation. Commenter s 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 commenter s believe d is wholly inadequate where286 new generation and required supportive infrastructure is necessary given permitting and construction of new transmission and pipeline infrastructure can take more than 10 years.

Commenters stated that many permits may be required for a new transmission line or natural gas
p ipeline, which may include the following: an Environmental Assessment or Environmental Impact Statement (required under both federal and state law, in some cases), if the project involves significant state or federal government action of any kind; a Sectio n 404 permit from the Army Corps of Engineers if dredge or fill material 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 endangered species; a Special Use Authorization under the National Forest Management Act if the project 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. Depa rtment of Interior Bureau of Land Management (BLM) if the project traverses federal lands managed by BLM; a state water quality permit (if required by a state water quality statute); fish, game, and other wildlife related permits, if the project will diver t natural flow of water bodies or otherwise affect fish and game; Section 106 National Historic Preservation Act consultation if the project might impact cultural or historic resources; a right

of

- way lease agreement; and an air quality permit if disturbe d acreage will exceed certain thresholds (citing California Public Utilities Commission, "Federal, State, and Local Permitting Processes Likely to be Required for Electric Transmission Projects" (June 2009), http://www.cpuc.ca.gov/NR/ rdonlyres/D896C1EA

- B D35

- 4BC8

- 83C8

- 32BAE959BF/0/GenericTransmissionLinePermit.pdf.)

Commenter s added that the Utah Office of Energy Development 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 miles long, crosses federal lands, and requires a federal environmental impact statement. (See Utah Office of Energy Development, Guide to Permitting Electric Transmission Lines in Utah, at iii, Fig. ES

- 1 (Aug. 2 013), available at http://energy. utah.gov/download/reports/PermittingGuide_Final%20080913%20(cd%20ver).pdf.), and in Colorado, siting transmission lines can take even longer because local governments (counties and municipalities) have jurisdiction over th e siting of transmission lines and each may impose different permit or other authorization requirements and conditions.

Commenter s stated the EPA does not address the time needed to complete critical project tasks before pipeline construction can begin, su ch as an extensive public involvement process, regulatory proceedings before local committees and commissions, obtaining rights

- of

- way, acquiring permit authorizations, conducting environmental assessments, and procuring bank financing. Commenter s stated t hese 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.

Commenter s also stated that in order to take advantage of the abundance of shale gas resources, new pipelines will be needed to transport these natural gas supplies to regions of the country that propose to build new, lower

- emitting NGCC units. Commenter s noted that if the pipelines will cross federally

- owned la nds, approval of permanent rights

- of

- way from federal land managers must be obtained and, because there is no streamlined process for obtaining such federal287 approvals, their approval can take years, which could impede the ability to expand the network of n atural gas pipelines to deliver gas for power generation.

Commenter s stated that it can take 3 to 6 years to permit and build new pipelines (citing Initial Reliability Review at 10). Commenter s indicated that the GAO report lists other applicable
statutes to include the National Environmental Policy 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 Safe Drinking Water Act and the Wilderness Act, with permitting agencies that include FERC, EPA, U.S. Corps of Engineers, Bureau of Indian Affairs, Bureau of Land Management, Department of Wildlife and Fisheries, Forest Service, DEQ and a host of other federal, state and local agenc ies as well as tribal and local governments.

Commenter s stated that increased operation of the NGCC plants could have practical implications, including permitting issues, engineering and design limitations, natural gas pipeline restrictions, availability and price volatility, and transmission limitations.

Commenter s stated that, if the federal government wants states to shift to cleaner sources of electric generation, such as natural gas, it must expedite the process of approving Environmental Impact Studi es so the necessary pipeline infrastructure can be built. Commenter s stated that, without such an initiative, the Federal government is simply setting the states up to fail.

Commenter s stated that planning, permitting, and constructing such infrastructure takes time and is expensive, and that the EPA does not appear to have taken this factor into account in the proposed rule, and instead implicitly assumes no lag time in its model for b ringing natural gas pipelines online. Commenter s 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, re liability, or sustainability of running individual units at such high capacity factors. Commenter s concluded from this that to comply with the proposed rule, and bring in the amount of natural gas required by the rule, will take much more time than is cont emplated by the proposed rule, which creates particular risks to Texas because of the disproportionate impact that Building Block 2 has on Texas's interim emissions rate. According to the commenter s , the proposed rule assumes the entire re

- dispatch is acco mplished beginning in 2020, resulting in approximately 77% of Texas's final emissions reduction be achieved by 2020. Commenter s contended that the time 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 electricity production will require. Commenter s stated that the EPA offers no analysis on the possible impacts of requiring increased use of natural gas generation. Commenter s indica ted that existing transmission constraints may preclude some EGUs from operating their natural gas plants in accordance 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 the proposed rule, there will be a need for additional gas pipeline infrastructure. Commenter s stated that a GAO report analyzed public records of interstate gas pipeline permitting processes (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 558 days; the average time for those projects that began at the application phase was 225 days." Com menter s added that the GAO report did288 not have data for the time frames required to obtain intrastate gas pipeline permits. Commenter s noted that interstate permitting must comply with various 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 complex in that they can involve multiple federal,
sta te, and local agencies, as well as public interest groups and citizens, and include multiple steps" (Id. at 12).

Time to ensure grid reliability

Commenters stated that available transmission and the transmission planning process present constraints on re

- d ispatch.

Commenter s stated that a NERC CPP report found that the timeline EPA proposes does not provide enough time to develop the resources that are needed to ensure grid reliability by 2020. Commenter s stated that, even where systems are connected and i ntegrated, there is not an unlimited ability to move flows between regions, and 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.

C ommenter s referenced a November 2014 NERC report and stated that a wholesale shift in the dispatch order away from coal

- fired units (almost all of which provide baseload power) to NGCC units (which typically provide peak or intermediate load power) will cr eate significant electric reliability issues in many parts of the grid. Commenter s referenced comments of Southwest Power Pool and stated that the transmission and pipeline systems in many parts of the country may not be capable of handling the increased d emands on their capacity that will accompany a large increase in NGCC generation. Commenter s stated that many parts of the country rely on NGCC units to provide peak generation on short notice during periods of high demand, or to accommodate system emergen cies and, if these units begin to operate as baseload units while other baseload units are retired, the electric grid could be at greater risk of blackouts or price spikes during periods of high demand or unexpected interruptions from one or more large gen erating sources. Commenter s stated these units also will be less available to balance intermittent RE generation, thus potentially raising the overall costs of integrating the higher levels RE that the Proposed Rule would require. Commenter s 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 sufficient transmission and pipeline capacity will materialize within the next few years.

C ommenter s stated that cost allocation issues will need to be addressed, rights

- of

- way must be acquired from landowners, and permits must be obtained. Commenter s stated that public opposition and lawsuits seeking to stop or move planned transmission are als o common and can add substantial delay and expense to transmission projects. Commenter s stated that it is not yet clear what modifications to transmission infrastructure may be required to support a re

- dispatch of existing NGCC capacity to achieve a 70% or greater 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. Commenter s stated that there are more problems with siting289 new transmission now than ever before, so lead times for those proposed new facilities could be even longer.

Comment 15: Commenters stated the EPA has not adequately considered the time involved in the permitting process and the impact this will have on infrastructure development

. Response 15: The EPA dis agrees that we have not adequately considered regulatory constraints and time for implementation in the 111(d) final rule. In response to additional analysis and many

com ments, we have modified the proposal and RIA ; the start of the performance period is postponed . The 111(d) final rule requires that states develop plans that establish emission standards for affected EGUs. We are providing states with substantial flexibili ty 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 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 states may consider local circumstances as they develop their plans, in cluding system reliability, fuel diversity, permitting and 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 th e CPP Final Rule supporting the final CPP.

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

Commenter s stated that significant amounts of new transmission infrastructure will be needed to accommodate Building Block 2, parti cularly in areas where load has been served by coal

- fired EGUs and NGCC units are located a great distance away. Commenter s stated that permitting, design, construction, and commissioning of new generating facilities can take many years

-- particularly when including the time needed to conduct required meteorological surveys. Commenter s stated the timeframes required to construct the new transmission and generation that will be needed to support Building Block 2 suggest that compliance with the Proposal would be impossible. Commenter s stated that, because EPA failed to consider the numerous limits on the ability of existing NGCC units (individually and collectively) to increase utilization to a 70 percent capacity factor, the Agency has not demonstrated that i ts proposed Building Block 2 target is achievable. Commenter s provided the following additional comments regarding Tri

State'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 private parties before construction even begins. The timeline for a transmission project depends on completion of planning studies and tech nical analysis, real estate availability (negotiating rights

of

- way or exercising eminent domain authority), procurement of long lead time290 equipment, environmental permitting requirements, public opposition, regulatory approval, and opportunities for tie

- i n outages. A relatively simple project that will not traverse an environmentally sensitive area, require the exercise of eminent domain, or involve significant public opposition will take up to three years prior to construction. More complicated projects t hat will traverse federal lands, environmentally sensitive areas, or will generate public 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 th e 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 subject to regulatory approvals from the various entities involved before construction can proceed. Delay in approval from any of these stakeholders can delay or ultimately prohibit construction of a transmission project. These approval processes are unpredictable.

• At the federal level, implementation of the National Environmen tal Policy Act can present delays for environmental impact review, as can new species and critical habitat listings under the Endangered Species Act and the creation of new national monument designations or "exclusion" areas through wilderness areas.

• Loca ting transmission facilities on tribal land can involve substantial uncertainty and high costs.

• Within Tri

- State's service territory, state approval processes differ significantly, and in Colorado and other states, local governments have jurisdiction over siting and permitting processes on private lands. The United Power 115 kV Transmission Improvement Project required 10 years to obtain preconstruction approval for only 15 miles of transmission line. The project consisted of three phases. In Phase II, one local jurisdiction insisted on implementing an underground configuration, requiring an appeal to the 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 resolved by the courts before the project could move forward. Phase III is currently under construction.

• The Nucla

- Sunshine 115 kV project endured a 13

- year pre

- construction p rocess. The project crossed federal lands, necessitating an environmental impact statement under the National Environmental Policy Act and three records of decision. The project also required approval from two local jurisdictions, one of which demanded uti lizing underground transmission lines. Tri

- State appealed to the CPUC. The case ultimately went to district court but was settled.

• The development process for the Gladstone

- Walsenburg 230 kV Transmission Line project in New Mexico and Colorado began in 1 997 and did not end until 2006. Various New Mexico landowners refused Tri

- State access to their land for291 the purpose of pre

- construction surveys and other work. Ultimately, the New Mexico Supreme Court resolved this dispute in Tri

- State'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, which involved a condemnation process with uncooperative landowners.

• The San Luis Valley

- Calumet

- Comanche 230/345 kV project received a Certificate of Public Convenience and Necessity from 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 for 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 the San Luis Valley. The owner of a large parcel of land in a location key to the project's route successfully lobbied the f ederal government to obtain a conservation easement on his property, which not only resulted in a prohibition against construction of the transmission line but also resulted in the solar generation not being built because there was no way to transmit the e nergy.

• None of these projects are outliers. They reflect many of the common obstacles that utilities often face to obtain approval for transmission projects, particularly in areas of the West in close proximity to federal and tribal lands. It is unreasona ble for EPA to simply assume that the transmission and pipeline infrastructure necessary to implement Building Block 2 can be developed in a more expeditious timeframe.

Commenter s stated the assumptions in the block 2 analysis fail to take into account th e 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. Commenter s stated that new NGCC units require additional electric transmission, which requires substantial time. Commenter s 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 stated that, while CapX initiated the Minnesota regulatory proceedings in 2007, it will have tak en 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.

Comment er s stated the Proposed Rule also fails to take into account the fact that, if a combined cycle plant which was designed to operate intermittently 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. Commenter s referred to the CapX transmission upgrade and noted the project has taken over a decade from design through construction. Commenter s stated the Proposed Rule overlooks this issue in c alling for higher capacity factor output of natural gas EGU's into an electric grid not designed for those units to be baseload units. Commenter s stated the Final Rule needs to take this into account to give Minnesota the flexibility to ramp up its require d carbon reductions. Commenter s stated that, with292 the Final Rule being issued in mid

- 2015, history shows transmission facilities will not be online until 2026 or later.

Commenter s stated the EPA has not considered the time involved in the normal FERC regul atory siting process. Commenter s stated the transition to gas

- fired generation envisioned in BB2 is intrinsically tied to an increase in construction of pipelines to transport that gas. Commenter s expressed concern that, in setting the CO2 reduction 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. Commenter s stated this two

- year period is in addition to the time spent developing a proposal a nd preparing an application as well as the time for the actual construction of the pipelines themselves. Commenter s urged the EPA to take pipeline construction timelines into consideration in designing BB2 goals. Commenter s provided the following related i nformation.

• Under Section 717f(c) of the Natural Gas Act of 1938, 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 tra nsportation in interstate commerce of natural gas." Companies seeking to build interstate natural gas pipelines must first obtain certificates of public convenience and necessity from FERC. The Energy Policy Act of 2005 (EPAct) designates FERC as the lead agency for coordinating "all applicable Federal authorizations" and for National Environmental Policy Act (NEPA) compliance in reviewing pipeline certificate applications. There are no statutory time limits, however, within which FERC must complete its cer tificate review process.

• The regulatory process for certification of interstate gas pipelines varies depending on whether or not the pipeline developer opts to enter the voluntary
pre

- filing process before formally applying for a pipeline certificate, pursuant to 18 CFR 157.21. The pre

- filing process involves a set of specific activities including a study of the project sites, stakeholder identification and an open house for affected parties. Concurrently, FERC Staff participates in the open house and
p ublishes, pursuant to 40 CFR 1508.22, in the Federal Register a Notice of Intent for Preparation of an Environmental Assessment or an Environmental Impact Statement that opens a public comment period. FERC may also consult with stakeholders and hold public meetings and site visits in the proposed project area. The pre

- filing process requires a written request to FERC's Office of Energy Projects and commences seven to eight months before the filing of a certificate application.

• Whether or not the developer p articipates in the pre

- filing process, a developer must formally file an application with FERC in order to receive a certificate of public convenience. This application requires the submission of a description of the pipeline, route maps, construction plan s, schedules, lists of other statutory and regulatory requirements from other agencies, environmental reports analyzing route alternatives and the potential impacts on the environment, cultural and aesthetic resources, geology and land use. If the applican t did not pre

- file, FERC then begins the environmental review process that includes many of the same293 steps of the pre

- filing process. In either case, an environmental assessment is typically prepared and a more extensive environmental impact statement is a lso required where impacts are determined to be significant. 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 complicated regulatory review process for gas pipeline certificates is illustrated below:

• The FERC process of pre

- filing, filing and review can be lengthy. There are no statutory time limits within which FERC must complete 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 intrastate gas pipeline p rojects in Pennsylvania alone averaged fourteen months from filing 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

- four months solely in the regulatory re view process.

Comment 16: Commenters asserted states will not be able to meet the 2020 deadline given that a state's proposed compliance plan may not be approved by the EPA until 2018.

Response 16: The EPA disagrees that we have not adequately considered regulatory constraints and time for implementation for the 111(d) final rule. In response to additional analysis and many comments, we have modified the proposal and RIA ; the start of the performance period has been delayed . 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, 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. Neither 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 V III.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:

Commenter s stated new gas supply will not be able to be in place by 2020 given that a state's proposed compliance plan will not likely be approved 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 be as late as J uly 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 July 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 Plan is finalized and all legal issues are resolved by July 1, 2016 and the SIPs/FIPs impacting generating resources are approved on July 1, 2017, only two an d 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. Commenter s stated it is particularly impractical for electric cooperatives, wh ich must satisfy a bevy of time

- consuming requirements in order to obtain RUS financing. Commenters suggested the following timetable would need to occur 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 generation requirements and alternatives (power procurement, self

- build, joint ownership, etc.) and site selection. Begin participating in SIP process. Note: all efforts and funds ex pended 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 requirements are defined. Begin preliminary design process required for permitting.

• January 1, 2018

- Begin per mit application process. Expect application approval process to take 12

- 18 months (or longer if the state permitting agency is swamped with permit applications as a result of the CPP).

• July 1, 2018

- Begin 30

- week (minimum) financing process. This process c ould be extended due to stranded assets.

• January 1, 2019

- Begin estimated 8

- 12 month plant design, equipment procurement, and construction contracting process.

• January 1, 2020

- Commence construction

- 18

- 24 months until COD

• October 1, 2021

- Commercial op eration commences.

Commenters noted that all of the dates above reflect 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 complian ce requirements and forced unit retirements regionally and nationwide. Commenter s stated the information provided above clearly demonstrates that the retirement of RPS

- 2 by 2020 is impractical for LUS.

Commenter s recommended that EPA extend the start of th e compliance period (e.g., five years after EPA approval of a state's compliance plan) to mitigate the constraints of building block 2. Commenter s stated this major shift in generation to NGCC over the next five years is infeasible for many existing units because of technical limitations, gas pipeline and electric transmission295 infrastructure constraints, and/or regulatory limits. Commenter s stated that, even if existing NGCC units are capable of running at 70% or greater capacity, gas pipeline capacity or
t ransmission infrastructure may not be sufficient to provide the gas volumes needed to operate at these high capacity factors, especially in the short term before additional infrastructure can be built. Commenter s stated that gas supply infrastructure const raints may be further exacerbated during extreme weather events such as the past winter's Polar Vortex when larger than normal gas supplies needed for space heating reduce the gas available for generation.

Commenter s stated the significant shift to natural gas from coal would require significant investment in gas pipeline infrastructure to accommodate the increased demand for natural gas and investment in new electric transmission enhancements to address reliability concerns associated with the changing the location and mix of generation resources. Commenter s stated infrastructure upgrades, most notably gas pipelines and electric transmission lines, require permits and approvals at the federal, state, and local levels that can take five years or more to

secu re and put in place. Commenter s stated the timeframe that EPA has allowed 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. Commenter s stated it is unlikely that new infrastructure would be available to support the 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 complia nce period to comply 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 example, 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 dis agrees we have n ot considered system reliability, balancing and the integrated utility power sector for the 111(d) final 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 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 in cludes, 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 perio ds. Neither 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.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.296 The following are summaries of the specific publ ic comments under this comment:

Area

- specific issues

Commenter s disagreed with the EPA's statement that "Re

- dispatch for GHG abatement purposes would require one net MWh of a lower emitting technology displacing one net MWh of generation from higher emitting technology" (GHG Abatement Measures TSD at 3

- 6). Commenter s stated that megawatts are not directly equivalent from a legal perspective, as the courts have already decided, as well as from a technical and operational perspective. Commenter s stated the location of the generation is important in replacing net megawatt s due to transmission system constraints and grid losses. Commenter s stated the EPA inappropriately assumes that an NGCC with excess capacity exists in a location identical to the coal generation it replaces. Commenter s stated that, because the City of Tal lahassee has limited transmission import and export capability, the City cannot re

- dispatch its excess NGCC capacity, when it is available, to provide replacement power for coal fired generation at other locations within Florida. Commenter s suggested the E PA reevaluate and 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. Commenter s stated that mandating specific unit dispatch decisions on a state

- by

- state basis presents significant seam issues for states like Ohio and Indiana, where multiple regional transmissions organizations (RTOs) manage the dispatch of ele ctricity units located in different parts of the state. Commenter s referred to a PJM report on capacity imports and exports to and from the Midcontinent Independent System Operator, Inc. (MISO) and stated that that reliability requires the capacity constru ct and system planning to be consistent with actual grid operations (PJM/MISO Seams Coordination and Capacity Deliverability, presentation by PJM at FERC Meeting. June 20, 2013, http://www.ferc.gov/industries/electric/indus

- act/rto/pjm.pdf.). Commenter s st ated the dispatch decisions required by Building Block 2 are precisely the sorts of planning changes that will make efficient seam coordination increasingly difficult. Commenter s stated that, in the case of Indiana, there are multiple RTOs that manage the dispatch of electricity generated within the state. Commenter s stated a PJM report on capacity imports and exports to and from the MISO explains that "reliability requires the capacity construct and system planning to be consistent with actual grid operati ons

. " Commenter s stated the dispatch decisions required by Building Block 2 are precisely the sorts of planning changes that will make efficient seam coordination increasingly difficult.

Commenter s stated the EPA does not take into account the methods uti lized to dispatch EGUs under the FERC

- approved SPP integrated market system. Commenter s stated the EPA incorrectly assumes that the absence of existing NGCC EGUs in Kansas will not impact the energy produced by affected Kansas EGUs. Commenter s stated that, for the states in which SPP members are located it will be necessary to establish some offer curve "adder" to the cost structure of lower

- cost resources in order to accomplish the EPA average re

- dispatch of energy production for NGCC EGUs to 70% within th ose states. Commenter s stated that, as a result, the dispatch of coal

- based and other gas

- based Kansas EGUs will be reduced substantially, and the price of energy purchased from SPP will increase substantially for Sunflower's members and their consumer

- own ers. Commenter s stated that Sunflower 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. Commenter s stated the ultimate ut ilization of Holcomb 1 may approach a 35% capacity factor minimum load for the technology. Commenter s stated the economic model results indicate the effects of this NGCC re

- dispatch will result in an approximate 65% increase in the price of all energy purc hased from the pool 3

. Commenter s noted that these effects on Sunflower member

- owners and their consumer

- owners occur all the while there are no NGCC facilities located in Kansas. Commenter s stated that, because EPA has done a separate analysis of each of i ts 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. Commenter s 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 variable to introduce to these systems. Commenter s 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 considering the complicated economics that will inevitably develop when the four building blocks are combined. Commenter s stated the EPA should direct states in RT O regions to work with RTOs, utilities and pipelines to determine the level of dispatch that can be reasonably achieved and allow states to modify their targets (if necessary) to reflect the achievable level of dispatch.

Commenter s stated the EPA's conclusion that NGCC utilization 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 reliability responsibilities, exist ing energy and fuel supply contracts, transmission rights or transmission service reservations.

Commenter s asserted that in many cases, achieving such dramatic increases in NGCC utilization effectively would require substantial changes in how the natural gas industry and organized wholesale electricity markets operate, both of which are outside the scope of the proposed guidelines and EPA's general authority under the CAA. Commenter s added that while the NODA points to discrepancies and limitations of the proposed guidelines, none of the new proposals provide credible solutions. Commenter s expressed the opinion that the NODA's proposals would add subjective elements and would exacerbate some problems by grossly overestimating fuel switching potential in the states.

Commenter s said that meeting EPA's state goals through 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 take 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 could have a final, approved compliance plan.

Commenter s stated that many different types of system constraints may make it impossible or unreasonable for state NGCC fleets to dramatically increase their utilization rate. Commenter s298 referred to a 2010 CRS report (Stan Mark Kaplan, Displacing Coal with Generation from Existing Natural Gas

- Fired Po wer Plants, CRS, Jan. 2010) which concluded 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 fleet; the operating patterns of coal and gas plant s and the system's degree of flexibility to change them; the ability of the transmission system to deliver power from existing gas plants to loads served by coal plants; and the ability of the natural gas supply industry to deliver larger amounts of natura l gas where it is needed. Commenter s stated the CRS report demonstrates the importance of evaluating the electric power system as an integrated whole that comes with various locational constraints. Commenter s stated that an assessment of the "excess" natur al gas generating capacity is not enough; rather, limitations such as the location of each plant in the electric grid and plant position vis

- a

- vis nodes and load must be considered. Commenter s stated that each portion of the system, while to some extent in terrelated, is unique, with specific resources designed to fill specific needs; thus, the tailored nature of the system makes one

- size

- fits

- all solutions problematic.

Commenter s stated that the current methods of load dispatching and future reserve margin s and transmission loading need to be assessed for this revolution 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 utilization rates when in actual operation. Commenter s stated that NGCCs that have been designed to operate as intermediate or peaking units with lower capacity factors, may not be technically able to increase their utilization to 70 percent. Commenter s stated that it is n ot clear that EPA factored these situations, or the impacts of increased NGCC utilization on "must run" resources, into its re

- dispatch analyses. Commenter s stated EGU and electric system constraints may make increased NGCC utilization unachievable in the timeframe stipulated by the EPA. Commenter s 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 capacit y in the natural gas fleet;

• The operating patterns of coal and gas plants and the system's degree of flexibility to change them;

• The ability of the transmission system to deliver power from existing gas plants to loads served by coal plants; and

• The abi lity of the natural gas supply industry to deliver larger amounts of natural gas where it is needed.

According to c ommenter s , the CRS report demonstrates 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 capacity is not enough. Commenter s stated that physical (infrastructure) and operational limitations, as well as the location of each plant in relation to other generation facili ties and load, must be considered. Commenter s indicated that these locational limitations matter as much as unit size or technical capabilities, and gave the example that some NGCC units that theoretically could run at higher capacity factors will299 necessar ily be hindered by transmission constraints. Commenter s added that for coal

- based generation to be able to be replaced by increased production from existing NGCCs, the natural gas units would have to be located in proximity to the coal plant. According to the commenter s , CRS conducted a proximity analysis and concluded, based on locational constraints alone, that "[e]xisting NGCC plants near coal plants may be able to account for something on the order of 30% or less of the displaceable coal

- fired generation and CO2 emissions," and that this limitation should b e factored into any plans to replace coal with natural gas (CRS Report at 17).

Commenter s stated that equally important is whether the two units are dispatched by the same transmission operator. According to the commenter s , this concern was raised by Mon tana 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 plants would "not share a dispatch signal that would allow one plant's increased operations to result in the lower dispatch of a plant operating in a different market."

Commenter s stated that there are other system constraints that can make it difficult to displace coal with existing natural gas

- based generation. Commenter s noted that it is possible tha t increasing the capacity factor of existing NGCC units would involve the closure of coal

- based "must run" resources that could put reliability at risk. Commenter s also indicated there may not be enough actual NGCC spare capacity to achieve the necessary l evels of fuel switching that are included in the proposed guidelines. Commenter s gave 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 diffi cult to comply with the interim targets. According to the
commenter s , in explaining this situation, the Director of the Arizona DEQ pointed out that "electricity generated at a facility in the winter cannot offset the need for electricity during the peak d emands experienced in the middle of the summer." Commenter s explained that due to the extreme temperature fluctuations in Arizona, the EPA cannot assume that all capacity from natural gas units is available to be dispatched to replace coal generation

- whi le such capacity may be available to displace some coal generation during winter months, this "excess" capacity will be needed to meet summer peak demand. Commenter s added that increasing existing NGCC generating capacity may also not be possible due to co nflict 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.

Commenter s added that the EPA has not addressed the effect that incre ased existing NGCC capacity factor will have on the other Building Blocks

- existing coal and gas units do not operate in a vacuum and are part of a complex, integrated electrical system so that shifting the way these units are operated and dispatched will have impacts on other forms of generation and how they contribute to the electrical system.

Commenter s stated an assessment of the excess natural gas generating capacity is not enough. Commenter s stated that physical constraints are not uncommon in the de livery of natural gas during very cold months as the transmission to Empire's natural gas generation facilities has been interrupted by frozen compressor stations. Commenter s stated that, even when all natural gas pipeline infrastructure is operating prope rly there are numerous instances where even firm transport contracts get curtailed during extreme weather events. Commenter s stated that while Empire experienced recent curtailments on the natural gas pipeline to its generators and had to300 burn oil as an em ergency backup, not all NGCC's are equipped with the ability to use oil back

up. Commenter s stated new infrastructure and long

- term firm transportation contracts will be needed to meet the 70 percent CF computation for the states. Commenter s stated that na tural gas EGUs are dispatched only when it is economical to do so, as a back

- up to RE, and if needed to meet load requirements while ensuring system reliability. Commenter s stated the ability of existing natural gas plants to displace coal generation depen ds on many factors, and demonstrates the importance of evaluating the electric power system as an integrated whole that comes with various locational constraints. Commenter s supported the four recommendations submitted by the SPP in their comments to the P roposed Rule to address reliability inadequacies: (1) a series of technical conferences jointly sponsored by the EPA and FERC; (2) completion of a detailed, comprehensive and independent analysis of the impacts the Proposed Rule will have on the reliabili ty of the nation's bulk electric system; (3) extension of the proposed schedule for compliance in order for the necessary electric and gas infrastructure to be identified and constructed; and (4) adoption of a reliability safety valve.

Commenter s stated t he EPA needs to more fully analyze the interaction between and among electric generation, wholesale electricity markets and the natural gas and Commenter s stated the EPA did not take into consideration time constraints required to physically realign the na tural gas supplies and transmission and distribution infrastructure needed to accommodate the 2030 requirements when assessing the 70 percent capacity ability of the NGCC fleet. Commenter s 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. Commenter s 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. Commenter s 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 lines, excluding substation costs.

Work with power regulators

Commenter s stated the EPA should work proactively with electric power regulators to ensure that adequate pipeline capacity is available for the expanded dispatch of gas

- fired generation. Commenter s agreed with the EPA that natural gas pipeline capacity, with feasibl e amounts of expansion, can meet the needs of increased natural gas use to reduce carbon pollution. Commenter s noted that the EPA has found average monthly fleet

- wide NGCC utilization rates have reached 65%, showing that the pipeline system can currently s upport these rates consistent with the increased use of natural gas as BSER for an extended period (79 FR 34863). Commenter s agreed with the EPA's observation that pipeline and transmission planners have repeatedly demonstrated the ability to methodically relieve bottlenecks and expand capacity (79 FR 34864). Commenter s stated the EPA should work proactively with entities such as FERC and ISOs on issues such as gas

- electric market coordination and the use of firm pipeline capacity by natural gas generators. Commenter s stated that, for instance, market rules may unduly hamper the use of natural gas generation, such as the failure to allow the recovery by natural gas generators of firm pipeline transportation costs.

Commenter s encouraged the EPA, before it pro ceeds with a final rule, to consult with federal and state agencies with greater expertise in operation 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 gre ater understanding of the infrastructure 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. Commenter s stated this understanding is fundamental to establishing the technical feasibility of Building Block 2. Commenter s expressed concern that the high proportion of federal, state, and tribal lands in the Western U.S. represent unique challenges to timely completion of n ew energy

- related projects.

Commenter s stated that, given the warranted concerns from the region's top energy officials on

over

- dependence on natural gas, the EPA must work with others and allow those with the expertise and authority to propose changes rel ated to the dispatch of electricity. Commenter s stated that, since New England states are not likely to take a path that would place their utility customers at risk, the state goals should be changed to reflect the actual natural gas constraints. Commenter s stated that, according to the Independent System Operator for New England (ISO

NE), the factors contributing to natural gas fuel availability issues are inadequate infrastructure, unreliable fuel arrangements, limited storage, and out of sync markets. Co mmenter s stated that, under the EPA's model, New England as a whole is projected to have no remaining oil or coal resources, which would be highly detrimental to the region's reliability as well as customer rates.

Commenter s requested the EPA to work with reliability experts, states, and industry stakeholders to undertake a detailed, comprehensive analysis of potential reliability impacts of the CPP before it is finalized.

Commenter s stated the EPA's final guidelines must consider the role that FERC, NERC

, RTOs/ISOs have in assessing technical feasibility and reliability implications of Building Block 2. Commenter s stated that, due to the interconnected nature of the electric and natural gas systems, the EPA should allow states sufficient time to complete regional studies to assess the adequacy of infrastructure systems to support increased natural gas use for electric generation.

Commenter s stated that NREA members feel it is imperative that EPA consult with Federal Energy Regulatory Commission (FERC), Nor th American Electric Reliability Corporation (NERC) and Regional Transmission Organizations to determine the impacts on reliability, cost stabilization and national security issues. Commenter s stated the NERC, the Midcontinent Independent System Operator ( MISO) and Southwest Power Pool (SPP) have reviewed the proposal and have expressed significant concerns about reliability. Commenter s stated a major concern in Nebraska regarding reliability is the need to meet consumer loads primarily with natural gas and renewable generation. Commenter s stated a lack of sufficient pipeline infrastructure to increase the supply of natural gas and the time constraints with modifying existing plants and building new plants render it impossible to meet the deadlines in the EP A Proposal.

Regional feasibility studies

Commenter s stated the EPA should conduct a state

- by

- state study to determine the time required to finance, permit, construct and commission new NGCC EGUs taking into account what NGCC units can burn oil in order to reach the 70 percent capacity goal in Building Bloc k #2. Commenter s stated that the CPP will result in increased costs. Commenter s 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 associa ted costs. Commenter s stated the EPA should take other environmental concerns into consideration when establishing NGCC capacity factors and the economic analysis for the Proposed Rule. Commenter s stated the EPA did not, but should, take into consideration the costs and project delays for right

- of

- way obtainment and for the construction of natural gas supply pipelines and transmission infrastructure to accommodate the Proposed Rule computations. Commenter s stated commodity costs associated with supply and d emand economics will escalate due to more than doubling the amount of natural gas used for electricity production.

Commenter s referenced a reliability impact assessment of the EPA's Proposed Rule within the SPP region, using as its baseline the generator retirements 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 expansion will be necessary from a reliability perspective: after incorporating the EPA's assumptions 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 generation. Commenter s 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 face a significant loss of load and violations of regulatory reliability standards. Comment er s stated that, according to the impact assessment, SPP's transmission system could face severe overloads that will lead to cascading outages. Commenter s stated that, in general, the report indicates not enough time is allowed to compensate for projected generation unit retirements, nor to build the transmission infrastructure necessary to maintain system reliability.

Emergencies

Commenter s stated that, although the EPA indicates consideration is given in the flexibility of state plans to accommodate emer gencies, the stringency of the interim and final goals for this building block creates a shift in a direction that cannot be reclaimed during emergencies. Commenter s stated that, during the extremely cold weather experienced earlier this year the SPP deter mined the activation of oil

- fired generating units was required in addition to our coal

- fired and natural gas

- fired generation in order to provide reliability on a system

- wide basis. Commenter s stated that during a reliability event dispatch 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. Commenter s stated the delivery of electricity is extremely complex a nd the system must be built to withstand extreme weather.

Commenter s stated that a presumed ability to activate NGCC at 70 percent utilization does not offer the diversity needed to respond to common occurrences, let alone emergency situations. Commenter s stated that overdependence on any one energy source such as natural gas will not allow adequate response capabilities in emergencies. Commenter s stated the electric generation system has become increasingly dependent on the operation of the natural gas sy stem and the natural gas system is also dependent on electricity for its ability to deliver natural gas from the well

- head to the consumer. Commenter s stated that, in the event of grid failure, both systems could be disrupted. Commenter s asserted that each state, along with the RTOs in that state, must303 be able to have the time to fully assess the options available during extreme weather and emergency events and maintain robust diversity in generation options.

Commenter s stated that Empire and other owners of NGCC EGUs will need to continue to have alternate fuel capability in the regions in which they operate to allow for contingencies. Commenter s stated that natural gas supply deficiencies and historical price volatility experienced by Empire continue to d rive the decision to maintain fuel diversity in our generation mix. Commenter s stated that a significant reliance on natural gas creates additional risks as it is impracticable and geologically impossible to locally inventory the fuel for our fleet. Commen ter s stated there will be events which cause deliverability issues and in some cases shortage of the commodity due to circumstances of risk that exist today. Commenter s stated that, during a recent natural gas supply shortage issue, fuel oil, which is trad itionally a significantly higher priced fuel, became a better economic decision than the utilization of natural gas or market power.

Comment 18: Commenters generally stated that more analysis is needed, such as plant

- level impacts, state

- specific actions , pipeline growth rate, population growth, storage, high pressure, variability of loads, and limitations in rural areas.

Response 18: The EPA dis agrees that we have not considered system constraints and demand in the development of the 111(d) final rule. A dditional 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 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 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 states may consider local circumstances as they develop their plans, including system reliability, fuel diversity, demand 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 Measures TSD for the CPP Final Rule supporting the final CPP.
The following are summaries of the specific public comments under this comment:

Aging pipe lines need to be analyzed

Commenter s stated the EPA must consider the hazards posed by aging pipeline infrastructure. Commenter s cited a US DOT report showing the age distribution 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 descri bed the impacts from a pipeline rupture that occurred on December 11, 2012. Commenter s stated that, for these reasons, they have very serious questions about whether 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. Commenter s stated that critical issues include reliability problems for the electricity grid; delivery problems for residential, commercial and industrial customers during periods of extreme cold; public safety problems from the explosive nature of compressed natural gas; and the environmental hazard from uncontrolled releases of methane.

Analyze interactions between the Building Blocks

Commenter s also stated that the EPA's inclusi on of re

- dispatch to NGCC units at 70 percent in the proposed BSER may also eliminate needed flexible generation to balance intermittent generation resources that are low

- carbon emitting, causing additional impacts to the system as whole. According to the commenter s , both FERC and EPRI have noted an increased and growing need for flexible generation capacity at the national level for balancing and regulation, particularly in the morning and evenings, due to rapid changes in solar and wind generation. Commen ter s indicated that the EPA's inclusion of renewable generation in the proposed BSER through building block 3 will increase the need for flexible generation sources to balance renewable sources; therefore, eliminating NGCC units as flexible units by requir ing their conversion to use as base load sources should be analyzed further. Commenter s stated that NERC, whose data EPA used in its technical feasibility analysis for this block, issued comments on the proposed guidelines warning that the timing and strin gency proposed in this block might cause reliability issues. Commenter s recommended that the EPA analyze the proposed BSER for all relevant interactions between the building blocks and adjust the proposal where necessary to ensure the entirety of BSER is t echnically feasible and can be achieved at a reasonable cost without negative reliability impacts.

Commenter s stated the EPA must consider the need for added load

- following capacity due to the installation of additional renewable energy under building blo ck 3.

Analyze local needs

Commenter s expressed concern that, although the EPA states that it is not concerned with infrastructure adequacy on the whole, the Agency failed to analyze whether local changes in the generation mix will require pipeline installa tion or capacity expansion. Commenter s 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 s tated r egional infrastructure limitations will complicate and can delay increased reliance on natural gas. Commenters stated p lanning, permitting, contracting, financing, and building this infrastructure if needed will delay full implementation of the CPP.

Commenter s stated that, because existing NGCC facilities 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 electri city can reach consumers. Commenter s stated the EPA has not accounted for these challenges in making its blanket assumption in building block two.

Analyze operational constraints305 Commenter s stated that uncertainty exists regarding the EPA's proposal to ope rate these NGCC units as a base load resource and how loss of this flexibility could affect other aspects of system operations. Commenter s stated that a significant impact on pipeline infrastructure could occur if the proposed Clean Power Plan results in t he increased need for simple cycle combustion turbines to support flexible operations that can no longer be supported by NGCCs. Commenter s stated that, if simple cycle combustion turbines are relied on more significantly because of the EPA's proposal, then additional pipeline infrastructure may be necessary, especially if the need grows in the winter and there is a need for increased firm pipeline capacity.

Commenter s stated many operational constraints should be more fully considered by EPA, including system reliability requirements, natural gas utilization for peak load, planned and unplanned pipeline outages, market drivers, and transmission constraints, all of whic h have the potential to make the targeted increased utilization of natural gas plants less likely in the near
term.

Commenter s the EPA has not provided a full assessment that considers the following factors and must do so prior to finalizing the rule: (1) the EPA must consider that, since operating NGCC units at a high capacity factor leaves less open capacity that can be used to react quickly to demand swings and peak loads and other reliable generation, such as coal

- fired EGUs, cannot ramp up as quickly as NGCC units, load following must 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 that must be allotted for; it is the maximum

ca pacity that may be needed in any one hour to maintain electric reliability.

Commenter s stated that the significant resource adequacy and reliability risks arising from such a wholesale change in dispatching of the generation fleet under the proposed rule are oversimplified by the EPA and did not receive sufficient analysis by the EPA. Commenter s also stated that the EPA did not sufficiently analyze the impact of changing the operation of "load following" natural gas units to running them in base

- load opera tion, 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, commenter s supported several comments by EPRI on the rule: (1) cautioned abou t increasing natural gas plants to a 70% capacity factor because there is little long term experience with operating at that level; (2) questioned assumptions that natural gas production could ramp up to meet the large increase in supplies needed to operat e in this fashion, the market price of natural gas, availability of pipeline infrastructure, and firm pipeline capacity; (3) questioned the relationship of gas capacity factors to gas prices: "Reinforcing the dependency of gas price to capacity factor; nat ural 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 consistently been inaccurate; establishing a mitigation goal based on an assumption of per sistent 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 extreme cold weather in January 2014 and expressed concern about elect ric system reliability in future instances.

Commenter s stated that there are a number of challenges to the natural gas industry in meeting the electric gas loads. Commenter s stated that Building Block 2 poses major regional challenges306 that the Proposed Rul e fails to recognize and address. Commenter s described several of these issues:

• High pressure requirements, where consistent fuel pressure is necessary for the generator to meet operational and environmental requirements. Newer, larger, combustion turbine/combined cycle units are less tolerant of variations in pressure than older unit s. While the electric utilities continue to increase their pressure requirements to improve their overall fuel efficiency, the increased requirements can impair overall pipeline flexibility and response capability.

• The variability of electric gas loads. M ore problematic for the gas industry than seasonal electric gas load variation are daily and weekly variations (i.e., non

ratable

- take issues). Daily variation is particularly difficult for pipelines to accommodate because they were initially designed for steady hourly load profiles (i.e., 1/24 of the daily consumption requirement each hour). Pipelines are thus unlikely to be able to provide the fuel necessary to meet daily peak electricity demand. Peak demand will thus have to be met by coal

- fired or nucle ar

- powered units. If coal

- fired units are prevented from being dispatched or are required to close under the Proposed Rule, then implementing the Rule presents significant risks of power failure at peak times.

• System flexibility to accommodate intermitten t renewables.

• 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 utility loads mostly occur at a sing le 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 cooperative rural service areas. Even where pipelines are available, the availability of firm gas supplies at a reasonable price is an ongoing uncert ainty.

Infrastructure needs analysis

Commenter s questioned whether it is feasible for states 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 other infrastructure is adequate or can be built to enable plants to operate at 70 percent capacity factors.

Commenter s stated that the EPA also must provide a legitimate justification for its assumption that supplemental electricity tra nsmission and gas pipeline construction "can reasonably be expected" because the Proposed Rule relies on new transmission and pipeline construction to satisfy Building Block 2's infrastructure requirements, 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 the3 07 Proposed Rule (IPM Documentation at 2

- 10 to 2

- 11, 10

- 37 to 10

- 38). Commenter s i ndicated that such an analysis should consider the time required for the transmission and pipeline permitting and construction necessary for compliance

- electricity 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. Commenter s added that the specific permits and rights

- of

- way needed for transmission design and construction 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 acros s multiple states in a region or if interregional planning is required.

Commenter s stated the EPA has not fully analyzed and supported the feasibility of the level of

re

- dispatch required. Commenter s stated that addressing reliability problems either thro ugh modification of the bulk transmission system or construction of new generating units requires that transmission studies be performed. Commenter s stated these studies

- and any identified upgrades

- optimistically take approximately two years to complet e. Commenter s 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 Clean Power Plan compliance

.

Commenter s expressed conc ern 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 conservative", but rather overly ambitious. Commenter s stated the EPA is picking select years (2005

- 2010) to justify its conclusion. Commenter s referred to their own analysis which applied several linear regression analyses on the same dataset available from the EIA and also expanded upon the EPA's analysis, utilizing the full dataset (1994

- 2013). Commenter s stated that, from 2005 to 2010, the period selected by U.S. EPA, this growth rate more than doubled compared to the period 1994

- 2007. Commenter s concluded the 21% growth in this period is not fully represe ntative and is certainly not conservative. Commenter s stated that, most concerning, is the apparent decline in capacity observed for years 2011 to 2013, which calls into question whether the pipeline capacity can sustain the growth projected by the EPA. Co mmenter s urged the EPA to consider the full range of available pipeline capacity data, examine more closely the apparent slowdown in growth observed in recent years, and derive a more representative estimate of growth potential of the natural gas pipeline system. Commenter s stated the EPA does not have the expertise to determine fuel market impacts or the ability to determine if individual states need to, or can, expand infrastructure. Commenter s stated the EPA is treading into a domain, control of the elec tricity generating market, in which it has neither expertise nor authority to regulate in this

manner.

Commenter s stated that, in its Proposed Rule, the EPA failed to account for increases in NGCC consumption just from existing generation sources. Commente r s stated this additional gas transportation capacity needs to be established before NGCC can meet its current demands and future proposed 70% capacity target. Commenter s stated that, currently, the United State and Canada are already in need of additional natural gas pipelines to provide adequate transportation308 for existing generation sources. Commenter s stated INGAA estimated that the United States and Canada already need 28,900

- 61,600 miles of additional natural gas pipelines through 2030

-- this is befo re considering any necessary increase in transportation needs from the Proposed Rule.

Commenter s stated additional evaluation is needed to ensure this increased demand can be accommodated. Commenter s stated, given the length of time it takes for new permit ting and construction, it appears unlikely that sufficient new 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.

Co mmenter s referenced the NODA (79 FR 64543) and stated EPA should have corrected its analysis for infrastructure improvement before developing its ambitious and unrealistic block 2 goals. Commenter s stated that, to perform a comprehensive study of the natur al gas pipeline system to determine the feasibility of supporting increased natural gas consumption would take at least six months to a year in duration and should have been done by the EPA to support the proposal. Commenter s stated the comment period of 1 20 days on the original proposal was not sufficient time to perform a comprehensive study nor was the remaining 30 days sufficient to provide the additional information requested in the NODA (79 FR 64548).

Commenter s stated that assumptions of high dispatc h 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 that have primacy regulating reliability and system stability) sufficiently ev aluates the impact on existing infrastructure from proposed Building Block #2. Commenter s stated the assumption that high NGCC capacity factors are possible on an annual basis is problematic from a reliability and system stability perspective.

Commenter s s tated that the EPA failed to fully evaluate existing natural gas supply and electric transmission constraints, contractual arrangements, or the timing and feasibility of necessary gas supply or transmission grid infrastructure improvements or expansion, ea ch of which may limit the feasibility, reliability, and sustainability of units collectively operating at such high capacity factors. Commenter s added that timing considerations are also of significant concern with regards the time to plan, design, approve , and construct any necessary pipeline and transmission infrastructure. Commenter s asserted that evaluating these types of issues in more detail would offer a more credible assessment of potential natural gas supply concerns than the qualitative conclusion s that EPA made in the proposed rule. Commenter s stated that the EPA failed to identify or fully evaluate potential constraints within or impacts to the electric transmission system that may limit the feasibility, reliability and sustainability of NGCC uni ts collectively operating at higher capacity factors, instead providing minimal qualitative justification. Commenter s noted that the EPA references EIA and EEI 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 units. Commenter s stated that the EPA should thoroughly review the current state of the existing natural gas supply network and related contractual arrangements to determin e 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, most commonly shown through the execution of a sufficient level of long

- term service contracts, before approving either expansions of existing infrastructure or development of new infrastr ucture. 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 accommodate the needs of firm shippers, many pipelines are fully subscrib ed. Competition determines 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
reg ulatory and legislative positions of importance to the pipeline industry in North America, has stated, "the competitive model has worked well in the past and will continue to work well into the future." This competitive model may not, in fact, result in th e most expedient, economic and holistic national expansion of the natural gas pipeline infrastructure. The availability of existing infrastructure and the construction of new infrastructure is locational. Economic access to sufficient, reliable delivery ca pacity will be location

- specific. Each NGCC that has already been built may have enough pipeline infrastructure in place to meet its needs if it has made a Firm Transportation capacity commitment for its full requirements. If it has not, then additional pi peline infrastructure may be needed to support a 70% capacity factor. The siting of new gas

fired electric generation will need to balance the cost and timing of both natural gas pipeline and electric transmission system expansion. Incremental costs for Fi rm Transportation and balancing services unique to electric generation loads may not result in the economic dispatch of NGCC's up to 70% capacity factor. However, if the units are dispatched at a 70% or greater capacity factor, the reservation charges asso ciated with Firm Transportation Service (FTS) could be more efficiently utilized. Currently, the RTO model does not allow the cost of FTS to be included in the bid/offer. Consequently, it is estimated that less than 50% of the nation's gas

- fired electric generation is served by FTS as the electric generators have no ability to recover this cost from the RTO. The EPA's proposed timeline may not be sufficient to increase existing NGCC plant capacity factors to as much as 70%. If new infrastructure is necessa ry, it could take up to three years from Service Agreement execution until initial natural gas deliveries. Regulatory and environmental approvals, engineering design, easement acquisition and construction have discrete timeframes that allow only minimal fl exibility by location. Furthermore, electric generating utilities will not be able to make the commitment 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 Public Convenience and Necessity approval from the governing state public service commission before it will be in a position to subscribe for Firm Transportation. Increased demand for pipeline infrastructure across the countr y to comply with the final requirements could increase competition for construction labor and materials. Significant expansion is already occurring throughout the northeast and the demand for limited resources is being stretched. Additional pressure on the se resources could increase costs and delay completion of projects by the required to support compliance with the final rule.

Commenter s stated the EPA has not adequately demonstrated that the natural gas pipeline and electricity transmission networks can support aggregate operation of the NGCC fleet at up to a 70% capacity factor on average, either as they currently exist or with modifica tions that can be reasonably expected in the time frame for compliance with this rule. Commenter s stated NERC must consider reliability but complete reliance on a single baseloaded fuel is not practical. Commenter s stated that oil backup would be necessary at a minimum. Commenter s stated that310 oil firing is higher CO2 and higher wear and tear on NGCC units, meaning less availability. Commenter s 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.

Commenter s stated the EPA failed to take into account the lack of necessary infrastructure that must be in place in order to have an adequate natural gas supply and fails to account for the lack of adequate storage. Commenter s stated that, if a 70% capacity factor is required to meet building block 2, it will be necessary for a natural gas operator to be able to have storage to provide the flexibility for necessary operations. Commenter s stated the EPA has not provided evidence that extended periods of high capacity factor operation of NGCC generation can occur under periods of peak natural gas demand in the winter. Commenter s stated that the EPA relies on data during peak hour s when constraints on pipelines or electricity transmission networks are most likely. Commenter s stated that, in Iowa, however, peak electricity demand typically occurs in the summer when there is a large air

- conditioning load, but the peak natural gas con sumption occurs in the winter when there is a large building heating load. Commenter s stated Iowa will prove a good test case for the building of a natural gas pipeline as the necessary franchise requirements are negotiated through the IUB during the next few months. Commenter s stated that, during the 2014 legislative session, much discussion 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 sess ion in regard to the proposed crude oil pipeline. Commenter s stated that potential legislation limiting or impeding the process could prevent or substantially hamper the building of necessary natural gas pipeline infrastructure.

Natural gas demand forecas t

Commenter s did not agree with the EPA's estimate that significant growth in natural gas demand (1.2 trillion cubic feet, a 14% increase) can be expected prior to 2020. Commenter s stated that, if finalized, the proposed rule would increase natural gas dem and by approximately 22% by year 2020, with occasional short

- term spikes higher than this amount. Commenter s referred to a report prepared for Dow by Charles River Associates which predicts that the increase in natural gas demand for the electric utility s ector will be an additional 1.8 trillion cubic feet by 2020 (a 22% increase), and an additional 3.8 trillion cubic feet by 2030. Commenter s 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 the next decade and stated the EPA has underestimated this increase in the industrial sector.

Plant level analysis

Commenter s stated that the EPA's analysis of the electricity and gas infrastructure required to support massively increased NGCC generation must be robust. Commenter s asserted that a robust analysis would consider plant

- level infrastructure constraints, justify assu med infrastructure improvements and analyze gas supply and storage requirements. Commenter s stated that EPA's re

- dispatch analysis should consider plant

- level electricity transmission and gas pipeline constraints. Commenter s 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 infrastructure exists by pointing to nationally aggregated miles of transmission and pipeline from prior and planned projects without regard to the projec ts' location or purpose, and that the Agency cites to 21 percent average regional pipeline capacity growth from 2005 to 2010 as evidence that pipeline capacity will not constrain Building Block 2 re

- dispatch. Commenter s asserted that these national and reg ional analyses do not consider plant

- level infrastructure constraints and that the EPA's assertions suffer from substantial analytical deficiencies.

Commenter s stated that the EPA's assertions assume future growth based on past actions, but the EPA has pr ovided no support for such a projection nor does EPA explain why it believes the planned infrastructure investments it cites will proceed as scheduled when studies have questioned their completion in light of siting and permitting issues. Commenter s furthe r stated that the EPA does not explain how the 21 percent regional average it cites is representative of the capacity increase possible for individual regions. According to the commenter s , the Proposed Rule acknowledges the importance of adequate regional capacity, but of the four regions considered here, three had increases of less than 10 percent and the remaining region had an increase of over 60 percent (citing GHG Abatement Measures TSD at 3

- 17 to 3

- 19). Commenter s asserted that the EPA should explain how a 21 percent increase is representative for all 4 regions.

Commenter s stated that the EPA's failure to consider plant

- level infrastructure constraints led the Agency to overestimate available NGCC capacity. As an example, c ommenter s offered that the Pr oposed Rule determined Arkansas' available NGCC capacity 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. Commenter s added that the EPA s imilarly presumes re

dispatch can occur in the New England, Arizona, and Nevada while according to NERC "current and planned pipeline infrastructures in [these areas] are inadequate for handling increased natural gas demand due to the CPP". Commenter s conc luded that had EPA considered plant

- level infrastructure constraints concurrently with its determination of NGCC capacity and the appropriate NGCC re

- dispatch capacity factor, the assumed capacity from a number of plants would necessarily have been decreas ed.

Commenter s stated that the EPA should analyze plant

- level infrastructure constraints during peak periods. Noting that the EPA cites to a 60 percent average national capacity factor during peak periods (15 to 20 percent above the average annual capacity factor) as demonstrating that adequate infrastructure exists to support a 70 percent re

- dispatch capacity factor, Commenter s asserted that the EPA provides no explanation for how 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 constraint analysis. Commenter s added that the EPA's argument that plant

- level infrastructure constraints at peak times can be overcome through emis sions 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 season because doing so would make compliance impossible with averaging.

Regional analysis312 Commenter s stated the EPA's IPM analysis does not take into account region

- specific technical issues. Commenter s stated that, in particular, given the remote location of Arizona' s existing coal units, it is anticipated that shutdown of these units may result in issues surrounding voltage and system stability. Commenter s stated that, in the absence of a detailed transmission analysis, given Arizona's demonstrated lack of flexibilit y, EPA would be unable to assess what units are necessary for the reliability of the electric grid.

Commenter s stated the EPA failed to recognize and analyze unique circumstances the natural gas supply infrastructure. Commenter s stated that, although the i nfrastructure 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. Commenter s stated the EPA failed to consider the differences in the gas supply infrastruc ture across the county and noted that the natural gas infrastructure is vastly different in the West compared to the eastern 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 throughout the U.S.

Commenter s stated the EPA must perform additional evaluation, in light of several factors and in context of the generation system operating as a whole, and make the needed adjustments to the proposal prior to finalizing its rule. Commenter s stated the EPA has not de monstrated that operating all combined cycle generation at 70% capacity factor, and leaving other fuel types to respond to intermittent and peak demand, will not severely and adversely affect electric reliability or reserve capacity needs. Commenter s state d the EPA must also account for the loss of hydroelectric generation during prolonged droughts or due to the elimination of dams for ecological reasons.

Rerun IPM

Commenter s stated the EPA must model the proposed rule in its entirety with NGCCs operating at a 70% capacity factor. In fact, commenters stated the IPM runs conducted by EPA only indicated 50% utilization of NGCC capacity (including new units). In performing this a nalysis, commenters stated EPA assumed that electricity could flow unconstrained within the major generation regions. Therefore, commenters added, EPA did not conduct modeling that adequately assesses electric reliability impacts.

Storage capacity analysis

Commenter s stated that the EPA also should analyze whether gas storage capacity can support the level of re

- dispatch that Building Block 2 requires because gas storage plays an important role in balancing pipeline flows, serving as a redundancy to enhance reliability and offsetting price volatility. Commenter s alleged that the EPA has not analyzed the consequences of re

dispatch on storage capacity. According to the commenter s , 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). Commenter s concluded that EPA cannot therefore rely on the IPM to support its re

- dispatch feasibility analysis.

Commenter s recommended that, in the final rule, the EPA analysis ful ly consider the availability of storage and associated interstate delivery capacity and include additional stakeholder313 perspectives and concerns related to operation of the bulk power system with increased reliance on natural gas. Commenter s stated, MISO h as begun studying 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. Commenter s also noted that the ability of the nation's natural gas infrastr ucture (pipeline, storage, markets) to deliver dramatically increased amounts of natural gas where and when it is needed by electric generators is also an issue of serious concern for electric regulators including the FERC and the NERC.

Commenter s stated t hat, while fuel can be and routinely is stockpiled at coal plants, natural gas units are dependent on pipelines which are subject to disruptions through such foreseeable circumstances as extreme cold. Commenter s stated this vulnerability makes the undemons trated likelihood that EPA's assumptions are correct even more parlous.

Comment 19: Commenters suggested state

- by

- state analyses are needed 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 projects exhibit a wide range of cost

. Additional analyses may be considered by implementing a gencies. 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 emissio n 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, ad ditional 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 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 fin al 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 Analysis of the final CPP

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

State

- by

- state analyses

Commenter s suggested the EPA should analyze what individual pipeline systems are prepared to support in order for each state to meet a 70% utilization goal. Commenter s suggested the EPA

s hould account for state

- specific electric system operation and infrastructure constraints that limit the feasibility of relying on Building Block 2 as a major compliance strategy.

Commenter s cautioned the EPA regarding the limits of relying on nationwide s ummary statistics and past performance to draw conclusions about the ability to support the increased utilization of NGCCs with underutilized pipeline capacity. Commenter s stated that a more intensive314 examination of regional natural gas markets and anticip ated changes in pipeline flows over the course of implementation of the Clean Power Plan would be necessary to analyze the amount of off

- peak pipeline capacity that actually would be available to support the increased utilization of NGCCs. Commenter s state d this also should include an examination of pipeline connections with individual generators, because generators might be affected by localized capacity constraints and utilization patterns even if capacity was available on the broader regional level. Comm enter s stated the Energy Information Administration regularly examines changes in inter

regional pipeline capacity (i.e., the ability to transport natural gas between regions), although this does not include an examination of the availability of capacity w ithin a region to serve a particular pipeline delivery point.

Commenter s stated the EPA should develop building block 2 based on what has already been achieved by the NGCCs in each state, rather than what has been achieved at the regional level. Commenter s stated the EPA should adopt a bottom

- up approach, letting individual states implement building block 2 using unit

- specific information from within their respective states. Commenter s stated this would allow the building block to accurately reflect both w hat a state has accomplished to date and what it can actually achieve in the future. Commenter s stated this approach also recognizes what EPA has already acknowledged in its June 2014 proposal: that each state is starting in a different place and therefore must have a unique reduction goal. Commenter s stated a state

- specific, bottom

- up approach would recognize states that took early action, like Wisconsin, have less they can reasonably achieve when compared to those that have done little. Commenter s stated the EPA must prove that 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

Commenter s expressed concern that, while Arkansas receives almost zero credit for nuclear and hydroelectric power plants that produce no greenhouse gas e missions, the proposal assumes Arkansas 's natural gas

- fired power plants can operate at 70 percent capacity. Commenter s stated this significant increase in electricity generation from natural gas

- fired power plants is unprecedented in Arkansas, and noted s erious reservations whether it can be accomplished without expensive upgrades to pipeline and electricity transmission infrastructure.

Commenter s stated the EPA should re

- formulate its analysis of natural gas availability to account for potential supply co nstraints in Indiana, and EPA should include in its analysis a robust model of the effect a nationwide increase in the demand for natural gas will have on pipeline capacity in the short

- term. Commenter s stated the EPA assumes that necessary gas pipeline in frastructure 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 existing NGCC units. Commenter s stated the EPA made allowances in the computation of state go als for shortfalls in fossil fuel supplies, but only for states where the sum of coal, oil, and natural gas resources fell short of the natural gas required to sustain a 70 percent capacity factor at existing NGCC plants. Commenter s stated that coal, oil, and natural gas are dis

- analogous for the purpose of estimating resource availability, insofar as a state may possess large supplies of one and very limited supplies of another.315 Commenter s noted that Indiana produced 826.8 trillion Btus of coal in 2012, bu t only 8.9 trillion Btus of natural gas that year.

Commenter s questioned the EPA's estimate of the capital costs of constructing new pipeline laterals of $1 million per mile of pipeline built (79 FR 34875). Commenter s stated that the Columbia Pipeline Gro up just announced plans for the construction of a 160 mile natural gas pipeline to transport natural gas from Ohio and West Virginia to North Carolina, at a cost of $10.9 million per mile. Commenter s also referred to Atlantic Coast Pipeline, LLC, which has proposed a 550

- mile pipeline that will run from West Virginia through Virginia, then south through North Carolina at an expected cost of $9.1 million per mile.

Commenter s stated the magnitude of increased utilization of NGCC in 2020 is based on 2012
gener ation, which is in turn based on 2012 demand; however, the actual amount of NGCC capacity available in 2020 will depend on 2020 demand and EPA's current approach does not account for any load changes that will occur between 2012 and 2020. Commenter s stated NV Energy is projecting more than a 10% increase in load between 2012 and 2020 on its system. Commenter s stated EPA's failure to take this growth into account underestimates the demand conditions that the utility will experience in 2020.

Commenter s stated that, while the EPA projects the NGCC units to operate at levels very similar to those observed in 2012 under both the regional and state compliance options that is unlikely, given the historically low price of natural gas in 2012. Commenter s stated that, while IPM projects 6 of Ohio's 26 existing NGCC units operating at above 70% capacity and all 3 units at the Dresden Energy Facility are projected at 86% capacity in 2025, whether these units can receive the natural gas to operate at this level is not a f actor that is considered by the IPM model.

Commenter s 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. Commenter s stated that more evaluation of actual resource capacity and resource adequacy in the Western Interconnection is needed to understand what effects the proposed rule will have on natural ga s supply and delivery.

Commenter s recommended that EPA allow a reasonable time period for entities such as WECC and NERC to ascertain how the proposal impacts resource adequacy and reliability in California and other western states to determine if the assu mptions in Building Block 2 should be adjusted. Commenter s noted that, while the coal

- fired generating 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 E GUs in Nevada or, in part, as replacement energy for LADWP's share of Navajo Generating Station, which is located in Arizona. Commenter s noted the WECC has begun a phased study process that will continue throughout 2015 to provide an analysis of potential impacts of EPA's proposed Clean Power Plan to the Western electric generation and transmission industry. Commenter s stated that preliminary WECC results indicate that a state's decisions made regarding Clean Power Plan compliance can "drastically impact gr id operations, system resiliency, and potentially, compliance opportunities for a neighboring state" (EPA Clean Power Plan Phase 1

- Preliminary Technical Report, WECC Staff, September 19,316 2014). Commenter s stated NERC has begun a similar phased study pro cess and came to a similar conclusion that more studies would be needed to understand the full ramifications of the proposal on electric reliability. Commenter s urged EPA to work with NERC, WECC, states and regional transmission organizations to adopt a mo re realistic view of the potential for re

- dispatch that considers stranded costs and the reliability of 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 und ue stranded costs on states' electric ratepayers. Commenter s stated this review would determine whether adjustments to a state's goal are appropriate.

Commenter s requested the EPA examine the impacts of these transmission systems constraints and address how they impact the prospect of achieving 70% utilization within the time required. Commenter s stated that, with respect to the transmission systems that deliver t he electricity from the EGUs, the RTOs have operational control over all federal

- jurisdictional transmission facilities. Commenter s stated that, if there are constraints on the transmission system controlled by PJM that would be exacerbated if AMP's AFEC N GCC were dispatched, PJM will not dispatch or will curtail the output of AFEC. Commenter s stated that, whether EGUs run may not be limited to price signals, but rather, physical constraints on the transmission system and, of course, natural gas delivery co nstraints that are beyond either the EGU or the state's control. Commenter s stated that, given the myriad physical and market constraints that apply to EGUs, the 70% percent utilization rate for natural gas plants assumed in Building Block 2 is unrealistic within the timeframes envisioned by the rule proposal.

Commenter s stated that individual NGCC units may not be able to achieve higher utilization rates due to the particular configuration of the unit. Commenter s explained, for example, that South Carolin a's Columbia Energy Center facility, which 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 half of the firm gas requir ed to run at a 70% capacity factor. Commenter s 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 obtain enough gas to increase their capaci ty factor significantly, they would not replace generation from any of South Carolina's coal units to the levels assumed by EPA under building block two.

Commenter s stated it is not clear whether or not the infrastructure will be in place for South Caroli na to increase the use of natural gas to meet the entire emission reduction goal. Commenter s stated that it appears the EPA measured natural gas availability by only factoring in natural gas units available at the time of the baseline.

Commenter s stated th at, for South Dakota, the assumptions that existing NGCC units can increase generation to achieve a 70% capacity factor 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. Commenter s stated the EPA did not analyze several critical unit, state and interstate specific information including but not limited to: grid stability and reliability, NERC critical infrastructure protection, long term power supply contrac ts, 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 a vailability, natural gas supply contracts, dependable unit capacity, and units dispatched by different RTOs. Commenter s recommended the EPA re

-317 analyze Building Block 2 by involving plant owners, RTOs, Balancing Authorities, FERC, NERC, WECC, states and oth er stakeholders to determine the feasibility and limitations of Building Block 2 for each state including consideration of the interstate relationships between generation and loads. Commenter s stated the basis of EPA's analysis regarding the feasibility of implementing Building Block 2 is not detailed, accurate or reasonable.

Commenter s suggested that additional analysis is needed. Commenter s stated that although NGCC units are designed to be dispatchable and may be able to operate as priority base load
gen eration, these units are most often used to serve peak and intermediate load, due to their ability to ramp up and down quickly to meet dynamic demand changes over time. Commenter s described the two TVA NGCC facilities located in Tennessee, and noted that i n 2012 the two operated at an average of 47 percent capacity according to the EPA's data. Commenter s 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 funda mental shift to base load generation for these units. According to the commenter s , it is unclear whether, and to what extent, this is feasible. Commenter s cited the TVA's comments as stating that most of its NGCC facilities appear capable of running at a 7 0 percent capacity factor with sufficient maintenance; however, the existing affected coal

- fired EGUs may not be able to provide the flexible operational capabilities that NGCC units are currently providing. Commenter s stated that in other words, while the NGCC units may, theoretically, be able to do the job of coal units, TVA, itself, is uncertain as to whether the coal units can do the job of the NGCC units and that is what EPA's proposed BSER requires. Commenter s asserted that fundamentally shifting the way TVA operates and dispatches NGCC and coal affected units could result in uneconomic dispatch and higher cost for TVA ratepayers.

Commenter s stated that, prior to finalizing the rule, FERC and EPA must work with each of the Regional Authorities to ensure that the 70% utilization for that state is achievable. Commenter s asserted that, for states in which the emissions rate goal is so strongly t ied to NGCC unit dispatching, it is critical that FERC ensure that the rule will not have any detrimental effect on grid reliability and electricity transmission prior to rule finalization. Commenter s expressed concern with the following statement made on page 34835 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 CO 2 goal." Commenter s 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. Commenter s 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 emissions rate impr ovements that would account for a significant portion of the required emissions reduction.

Commenter s stated the EPA must adequately account for potential losses of current generation

sources. Commenters stated t his includes the retirement of nuclear gener ation. Currently, commenters stated , significant nuclear generation will be retired in 2030 and 2033 in Wisconsin. Commenter s stated the EPA also must consider that some NGCC capacity has been built to meet specific load profiles and must remain available for 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 the area. Commenter s stated it is important facts and nuances about t he EGU fleet, such as this one, that EPA's proposal fails to recognize and calls into question the thoroughness and basis of EPA's rule.

Commenter s stated the EPA did not adequately assess natural gas pipeline capacity and storage. Commenter s noted that na tural 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 Wisconsin's natural gas consumption by 12. 6%. Commenter s stated the EPA has not shown that the supply and storage infrastructure for natural gas would be available to support such an increase in consumption. Commenter s 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 (Novembe r 2013, MISO Summary Document Phase III Gas Infrastructure Analysis, Midwest Independent System Operator). In its own analysis, EPA projects only a 4 to 8% increase in pipeline capacity serving Wisconsin in the foreseeable future; this is clearly at odds w ith the 12.4% anticipated demand increase. In addition, in assessing pipeline capacity, EPA did not consider that the existing infrastructure supporting simple cycle turbines and new NGCC units will have to be upgraded in order to replace the load and peak ing capacity of the existing NGCC capacity.

• Second, storage capacity for natural gas has remained relatively flat. There are some additions to storage capacity coming online, but these are relatively small in the context of total system capacity and also a re located 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 capacity because the approp riate geology does not exist in the state. EPA does not consider these factors in its proposal.

• Finally, there are fuel availability factors that are not directly related to physical infrastructure, but will be driven by a market for fixed

- load support. EP A must consider that utilities may have to procure long

- term 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; however, there certainly will be a cost i mpact. One Wisconsin utility currently in the planning stages for a new NGCC has relayed that reliable transportation, storage and no

- notice service could cost $12 million per year for a 500 MW plant. In addition, a new or upgraded connection would cost ap proximately $2

- 3 million dollars 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 dis agrees that we inadequately considered system issues in development of the 111(d) final rule. Additional a nalysis 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 emis sion 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, 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 emissio n rate achievement between performance periods. Neither 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 requi rements 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:

Commenter s suggested a longer term analysis is needed, including consideration of sustainability and maintenance concerns. Commenter s recommended the EPA reconsider the level included within proposed BSER from b uilding block 2 after analyzing 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 generation source. Commenter s stated the EPA's conclus ions as to the technical feasibility of increasing NGCC capacity factors to 70 percent consistently over the interim goal period of 2020

- 2029 (79 FR 34862) is not adequately supported by information in the docket, including the EIA and NERC data that EPA u ses in its analysis. Commenter s referenced an October 2014 EPRI 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 percent c apacity 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 suppor t the proposed guidelines.

Commenter s stated the assumption that an NGCC unit can sustain a 65 percent, 70 percent, or 75 percent utilization rate over a decade based on data that otherwise suggests highly variable monthly averages, and without considerati on of maintenance and down

- time for operational constraints, is not reasonable. Commenter s stated it is not supported by the actual demonstrated utilization of the national fleet of NGCC units when market conditions would favor their use more so than other generation resources. Commenter s 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 acro ss the national fleet during that period was much lower than 64.5 percent at 44.8 percent in January 2014 and 41.2 percent the following month.320 Commenter s stated that if, as EPA assumes, the increased utilization of NGCCs needed for the states to achieve t he proposed goals could be accomplished without increasing such units' utilization rates during peak hours, then it is likely that significant compliance can be achieved via increased utilization of existing natural gas infrastructure. Commenter s expressed concern that, while there is less demand for interstate natural gas pipeline capacity during off

- peak months, pipeline operators typically schedule maintenance during these periods in order to minimize the effect on firm transportation customers. Commente r s stated that, consequently, the amount of available pipeline capacity may be reduced because the pipeline operator has temporarily withdrawn facilities from service to perform maintenance. Commenter s 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 available for interruptible shippers may be limited.

Commenter s stated that the shift in natural gas pipeline flows attributable to the shale gas

re volution may create additional underutilized pipeline capacity that could be used to serve gas

fired generators operating at increased capacity factors. Commenter s stated that, in some cases, the abundance of natural gas and the shift in the location of na tural gas relative to consuming markets has resulted in diminished capacity utilization along some pipeline corridors. Commenter s added that, because the flow of natural gas has increased along other pipeline corridors, there will be less underutilized pip eline capacity available along those corridors to support the increased utilization of NGCCs. Commenter s noted that the initiation of liquefied natural gas exports and the demand for natural gas to supply new and re

- opened petrochemical facilities along th e Gulf of Mexico will result in greater year

- round utilization of existing pipeline capacity in that region. Commenter s stated that, since many pipelines were designed to deliver sufficient natural gas to meet the LDCs' peak day winter heating loads, for m uch 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 market for pipeline capacity. Commenter s stated that during off

- peak months it is likely that pipeli ne capacity will be available in the secondary market to deliver the natural gas that will be needed to increase the utilization of NGCCs.

Commenter s stated that it is important to note that under the open access requirements prescribed by the Federal Ene rgy Regulatory Commission (FERC), interstate natural gas pipeline capacity must be available on a not unduly discriminatory basis. Commenter s stated that priority for access to pipeline capacity is dictated by the quality of service that a shipper chooses to subscribe (e.g., firm transportation versus interruptible transportation). Commenter s 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 t ransportation to take priority over another shipper wishing to transport natural gas, to be used for some other purpose, if that other shipper subscribed to higher priority pipeline service.

Comment 21: Commenter s stated the EPA should use modeling to determine how NGCC generation offsets other generation throughout the electric supply system.321 Response 21: The EPA dis agrees 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 rule requires that states develop plans that establish emission standards for affected EGUs. We are providing states with substantial flexibility as to how they str ucture 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. Neither the Building Blocks nor the IPM analyses are prescriptive, and states may consider local circumstances as they develop their plans, including system reliability, fuel dive rsity, 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 GHG Mitigation Measures TSD for the CPP Final Rule supporting the final CPP and the Regul atory Impact Analysis of the final CPP.
The following are summaries of the specific public comments under this comment:

Commenter s stated this modeling will likely show that increasing NGCC generation will offset existing and new renewable energy, indicat ing that the proposed RE requirement is neither practical nor cost

- effective in operating the grid. Commenter s stated that, at a minimum, EPA should assume that additional NGCC generation will offset renewable energy capacity before existing coal

- fired gen eration and solid fuel biomass

- fired generation. Commenter s 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; instead, the EPA must assume that additional NGCC generation will offset a combination of coal

- fired generation, renewable energy, and simple cycle combustion turbine operation. Commenter s stated that, as a part of this modeling, the EPA must establish a floor for operation of existing coal

- fired EGU s that prevents degradation of their heat
rates.

Comment 22: Some commenters raised issues regarding natural gas

- electric coordination.

Response 22: The EPA dis agrees that we have inadequately considered na tural gas

- electric coordination. We have consulted extensively with stakeholders. Additional analysis and consultation may be performed by implementing authorities. 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, 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. Neither the Building Blocks nor the IPM analyses are prescriptive, and states may consider local circumstances as they develop their plans, including system reliability, extrem e weather, fuel322 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:

Scheduling protocols

Commenters stated that inconsistencies in scheduling protocols between the gas and electric industries make it challenging for gas

- fueled generators to purchase gas supplies and schedule pipeline capacity and expressed concern that such processes be in place in time to adequately handle the next weather

- driven electricity surge like the one we saw on January 7, 2014.

Commenters (cited a Marc h 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 regionally coordinated electricity market scheduling timelin es and the nationwide gas scheduling timeline are increasingly likely to impede reliability across the electric grid. Commenters noted that three things make managing fuel procurement and price risks challenging for generators and transmission 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 service is not synchronized with the timeframe during which generators receive confirmat ion of their bids in the day

- ahead electric markets; and (3) the fact that it is not economic for electric generators to pay for firm pipeline capacity. Commenters stated FERC has determined that generators need the flexibility of the gas scheduling system to improve in order to accommodate their need to revise nominations in response to weather events or other operational needs. 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 effects on their systems should gas

- fired generators have trouble acquiring natural gas or experience curtailment of na tural gas supplies, particularly during periods of extreme weather, and that steps must 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 sta te 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 related to natural gas infrastructure and

e lectric

- gas coordination. Commenters stated the EPA failed to consider factors such as age and design of a unit, hourly limitations in existing operating permits, and the ability of existing natural gas infrastructure to serve additional capacity at the NG CC 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 infrastructure and electric transmission systems of dramatically increasing the d ispatch of electricity produced at the NGCC plant, particularly on the short timeframes required in the proposed Guidelines. Commenters stated that, for the most323 part, coal

- fired and NGCC plants are not co

- located in Indiana, thus there is no guarantee tha t adequate transmission currently exists to send the same electric load from an NGCC plant as that being serviced by baseload coal

- fired units. Commenters expressed concern that the EPA assumes that the necessary gas pipeline infrastructure can be added in the short span of 3

- 4 years to support reliable operation of NGCC plants at higher 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 building block 2 in the final rule. Commenters expressed concern about the following issues:

• Availability of sufficient natural gas pipeline capacity to accommodate this increase in utilization and being able to obtain firm commitments from natural gas suppliers, especially during the winter months when many residential and commercial buildings use natural gas for heating purposes. Commenters noted the di spatch order for natural gas pipelines prioritizes residential heating, then industry usage, and electricity generation is typically 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 increasing the utilization of NGCC units to 70% of their capacity could result in uneconomic 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 electricity at these levels.

Commenters stated that the EPA recognizes some of the challenges to increasing NGCC utilization, primarily infrastructure and system considerations, but does not analyze the impact of those challenges or take them into account when determining an achievable level for the nation's NGCC fleet utilization rate or recognize the importance of these constraints. Commenters indicated that solutions to some of these challenges depend on actions taken by other sectors, injecting a level of uncertainty into any discussion about fuel availability and deliverability. Commenters asserted that the EPA should take into account 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 when calculating potential natural gas utilization rates, and that natural gas consumption patterns of other industries should a lso be factored into any determination of "reasonable" or achievable levels of NGCC utilization. Commenters noted that the two industries have different regulatory schemes, different operational requirements and different processes for building infrastruct ure, 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 at the regional level.

Commenters supported a comprehensive and independent analysis of the i mpacts of the proposed rules on the reliability of the nation's electric grid, referencing Supplemental Responsive Comments of Southwest Power Pool, Inc. Exhibit A. Case No. EW

- 2012

- 0065. October 13, 2014. Commenters stated the proposed rules will change t he dispatch of generating units by324 replacing economic generating resources with less economic resources which could affect the reliability of the national electric grid.

Commenters stated that generators that supply their NGCCs using strictly interruptibl e 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 dist ribution companies (LDCs) also offer various levels of transportation services to generators. Commenters indicated that units that source gas from intrastate pipelines or that are located behind LDC city gates could potentially be exposed to supply constra ints due to inadequate pipeline capacity. Commenters asserted that while the EPA assumes those constraints will have plenty of time to be addressed, this assumption may be invalid and from the standpoint of reliably serving the public's need for electricit y is risky. Commenters stated that the size 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 i nteraction between electric 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 re

- dispatch between existing coal

- fired and NGCC units is largely a factor of whether certain system constraints have been addressed, and that making the appropriate infrastructure and system upgrades that 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 noted that TVA is participating in a DOE

funded study of gas supply adequacy being performed by the Eastern Interconnect Planning Collaborative (EIPC) that is expected to identify areas where pipeline capacity needs to be expanded, develop contracting mechanisms to incent those expansions, and improve gas

- electric coordination to eliminate scheduling issues. Commenters stated that the final report is expected to be submitted to DOE in June 2015 and will provide analyses that should be helpful in determining how feasible EPA's assumed 70% capacity factor is.

Commenters stated the EPA, in its final rule, should examine the impacts of improved gas electric coordination practices in imp lementing BB2. Commenters stated this issue relates to a fundamental disconnect between how gas pipelines schedule and nominate supplies for delivery customers and how generators schedule available capacity to the wholesale electric markets. Commenters sta ted this disconnect between the scheduling functions of the two industries has also contributed to supply shortfalls to electric generators during periods of increased system demand. Commenters stated the FERC has an ongoing proceeding to address this issu e and is expected to make some general recommendations for further consideration in the near future. Commenters stated the individual RTO/ISOs have undertaken initiatives to resolve these inter

industry issues. Commenters stated the EPA should consider whe ther 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 issues between the two industries.

Commenters suggested the EPA consult with FERC b efore trying to redefine the entirety of the electric market/dispatch. Commenters stated the electricity market can be volatile, and massive changes in the capacity and distribution of electricity could have major implications on the market. By incorporati ng FERC into the rule development process, Commenters stated the EPA325 will have a better technical understanding of the important subtleties associated with electricity dispatch and appropriate timeframes for changes to occur.

Commenters stated that the EP A Proposal relies heavily 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. Commenters 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 co nstruction 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 disc onnect may prevent facilities committed to provide electric power from securing the gas supplies they need to operate, or require them to pay higher prices for longer time periods. Commenters added that this issue is further complicated by the interdepende nt nature of the natural 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 capabilit y can become a bottleneck. Commenters pointed out this is particularly true in the winter when shorter days and colder temperatures increase demands for heating and lighting; while adequate supplies of natural gas exist, delivering at the rate needed durin g peaks could be constrained. Commenters stated that additional coordination between these two industries is needed, in addition to fuel diversity, which will reduce the interdependence 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 electricity generation markets and pipeline capacity shortages, FERC has led an effort to encourage stakeholders and numerous collaborative bodies to identify regional issues a nd propose possible solutions. Commenters added that a number of RTOs have established task forces on electric and gas coordination, looking at information sharing, operations coordination, and process improvements. Commenters noted that in November 2013, FERC issued an order allowing the voluntary sharing of non

public operational information between interstate gas pipelines and electric transmission providers to promote grid reliability and operational planning. Commenters stated that while FERC was able to take steps quickly to address communications between the two industries, the issues of insufficient gas infrastructure and the nonalignment of gas and electricity markets have proven to be thornier for the Commission to deal with as the U.S. gas boom wh ets 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 extraordinary effort by the North American Energy Standards Board (NAESB) and natural gas and electric i ndustry participants to develop a consensus on standards for coordinating the scheduling processes of the natural gas and electricity markets. Commenters provided extensive detail about the NOPR and the development of consensus standards, including remaini ng areas of disagreement.

Extreme weather

Commenters stated that the maximum annual NGCC capacity can be limited by natural gas curtailments, transmission constraints, and/or air permit requirements, which provide additional compliance hurdles with the pr oposed Rule. Commenters provided detailed information326 regarding natural gas constraints that affected NGCC unit production at the Fulton and Oswald stations over four continuous months during the winter 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 constant 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 plants' 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. Commenters stated the winter of 2013

- 2014 experience yields three primary conclusions which are 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 existing 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%), th e natural gas pipeline infrastructure needs to be upgraded. Commenters urged the EPA to take these factors into account when finalizing the proposed Rule. Commenters stated that, while industry experts may differ about the sufficiency of the existing natur al gas pipeline system, there is no doubt AECC was affected by natural gas delivery issues during the most recent winter and those effects cost AECC and its members' precious time and money.

Commenters stated that transmission constraints affect the abili ty to achieve capacity factor targets, further impeding the ability to comply with the proposed rule. Commenters stated the scope and cost of transmission improvements to eliminate these constraints need to be identified and considered. Commenters noted th at AECC has experienced transmission constraints in the past and specifically pointed out that Entegra's Union Power facility has substantial excess capacity and energy that could be sold and provide substantial economic benefits to Arkansas electric consu mers if transmission access were not severely constrained. Commenters referred to an Entegra petition and stated the scope and cost of transmission improvements that eliminate this constraint

- allowing the Union Power facility and other existing generatio n resources in the Entergy region to reliably and economically transmit power across the Entergy

- SPP seam

- need to be identified and considered [Arkansas Public Service 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 reliabil ity and could even affect safety, if power cannot be delivered during peak utility usage times (such as for heating 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 Rule's power supply regime, qualitative and comprehensive studies are needed to assess the capabilities of the natural gas pipeline system and the vulnerability of the system to attacks with resultant impact s to electricity supply.

Commenters expressed concern regarding the impact of 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 20 13

- 14. Commenters stated that, despite having a firm natural gas transportation contract in place, because of deliverability issues that occurred for 66 days during that winter, AECC would have faced contractual, financial penalties from its natural gas tr ansportation provider for starting up either Oswald or Fulton. Commenters added that, if AECC had started up either Oswald or Fulton in order to serve load demand, it would have been327 unable to vary the hour

- to

- hour gas consumption during the day for either facility because of the deliverability constraints.

Commenters stated that extreme spikes in spot gas and electricity prices, accompanied by widespread unplanned outages of gas

- fired generation facilities, experienced in the eastern United States, and esp ecially in New England, during the polar vortex of January 2014 brought
gas

- electric interdependency to the forefront. Commenters indicated that though they were likely planned before that event, FERC's proposed changes to pipeline nominations and scheduli ng procedures soon followed.

Commenters stated the EPA should not ignore the nature of the current system of interruptible gas contracts that may not support increased dispatch during the winter months. Commenters stated that moving toward a system of non

- interruptible gas contracts to ensure supply at electric generating units during winter months means that these units will be competing with home heating for available gas supplies. Commenters stated 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 requirements of Building Block 2. Commenters stated that these concerns are also mirrored in comments provided by MISO. Commenters stat ed that, if the organizations charged with maintaining reliability and the functionality of the electric system are concerned with natural gas infrastructure and electric

- 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 dispatch, particularly in ISO/RTO markets. Commenter s (cited Moeller House Testimony and) stated 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 Proposed Rule would requir e utilities to put on the system.

Commenters stated the availability of gas

- fired generation depends on the availability of natural gas transportation to the individual unit and, especially during periods of high gas demand, the availability of sufficient high

- capacity gas storage 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 purchasing firm transportation service for gas is often not economically feasible when that service is really only needed those few hours a year when extreme weather events like the Polar Vortex create high demand for both electricity and end

- use natural gas. Commenters (cited a March 20, 2014 FERC Sch eduling Coordination Order and) stated that, when the nationwide gas transportation 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 th eir electricity market commitments and to contribute to reliable system operation. Commenters provided examples of service problems during last winter's Polar Vortex. Commenters (referenced the NERC report Potential Reliability Impacts of EPA's Proposed Cl ean 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 bla ckouts.328 Commenters (cited a September 2014 NERC on the Polar 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 interruptions 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 ga s and must rely on real

- time delivery of the fuel in order to generate electricity; thus, if the natural gas cannot be delivered (for any reason) then the generators cannot generate to meet electricity demand. Commenters provided Figure 3 (titled:

“ Reprodu ction of Figure 13 from NERC Polar Vortex Review" ), and stated the figure shows the natural gas

- fired generators represent 55% of the forced outages, while coal

- fired generators represent 26% of outages) and nuclear generators (3% of outages).

Comment 23 : Commenters said that, this proposed guideline is totally inadequate to address a horizontally integrated electric utility system where the cooperative has no control over the portfolio mix, and limited access to transmission options. Commenters said, it is inadequate to regulate merchant generation plants that have no contact 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 compon ents of and general practices in the Electric Generation and Transmission sector is a major reason the commenters requested that EPA withdraw the rule and make the necessary adjustments before restarting the entire process.

Response 23 : The EPA disagrees. The final rule applies to sources and emissions from those sources, not to the consumption choices of end users. The final rule provides multiple pathways for sources to comply, including shifting between sources 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 Mitigation Measures TSD for the CPP Final Rule supporting the final CPP.

Comment 24: Transmission issues, market issu es, and line losses
Response 2 4 : The EPA dis agrees 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 state s 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 approach es, 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. Neither 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. See329 sections V.A, V.B, V.D, VIII.A, VIII.C and VIII.G of th e 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 the EPA needs to address h ow 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 f aith efforts could be considered market manipulating activities: NGCC owners may have to bid into the MISO market as "must run" or self

- schedule NGCCs in MISO's day

- ahead bidding process and coal

- fired generators may have to adjust the offered price to com ply with other Building Blocks of the Proposed Rule. Commenters stated these combined activities could be interpreted unfavorably by MISO's Independent Market Monitor (IMM). Commenters stated that, for the IMM to perform its market monitoring function, MIS O 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 ensure it was not done in a way that allowed the "complying" generator to ma nipulate 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 environmenta lly 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. Commenters stated that the longer the distance between the NGCC and the market it serves, the higher the "line loss" associated with delivering the electricity to market. Comm enters stated that line loss cuts into the emissions reductions assumed by the EPA. Commenters stated that, while the EPA includes line loss calculations in the Agency's feasibility estimates, the estimates are not region specific and not appropriately
app lied 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 majo r concern, between and within transmission regions. Commenters noted that PJM in particular has experienced 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 unintended 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 b etween its eastern and western markets, there is no guarantee Indiana will be able to economically consume the excess electricity produced by NGCC plants operating at a higher capacity factor.330 Comment 2 5 : C ommenters stated that the proposed rule does not examine whether sufficient natural gas storage exists to support large

- scale fuel switching.

Response 2 5 : The EPA disagrees. 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 EPA does not project large 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 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 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 states may consider local circumstances as they develop their plans, including system reliability, fuel diversity, gas storage capacity, 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 stated the proposed rule does not examine whether sufficient natural gas storage

ex ists to support large

- scale fuel switching. Commenters stated that many states do not have adequate geologic formations to store the natural gas that would be needed for the large scale dispatch of NGCC called for under Block 2. Commenters stated that, acc ording to a 2013 report, "[g]eology limits opportunities to build storage where 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 reservoirs

-- rather than higher deliverability salt

cavern

- based facilities." Commenters stated that while 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 plants 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 s tockpile fuel on site, providing reserve fuel supplies in the event of delivery problems. Commenters stated that, not only will the increased reliance on natural gas require new pipeline infrastructure, or provision of fuel oil backup, but it may require r edundancy in the 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 nation, but during the winter of 2013

- 2014 there

wer e questions of being able to maintain an adequate 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, w hile 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 natural gas storage

-- most parts of the U.S. lack the appropriate geology to store natural gas in the subsurface. Commenters noted that natural gas transmission pipelines cannot store significant quantities of gas; at best, they can store a marginal amount through "linepacking." Commenters stated that th e question of sufficient storage is often331 not considered because many existing natural gas

- fired power plants are located in regions of the U.S. with suitable geology to store sufficient amounts of natural gas for the power and industrial

manufacturing sec tors without any glitches in supply 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 natural gas fields offer excellent loc ations for storage of natural gas, but they are not suitable for natural gas re

- injection on a "multi

- turn" or "rapid

- use" basis needed by the power sector. According to the commenters, utilities encounter weather events that alter how much gas they may ne ed and have to resell it since they do not have sufficient localized storage. Commenters stated that underground natural gas storage will be necessary to allow the electric utility industry to generate more power from natural gas

- fired power plants. "Stora ge 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); manage its imbalances; potentially h old 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 underground gas storage fields, were in operation, but t hese underground storage fields are not equal in that most are not configured to provide rapid withdrawals for power plants, and many are not located close enough to power plants to support the rapid change in linepack needed when a power plant fires or ot herwise accommodates multiple turns often needed to support power plant operations (commenters provided a table showing the location of natural gas storage facilities and their proximity to existing coal

- fired power plants). Commenters provided information on the existing underground storage fields as follows: 90 percent are "reservoir or aquifer storage where gas is generally injected during the summer months and withdrawn during winter to serve seasonal demand (with certain exceptions)" and the other 10 p ercent are high

- 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 "pr oducing area storage" located in the states of Mississippi, Louisiana and Alabama. (Commenters provided a table summarizing the key characteristics of U.S. natural gas storage.) Commenters explained the various ways in which storage can be used.

Commenters stated that NERC reliability standards require electric generators to be able to generate within 10 to 15 minutes of receiving notice to do so (depending upon NERC region), which means that the natural gas to run those generators needs to be relatively cl ose by. Commenters stated that linepack cannot be used to store enough natural gas for major power plants; it can only be used for marginal hedging against unexpected weather events and often will provide up no more than 12 hours of supply, assuming that o nly one or two utilities are doing this on an entire pipeline. Commenters provide a figure showing that storage facilities are not evenly distributed, either geographically or relative to demand around the country. Commenters noted that certain pipelines a nd regional markets do not currently have access to any underground gas storage, including Nevada, Idaho 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 Yo rk, western Pennsylvania and West Virginia; and to the extent that there is a small amount of storage in the Southeast, none of it is in the eastern coastal states. Commenters said the Proposed Rule fails to look at key issues related to natural gas storag e. Commenters indicated that the EPA needs to examine these issues 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. Commen ters 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 inability 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 emission goals and/or an extension of the final compliance date.

Comment 2 6 : Commenter s 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.

Re sponse 2 6 : The EPA agrees that many studies demonstrate the benefits of energy storage.

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

Commenters stated that energy storage can specifically augment the output of natural ga s turbines through thermal energy technology. Commenters 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 turbin e output increased from 86% to 104% of their rated capacity. Commenters stated that energy storage can also substitute for spinning reserves entirely, thus reducing the need for additional peaker plants and preventing increased CO2 emissions. Commenters st ated that energy 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 hours, all of which increase the efficiency of the enti re system. Commenters stated these values are provided wherever a storage system is installed on the grid, whether at the transmission or distribution level.

Commenters provided Figure 3 (titled: " Energy Storage for Peak Shaving ")

, which shows how savings at low demands can be used at high demand

. Commenters referred to a paper which asserts that most 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 utilization of storage can be much higher compared to CTs [combustion turbines] interconnected at transmission voltage and operated as a central station resource." Commenters stated t he paper makes the argument that flattening system load with energy storage synergistically reduces the need for all major categories of utility asset investment, including generation, transmission, and distri bution. 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 replacement for additional peak capacity, recognizing the ability of storage to prov ide peaking services comparable to natural gas. Commenters stated that, in another case, Southern California Edison awarded energy storage over 260 MW of capacity in their Load Capacity Requirements Request for Offer. Commenters stated that this decision

-- that only required 50 megawatts of storage in the LA Basin but ended up in the333 purchase of 260 megawatts of energy storage

-- was further affirmation that not only can energy storage provide these services, but can do so cost

- effectively in a competitive pro curement process.

Comment 2 7 : Commenters expressed concern regarding the adequacy of pipeline infrastructure

. Response 2 7 : The EPA dis agrees that gas market issues prevent achievement of the goals. Additional studies may be considered by implementing author it ies

. In response to additional analysis and many comments, we have modified the proposal and RIA ; the performance period has been postponed . 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

ex ample, 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. Neither th e 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, VI II.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:

More infrastructure needed
Commenters stated that, given there currently are infrastructure and supply constraints in the natural gas market, more pipeline investment is required to satisfy the 70 percent requirement. Commenters stated that 2012 natural gas pri ces 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 even close to 70 percent dispatch. Commenters used 2014 winter in the polar vortex to see how the stock market handles relying on only one fuel

source.
Commenters expressed concern regarding the adequacy of pipeline infra structure 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 "cr itical 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 a dequacy of natural gas pipeline capacity to support increased operation of existing NGCCs, EPA conflates natural gas retail deliveries overall and delivery to power plants. Commenters stated that gas 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 require twice as much gas on peak a s compared to off peak hours. Commenters concluded the EPA overestimates the adequacy of natural gas pipeline capacity to support increased operation of existing NGCC.

Commenters stated that an enormous amount of natural gas pipeline and storage infrastruc ture will be needed to enable fuel switching from coal to 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 in the last 4 y ears were made to move the upstream production of natural gas to gas processing centers or oil to refineries; very little pipeline capacity has been built to address electric 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 infrast ructure, nor does it look at potential impediments to the siting and permitting of natural gas pipelines. Commenters noted that FERC must review and approve all projects to construct new interstate pipelines or expand existing ones before 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). Commenters 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 approval process, which slow down the approval process and in some ca ses prevent the project from going forward or result in increased construction costs that are eventually borne by natural gas end users. Commenters stated that contentious permitting issues can lead to avoidance of certain areas of the country for future
p ermitting, "constraining the ability of supply to reach markets."

Commenters stated that market

- related issues can also present impediments to new gas pipeline development. According to the commenters, RTO

- operated capacity markets in the eastern part of t he 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 generat es over half of its electricity from natural gas and where the lack of sufficient pipeline 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 sufficient pipeline capacity to meet demand by the New England states led to an attempted effort to develop a new business model for obtaining needed natural gas pipeline and transmission infrastructure. Commenters explained this as follows:

"In Decem ber 2013, the Governors of the New England states issued a joint statement expressing their commitment to "continue to work together, in coordination with ISO

NE, and through the New England States Committee on Electricity (NESCOE), to advance a regional e nergy infrastructure initiative that diversifies [its] energy supply portfolio while ensuring that the benefits and costs of transmission and pipeline investments are shared appropriately among the New England States." To further the335 Governors' stated goal s, NESCOE launched the Energy Infrastructure Initiative ("Initiative") with two primary purposes; to increase pipeline capacity in the region and to expand electric transmission to facilitate the delivery of electricity from "low to no

carbon resources.

" NESCOE recognized that the natural gas and electricity markets are not producing needed pipeline construction. Natural gas pipelines require long

- term contracts to provide a steady stream of revenue, and in contrast the natural

- gas

- fired merchant generator s operate in a short

term restructured market with volatile revenue streams. 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 transpo rtation. The absence of generator subscription caused Spectra Energy's Algonquin Incremental Market (AIM) pipeline project to be downsized from the planned 500 mmcf/day to 342 mmcf/day.

"However, the NESCOE Initiative is currently on hold as a result of t he 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 component of the Initiative, the natural gas infrastructure efforts were also stalled."

Time

Commenters also noted concern that regulatory actions might delay the additional pipeline investment.

Commenters stated it is not likely there is sufficient tim e and incentive to build the pipeline that is needed. Commenters noted that pipeline is generally built on the basis of demonstrated firm demand resulting from an open season. Commenters stated that, historically power generators have been hesitant to sign up for long term firm transportation capacity that is required to gain the needed investment in a timely manner, which results in a slower build

- out of gas transmission, such as we see in the Northeast, where incremental pipeline capacity is not growing f ast enough to mitigate periods of very high gas prices. Commenters stated that, as power generators' share of gas consumption in Arizona and surrounding states grows, a similar situation to the Northeast region may develop in the Southwest, in which new pi peline capacity is hindered by hesitation for firm capacity commitments.

Commenters stated the time to develop new pipeline infrastructure is at a minimum four years from the determination of need, although the permitting stage can often significantly ext end the process to five years or much longer. Commenters stated 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 nations 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 expansion s. Commenters stated the NERC's 2014 Initial Reliability Review specifically identifies Arizona as one state whereby the existing pipeline capacity is not adequate to handle incremental gas needs of the state under the CPP, consistent with Pace Global's fi ndings. Commenters stated Pace Global projects power 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 alone. Commenters stated th e natural gas supply situation in combination with literal application of the CPP building blocks appears to place Arizona in a precarious position: given that Arizona is reliant on the supply of natural gas from 3 major pipelines, the prolonged disruption of service 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. Commenters stated the proposed rule would require utilities in the state to shut down or convert all coal facilit ies. Commenters stated that phasing out coal in Arizona is not as easy as simply 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 that, 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 generation to replace the current coal generation. C ommenters added that forcing the state to become that reliant on one source of energy production is a costly and imprudent action that will leave the citizens of Arizona beholden to a resource that has historically been subject to volatility in both cost a nd availability.

Commenters stated that the EPA's assumption that all 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 frequently us e non

- firm pipeline capacity because it is generally available in the summer time 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 fi rm gas pipeline capacity 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 new 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 Phoenix expansion project took close to five years from the initial open season to operation and cost approximately $950 million. Com menters stated that, as a result, it is almost certain that there would not be adequate firm gas pipeline capacity by 2020 to meet the needs under EPA's assumptions. Commenters stated the NERC recently identified the need for natural gas pipeline 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 natural gas demand due to the Proposed Carbon Rule

. Commenters agreed with all of the c oncerns NERC has raised and stated they support the concerns raised by the ACC.

Commenters stated the EPA's assumption that the existing NGCC generation could replace all of the coal generation ignores the electric transmission limitations within Arizona. Commenters indicated the major load pockets (Phoenix and Tucson) are served by t ransmission lines from the coal plants, which tend to be in the northeastern part of the state, and by transmissions lines from337 the Palo Verde hub, which is to the west. Commenters 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 solar plants are located. Commenters stated that reliance will then be primarily upon the electric transmission lines from the west, which

curre ntly are not capable of transporting all of the energy needed from the Palo Verde Hub into the Phoenix and Tucson load pockets.

Commenters stated that Arizona's current NGCC capacity is not sufficient to both redispatch coal generation and meet summer pe ak demand. Commenters stated the Pace Study similarly found that existing NGCC EGUs are inadequate to replace the coal

- fired EGUs (Pace Study section 3.1, at 13). Commenters stated that, if Arizona were to redispatch coal with the existing NGCC capacity, t he State would need to build out significant additional NGCC capacity and infrastructure and renewable resources or make large 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 pipeline system improvements given lead times for such infrastructure projects. Commenters referred to the Pace Study (section 3.6 at 26) and stated that NERC

- CAISO has determined that Arizona's "existing 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 requires a change in the timing of BB2 and revision to the Interim Goal, at the very least. Commenters stated the assumption that this generation switching could occur by 2020 is not feasible for Arizona due to in large part to the
mag nitude of investments in generation, transmission and pipeline infrastructure simultaneously, which require substantial commitments, permitting and construction lead times.

Commenters referenced PACE modeling and stated that natural gas reliability in Ariz ona could be compromised due to the short time available to demonstrate firm demand, secure necessary permits and build the natural gas pipeline expansions that would be needed to accommodate increased demand, as well as the risk of a prolonged disruption to one of the pipelines serving Arizona. Commenters stated demand would exceed existing pipeline capacity as soon as 2022 because existing natural gas capacity is nearly fully 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 several

- hundred

- mile

- long pipelines, as this additional capacity is simply not available. Commenters expressed concern that the EPA has factored re

- disp atching to existing sources as accounting for nearly 30% of the total reductions leading to the state goal, given that Florida already relies significantly on NGCC generation for more than half of the state's total sales. Commenters stated the City has alr eady pushed its own generation, absent an EPA requirement, to natural gas, and improved the heat rate by retrofitting combined cycle operations to an existing unit at the Arvah B. Hopkins Generating Station. Commenters stated that, even with this already

- h eavy reliance on NGCC, EPA presumes that the state of Florida can push 20% more of the state's generation 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 units, including a gas transport limitation that impedes the station output from at least one NGCC unit.

South Carolina

Commenters stated the EPA has designed building block 2 based on a series of assumptions that are inapplicable to South Carolina and Santee Cooper. Commenters stated the Proposed Rule presumes that there is existing firm gas capacity available to operate all NGCC units at 70% capacity. Commenters stated that, while for South Carolina 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 stated 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 may not be available and, thus, interruptible gas contracts are not a reliable option for units to meet anywhere close to 70% utilization. Commenters stated that South Carolina is not a producer of natural gas and, while natural gas

con sumption for electricity generation in South Carolina 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 significantly. Commente rs stated that, in the winter of 2006

- 2007, on the Carolina Gas Transmission 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 interru ptible 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 annua l 70% capacity factor. Commenters stated t his expansion will take significant time for financing, permitting, and construction

- a minimum of three to five years is estimated (NERC Initial Reliability Review at 10) and then only if the expansion experiences minimal delays or opposition. Commenters s tated i t 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 2 8 : Commenter s included a description of NERA's whole

- economy model, NewERA, and findings from their analysis of the extent to which the y anticipate gas deliverability concerns over the peak seasons that may constrain states’ ability to comply with the EPA's proposed CPP targets under Section 111(d) of the Clean Air Act.

Response 2 8 : The EPA disagrees that the modeled results of the proposal would reflect a similar analysis of the 111(d) final rule

. The EPA believes that a model this detailed would likely show results quantitatively different from an analysis of the final CPP, due to signific ant changes from339 proposal. See sections V.D, VI, and VII of the final 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, comme nters provided state

- level disaggregated findings via a qualitative and relative ranking exercise informed by quantitative, model

- based projections of natural gas demand changes under the CPP.

Commenters included the following description of NERA'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 aggregate 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 increases implicit in EPA's analysis. NERA also ran a second scenario relaxing EPA's input assumption around the availability of energy

e fficiency, to help establish a range of uncertainty on projected state

- level gas demand increases. Using these state

- level demand projections, NERA assessed 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 demand. 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 relati ve prices, indicating constraints at natural gas supply hubs; high futures prices, highlighting traders' expectations of future constraints at such hubs; and large natural gas demand increases in each state, adding load to the system. If a state's projecte d baseload electricity generation is reliant on natural gas, we project that even a brief or small shortage could reduce electricity service reliability. 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 electric system planning has not taken into account the correlation of unit outages. Rather, it has treated outages as independent events. Insofar as multiple generators take natural g as from a single pipeline, a forced outage due to unavailability of natural gas on that pipeline would cause multiple generators to face an outage. In practice, unit outages can therefore be correlated. This underscores the potential for reliability concer ns 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 result fr om large increases in natural gas demand. As a result of these considerations, we categorized 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 and/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 n atural gas supply concerns and associated electricity price or reliability risk. The remaining states were not identified by any of the screening criteria that we have used in this assessment, but this does not imply that they are free of any natural gas s upply risk. For example, our analysis has not addressed how increasing natural gas demand on a national scale may affect even states that may have declining reliance on natural gas.340 Commenters stated that in ranking states in terms of 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 gas consumption by 2020; and (2) where the baseload is projected to be very hea vily dependent on natural gas combined cycle generation.

Commenters provided the following description of the 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 purposes, and retiring. Potential new units can also be added to replace retired units, to meet increasing electricity demand, and to meet environm ental rules and regulations. Given constraints 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 thro ugh time on a present value least

- cost basis. 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 s cenario where this is assumed to be cost

- effective 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 addition to re

- dispatch, there are also additions of new natural gas combined cycle generators to meet electricity demand. The combination of re

- dispatch and new natural gas

- fired generating capacity creates increased natural gas consumption in the electric sector in many states. The increased

c onsumption from existing natural gas

- fired generators is straightforward to quantify, since we know the physical location of each existing 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 rather than in specific states within each region. For this analysis, we have allocated natural gas use from projected new capacity to states based on each state's relative share of regional electricity demand. This assumption injects a degree of uncertainty into our projected state

- level increases in natural gas projections. A more complex quantitative analysis would evaluate whether alternative allocations might significantly alter our qualitative ranki ngs of some states. The NewERA model is a whole

- economy model, which assesses both natural gas demand changes for the electric sector and for other sectors of the economy. Commenters stated that evaluation of risks associated with increases in natural gas demand requires an assessment of total natural gas demand, not just electricity sector demand. Commenters stated that results from the IPM model cannot inform such an assessment, even if state

specific results were estimated from that model's outputs; rath er, a whole

- economy model like NewERA is needed.

Commenters stated they performed the natural gas demand projections using the NewERA model for two extreme assumptions about the cost/availability of demand

- side energy efficiency: (1) That the full amount of demand

- side 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 C PP) 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 bot h 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 coordination and that States would use the flexibility mechanisms to the extent possible, b ut they differ in how much cost

- effective demand

side energy efficiency would be feasible. Commenters stated they considered the two extremes: (1) that the entire amount EPA assumed when constructing the rate limits would be cost

- effective as a first line of action for compliance and (2) that none of it would be cost

- effective relative to the other potential compliance actions.

Commenters stated that all other key compliance assumptions in their model runs rely upon EPA's IPM modeling assumptions. Commenter s provided Table 2 and stated the table demonstrates the similarity of total electric sector natural gas consumption in the EPA's IPM analysis and the comparable baseline and policy evaluation that they conducted using the NewERA model (NewERA with Energy Efficiency). Commenters 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 required state emission rate limits and the quantity of energy efficiency available in each state.

Commenters provided a figure with two maps

, entitled "Figure 1. Projected Natural Gas Demand in 2020 in Compliance with Section 111(d) State Targets, with Overlay of Locations of Interstate and Intrastate Pipeli nes." Commenters stated Figure 1 shows the following:

Most states will experience increases in total natural gas demand by 2020 relative to the maximum they consumed in 2012. The largest percentage increases are generally in the mid

- Atlantic, Midwest and u pper Midwest, implying relatively little overlap between states with risks of institutional barriers and those with the larger increases in natural gas demand. Given such lack of overlap, we defined the states with the highest potential risk, based on dema nd 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 could trigger concerns about electricity reliability . We also add to our first

- tier screen states that are projected to generate more than 35 percent of their baseload energy with natural 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 than 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 natural gas for baseload genera tion under the baseline case with increased reliance on natural gas expected under the CPP: California, Florida, and Nevada. Also included are Arizona, Alabama, Louisiana, Oklahoma, and Texas, which we project will rely on gas for more than 35 percent of b aseload generation under the baseline case and will increase reliance under the CPP.

Commenters provided Table 3, and stated Table 3 summarizes 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 percentage 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 passed our first set of screening criteria (as listed in 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 anal ysis or by other institutional considerations. Commenters noted their analysis included reference to forward prices curves and well

- publicized infrastructure development, although this qualitative ranking exercise did not include a rigorous analysis incorp orating forward prices. Commenters stated that causes for fragility could be, for example, being upstream of a downstream constraint. Commenters stated they used the following the considerations 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 pipeline deliveries have been constrained and are projected to be constrained, as reflected in high basis spreads. Projected large increases in gas loads are likely to lead to delivery problems

• Moderate to High

- At risk of non

- deliverability in event

- driven tight supply

demand circumstances (such as the polar vortex). These are states where gas pipeline deliveries have not typicall y been (and are not anticipated to be) constrained on a sustained basis during the peak seasons. However, states that relied on gas for more than 50 percent of their baseload 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 market conditions.

• Low to Moderate

- States that are likely to have large projected growth in gas consumption but have sufficient infrastructure (existing or in the pipeline) to accommodate the increased demand. States that relied on gas for more than 35 percent of their baseload generation in the baseline 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 that were not identified by their first set of screening criteri a, they applied a second

- tier screening 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 undesirable outcomes, particu larly when a very large number of states are experiencing simultaneous demand increases. Commenters stated they included as relatively higher risk the 13 states with increases less than the 25 percent but more than 10 percent in both modeled cases. Comment ers stated 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 those other states are not free of any natural gas supply ri sk, and so they have classified these states 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 gener ators have no history of purchasing from interstate pipeline capacity. Commenters stated that such states are largely in the Northeastern U.S., although Northeastern states are mostly projected to demand less total gas in 2020 than they consumed in 2012. C ommenters stated there are two deregulated states that are projected to have at least 10 percent 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 Illin ois.

Commenters provided a table in Figure 2 , which summarizes the 18 top

- ranked states' relative risk rankings with an overlay of natural gas pipeline infrastructure. Commenters stated that Figure 2 highlights that not only may gas

- exporting states with d ense 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., Maryland, Florida, and California).

Commenters provided Table 4 , which shows the relative rankings of states that resulted from application of their criteria and the additional sub

- rankings for the 18 states that were identified by our first screen. Commenters stated T able 4 shown in plain text format is as below :

Risk Level: Relative ly High

• Maryland: Spot pricing for Transco Zone 6 Non

- NY has historically shown constraints. Forward pricing confirms market participants' expectations of continued congestion in the Mid

- Atlantic markets. Also, 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 projects.

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 market sits just upst ream of potentially congested markets. New pipeline infrastructure investment is being made to serve the Cove Point LNG Export Terminal.

• West Virginia: While more closely tied to the relatively 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 than 50% of baseload and this reliance projected to increase under proposed CPP.

• Florida: Relies on natural gas for more than 50% of baseload generation in base case increased reliance under proposed CPP. Pipelines near capacity during peak months.

Risk Level: Low to Moderate

• Arizona: Not currently considered to be constrained; excess capacity on pipes going west.344 • Indiana, Iowa, Kentucky, Missouri and Ohio: Typically 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. Significant in

- state production and in frastructure build to accommodate new supplies.

• Louisiana: 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. Natural gas exporting state that experiences an i ncrease 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 fo r more than 35% of baseload generation under the base case and will increase to more than 50% reliance under proposed CPP. Natural gas exporting state that experiences increase 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 under proposed CPP. Limited pipeline infrastructure that connects to other at

- risk states (i.e., California and Arizona).

Risk Le vel: Low

Colorado, Georgia, Illinois, Minnesota, Nebraska, North Dakota, Oregon, South Dakota, Tennessee, Utah, Wisconsin, and Wyoming.

Risk Level: Lowest

• Arkansas, Connecticut, Delaware, Idaho, Kansas, Maine, 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 that did not pass any of our screening criteria. This does not imply that they are free of any ga s supply risk. For example, our analysis has not addressed how increasing gas demand on a national scale may affect even states that may have declining reliance on natural
gas.
Commenters noted limitations regarding their analysis:

The analysis, which is based on a screening of projected changes in natural gas demand by state with an overlay of hub price data, could be enhanced by a more detailed comparison of infrastructure assets in those states and surrounding regions to the projected load increases345 amo ng different types of customers. For example, in those states where pipelines have operated at or near capacity, existing interstate pipeline infrastructure may not be able to accommodate even small increases in natural gas demand. The screening analysis d oes not consider freeze

- offs, where small amounts of water produced along with natural 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 hea ting gas demand and electric generation natural gas demand suggest heightened risks associated with such events in the future.

Comment 2 9 : Commenters suggested the EPA's modeling with the IPM is inadequate with respect to reliability margins

, transmission and operational constraints , and prices.

Response 2 9 : EPA disagrees that our modeling is inadequate. The IPM model is well described noted in published documentation, and EPA used other analyses in addition to the IPM model

. Moreover, EPA be lieves that the CPP provides states with the flexibility, including trading, to develop plans that consider reliability and local circumstances, such as transmission constraints, extreme events, and system balancing. See sections V.D, VIII.A, VIII.C and VI II.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 reliability and regional planning concerns should be more fully considered. Commenters stated that, while the EPA attempted to evaluate reliability via the Integrated Planning Model (IPM), NV Energy stated that use of the IPM does not allow for adequate co nsideration of system reliability and other operational concerns. Commenters stated that, in the NV Energy system, the state utility resource planning codes require that resource development, purchases, retirements, and contracts be prioritized around a pe ak open position that includes reliability margins and potential unit forced outages, not an annual capacity factor. Commenters stated that IPM lacks sufficient granularity to reasonably simulate the operational implications of EPA's proposed regulation un der section 111(d), and consequently, the IPM model results cannot fully predict how operational reliability considerations will affect the tradeoff between emissions benefits and electric sector costs. Commenters specifically recommended the EPA:

• Refine its analysis of the proposed rule by incorporating 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 with operational realities.

• In the event impacts to reliability are predicted, states should be allowed the flexibility to incorporate mitigation measures, including the time to implement such measures, into their state plans.346 • If reliability impacts are encountered during implementation 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 regional system reliability, modify the BSER for each st ate to ensure that it can be implemented without deteriorating regional system reliability, and update its economic analysis to include all costs required to maintain regional system reliability.

Commenters provided the following detailed comments on EPA 's IPM analysis.

• EPA's IPM analysis models resource adequacy by implementing a reserve margin, which is a percentage applied to net peak load within a model region that drives new resource additions over the simulation period. As described in EPA's docume ntation for IPM v.5.13, the reserve margin requirement encourages regions to build beyond forecasted peak load to guarantee reliability of the electric generation system within the region. While this modeling approach ensures that there is sufficient capac ity available at the time of peak load (i.e., one hour in the year), it does not ensure that generating plants are dispatched to maintain sufficient operating reserves among all hours in the year. In fact, IPM lacks the ability to simulate dispatch of gene rating assets in a way that provides sufficient operating reserves are being carried consistent with regional reliability standards, which extend beyond resource adequacy criteria. Actual operations can significantly impact dispatch levels of flexible gene rating assets, which in turn can significantly impact emission rates associated with fossil

- fueled plants. The very foundation of the proposed rule is to establish a BSER and derive a target emission rate for each state. If states choose to implement 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 of modeling operating

reserves.

• The EPA's IPM modeling also assumes significant retirements by 2020, but does not adequately accommodate transmission constraints. The IPM represents the effect of major transfer path constraints by limiting the ability to transfer power between regions to set values for each path. This is a simplistic method commonly used in p roduction cost models to recognize known transmission capacity constraints in order to improve the accuracy of the generation dispatch solutions. However, since the actual transmission system is not modeled, simulation results from the IPM cannot predict t he performance of the transmission system. This is particularly true if a significant quantity of existing generation is retired and new replacement generation is proposed for installation at unknown locations.

• A related limitation of the IPM is that it d oes 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 operational constraints (e.g., ramp rates, startup and shutdown costs, minimum load limits, etc. ). These omissions impact IPM's ability to offer insights about questions related to the operation of a347 portfolio of fixed capacity and investment decisions related to capacity expansion. Consequently, the resource adequacy and reliability analysis TSD doe s not sufficiently demonstrate potential operational challenges associated with the capacity mixes resulting from the proposed rules. The TSD states that "...the implementation of this rule can be achieved without undermining resource adequacy or reliabili ty...," and IPM runs are used as supporting evidence for this claim. However, detailed unit commitment modeling has not been done to date and NV Energy believes this would be a necessary prerequisite to a thorough assessment of the resource adequacy and fl exibility 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 specia l

- 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 require detailed modeling, c ontingency planning, and real

- word testing. Commenters noted the corresponding percentages of NGCC units that in 2012 operated at annual utilization rates of at least 65 percent and at least 75 percent were 16 percent and 6 percent, respectively (U.S. EPA, Emission Guidelines for Existing Stationary Sources: Electric Utility Generating Units, June 2, 2014, at Fn 127).

Commenters expressed concern that IPM projects no new significant NGCC generation in Ohio despite the closures of coal

- fired plants, increas es in electricity demand, and increasing availability of natural gas in the state. Commenters noted that new NGCC units appear in the IPM projections in Ohio, but those units have negligible generation. Commenters stated this makes no sense and is incompat ible with Building Block 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 : Commenter s stated that, based on modeling ana lysis, 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 believes that changes since proposal, including modifying the CO2 emission performance rate for Florida and delaying the start of the interim performance period until 2020 have made the analysis referenced in this comment less applicable. Also, EPA believes that the Rule allows Florida to address local issues including system balancing, transmission constraints, and fuel diversity. The Rule does not prescribe the approach states must take to achieve CO2 emission performance rate s, and it provides fle xibility, including trading, for states to develop plans that consider reliability. States may choose any of a variety of approaches to develop a plan. See sections V.D, VIII.A, VIII.C and VIII.G of the final rule preamble of the CPP and Chapter 3 of the G HG Mitigation 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 incremental to Ten Year Site Plans were not estimated, but are not sufficient to avoid new energy sources. Commenters stated the FCG membership collaborated on a modeling analysis to estimate the potential impacts of the proposed emission guidelines on Florida's electric generation system. Commenters stated th e results of this analysis are intended to be order

- of

- magnitude and directionally representative estimates of the potential impacts to Florida's electric generation system and its customers. Commenters noted that the cost estimates do not include consider ation of potential stranded costs, deferral of planned investments, or potential technology improvements, including energy efficiency. Commenters provided the following points regarding their modeling analysis :

• The analysis first determined that Florida's rate in 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 details 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/MWh to $20/MWh. Even with fuel sw itching, Florida's average emission rate will 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 aroun d 80 percent, which would materially increase reliability risks resulting from over

- reliance on a single fuel. And even with fuel switching, Florida's average emission rate will still be significantly greater than EPAs proposed requirement of 740 lb/MWh

- ne t by 2030. Inter

- utility purchases incremental to Ten Year Site Plans were not estimated, but are not sufficient to avoid new energy sources.

• The analysis focused on the most impactful component 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 additional 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 proposal over the entire state of Florida, which includes utilities located in two FERC regions (the FRCC and the SERC), each member utility ran its dispatch model for its service area for the study cases. The results were then aggregated in order 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 fuel

switching and (2) Change Case, in accordance with Building Blo ck 2, NGCC units were increased to a 70 percent capacity factor and the operation of other generating resources was decreased, using a base case natural gas price. Natural gas prices were derived from the current Energy Information Administration (EIA) fue l price projections. Since increasing natural gas demand puts upward349 pressure on gas prices, the change case also evaluated a high natural gas price forecast from EIA to estimate the cost impact from supply and demand.

• The analysis then attempted to bridg e the gap between the change case and compliance. Because the implementation of Building Block 2 resulted in a significant projected gap in the state's average emission rate between the modeled decrease and the proposed goal of 740 lb/MWh

- net, the analysis estimated the theoretical amount of nuclear power, solar photovoltaic (PV) power, or biomass that would have to be added to reduce emissions further to meet the goal (Building Block 3). Again, the base case and high gas price sensitivity cases were evalua ted. The costs of the zero CO2

- emitting technologies were derived from public information, FPSC filings, and industry studies.

• The analysis did not evaluate cost impacts from Building Blocks 1 and 4. Regarding Building Block 1, which focuses on heat rate improvements at coal

fired units, the opportunities for efficiency improvements are limited, and the resulting very low coal

- fired unit capacity factors resulting from fuel switching make Building Block 1 moot. Building Block 4, concerning substantial inc reases in demand

- side energy efficiency, was not specifically evaluated due to limitations of the model and because significant increases in end

- use energy efficiency are out of the control of utilities and regulatory agencies, and ultimately are dependent on the customer. Moreover, Florida utilities 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 substantial a dditional improvements can be made in Florida is unreasonable and unproven.

Comment 3 1 : Some commenters suggested the EPA has not adequately considered the competing demands for the available natural gas and/or the contracting mechanisms for that gas.

Res ponse 3 1 : The EPA disagrees. We believe our modeling adequately represents competing demand for natural gas

– the IPM model uses a natural gas module that models gas use throughout the economy. 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 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, trading, time to develop plans, additional time before the start of the interim performance period (postp oned 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 states may consider local circumstances as they develop their plans, includin g system reliability, fuel diversity, other regulatory requirements, competing 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 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 i nterruptible supply contracts, not primary supply, meaning that current contracts may not support 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 o perational stress on the power system due to the lack of coordination between the commodity market and intrastate pipeline. According to the commenters, this lack of coordination affects both generators holding firm transportation contracts and those using interruptible transportation contracts. Commenters stated that PJM also pointed out that it is common practice for pipelines to issue operational flow orders (OFO) that hold gas generators to a ratable (or consistent) hourly gas consumption over each 24 h our 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 result in normally low

- cost and flexible resources becoming high

- cost and inflexible generators . Commenters gave an example of this operational stress and inflexibility in a table that summarizes delivery interruptions and constraints in the winter of 2013

- 2014 for Arkansas Electric Cooperative Corporation's (AECC) NGCC Oswald plant, which is con nected to Natural Gas 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 flexibility to vary the gas consumption at Oswald, and would also have incurred contractual and financial penalties just to start up the plant from January 5, 2014 through April 7, 2014 due to the OFO.

Commenters stated that natural gas pipelines have traditionally been built through long

- term firm contracts for th e pipeline capacity, and because firm contract holders purchase for peak periods, they may have excess capacity that they will release or contract to others (using interruptible or secondary firm contracts); because the electric and natural gas systems his torically have peaked at different times, this "released" capacity has been 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 consideration in the proposed re

- dispatch of NGCC is the difference in firm and non

- firm natural gas supply contracts between generators and gas suppliers. Commen ters noted that firm natural gas supply for year

- round service is expensive to obtain for generators in a competitive wholesale market. According to the commenters, NGCC units typically are used during peak summer periods when the supply need is greatest a nd non

firm gas supplies are utilized; however, if NGCC units are expected to operate at a higher CF, they would require a secured firm gas supply or face supply constraints and/or price spikes forcing limited run time. Commenters added that the price vola tility of natural gas is a key determinant with respect to higher utilization rates for NGCC units, as the fuel cost typically sets the marginal price and associated offers of these units in the market.

Demand increase351 Commenters stated that natural gas av ailability and inadequate pipeline infrastructure hinder the feasibility of achieving a 70 percent NGCC state

- wide 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 demand for natural gas to provide more and more base

- load electric utility generation, the potential demand from industries such as chemical manufacturing sector, and the unknown growth long

- term 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 Foundation 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 added that pipeline construction and installation is not only a cost issue, but faces land use challenges from potential not

- in

- my

backyard (NIMBY) opponents to l ocating pipelines near residential, commercial or farm lands.

Commenters stated that the Proposed Rule presumes there is existing firm gas capacity available to operate all NGCC units at a 70% capacity factor. Commenters stated that interruptible gas
contr acts are not a reliable option for units to meet 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 those levels. Co mmenters 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 typical consumption patterns of the three competing groups of natural gas users, demonstrating that consumption from the three groups generally creates an "infrastructure use equilibrium." 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 distribution 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 priorit y over natural gas for power generation). Commenters asserted that a major expansion of the pipeline network and/or a modification of the rules governing that market would be required to avoid such results.

Commenters stated that EPA does not consider the competition 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 and commercial sectors, and industrial consumers. Commenters ind icated that EPA's assertion 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, natural gas and electricity consumers
tr aditionally demonstrate counter

- cyclical consumption patterns, which help facilitate greater sharing and efficiency in the use of pipeline capacity

- the natural gas peak tends to coincide with the winter heating season, whereas the electric peak usually o ccurs in the summer. Commenters believe d that by requiring the increased use of natural gas for electricity throughout the year, the proposed rule likely would strain the supply of natural gas in the winter months, and pointed out that NERC has stated that "though fuel supply concerns 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 the result of all affected utilities increasi ng NGCC generation simultaneously. Commenters stated that, in that situation, demand for natural352 gas to serve NGCC generation would reasonably be expected to increase significantly, which, in turn, would require additional pipeline, compression, and storag e capacity as well as freeze protection for critical natural gas supply system components to meet demand of all end users during periods of high usage.

Commenters stated the EPA must further consider that new and existing NGCC plants will be in competition not only with each other for existing natural gas pipeline capacity but also with new and expanding export markets for natural gas. Commenters stated the EPA has not demonstrated that existing natural gas pipeline capacity will be sufficient to meet the n eeds of all consumers in the market, nor has it analyzed the natural gas price or deliverability impacts that this increased demand may create. Commenters stated the EPA has not accounted for unpredictable market trends, which will impact Texas's ability t o meet EPA'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 and new NGCC plants. Commenters stated the market trends for the past 10 to 15 years, as analyzed by BMcD, indicate that pipeline capacity is most efficiently utilized when held or managed by gas producers and gas marketing firms that direct supplies to different markets and sectors as demand and gas prices fluc tuate. Commenters stated the natural gas

- fired power plant resources have historically operated as intermediate resources during that timeframe, not at the high capacity factors EPA projects. Commenters stated that existing capacity may not be sufficient t o meet the needs of all consumers in the market, and capacity constraints could be a more frequent and prolonged occurrence.

Comment 3 2 : Commenter s 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 3 2 : The EPA disagrees. We believe our modeling adequately represents competing d emand for natural gas

– the IPM model uses a natural gas module that models gas use throughout the economy. 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 establish emission standards for affected EGUs. We
are prov iding 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 inte rim 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 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 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.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 replacing 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 to natura l 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 t he winter heating season in order to safeguard home heating supplies.

Comment 3 3 : Commenter s stated forcing the system to dispatch the NGCC fleet to a 70% capacity factor will lead to higher costs than otherwise might be required under a market

- based solution, which would price in the cost of carbon and allow the system to be dispatched around th at constraint.

Response 3 3 : The EPA disagrees. The CPP does not force the system to dispatch the NGCC fleet to a 70 percent capacity factor. The EPA believes that the CPP provides states with the flexibility, including trading and additional time, to deve lop plans that consider reliability and loc al circumstances, The NGCC capacity factor is not prescriptive, but rather was used to calculate CO2 emission performance rates. 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.

Comment 3 4 : Commenters expressed concerns regarding the economics of the redispatch proposal

. Response 3 4 : The EPA disagrees that the concerns over the economics 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 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, 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 many comments, we hav e modified the proposal and RIA

– the establishment of CO 2 emission reduction standards is regionally based. The Building Blocks are not prescriptive, and states may consider local circumstances as they develop their plans, including system reliability, fu el 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 the CPP Fina l Rule supporting the final CPP.354 With respect to lack of economics and claims that the proposal requires environmental rather than economic dispatch, EPA regards these claims as misunderstanding the proposal. The proposed rule was intended and designed to work with current environmental regulations that are consistent with the current security constrained economic dispatch (SCED) protocols and to continue that history of compatibility between environmental regulation and economic dispatch. This final r ule reinforces th at 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 s ection 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 in the proposed rule used to calculate final CO2 reductions for each state wa s done randomly by increasing natural gas combined cycle capacity factors to 70 percent regardless of economics.

Commenters asserted that EPA mistakenly assumes that re

- dispatch can be effortlessly and economically achieved. Commenters stated that, if the State of Mississippi's combined cycle fleet were to run at 70 percent, it would force uneconomic dispatch that would raise electricity prices.

Commenters stated that, in order for combined cycle generation to reach a capacity factor above an economic dis patch, such as the 70% level EPA proposed, 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 advantage of economic power purchas e opportunities.

Commenters expressed concern over the EPA's requirement for sale of electricity generated from natural gas as mandated federally regardless of price. 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 Commission er Moeller when the Commissioner said "changing from economic dispatch to environmental dispatch is truly 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 actions would strain utilities' ability to meet demand, especially during extreme weather events. Commenters also noted that utilities would be required to reconstruct generation portfolios in a short amount of time and at sign ificant 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, th e states' options may be limited because EPA's proposal changes the current electricity dispatch process which considers cost and reliability to adding environmental factors.

Commenters noted that, under the proposed rule, the energy markets of the PJM reg ion (which includes Virginia) may have to shift to an environmental 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 existing in PJM's markets are limited and do not support the reach of the proposed rule. The commenters 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 commenters stated that the complexity of redispatching a system that has been constructed and operated under a different regulatory and market paradigm is substantial. The commenters noted that given this complexity and the 2020 start date for compliance, it would be difficult to envision how the proposed rule would

accommo date economic dispatch; Commissioner Moeller is quoted on wondering how state compliance plans could be implemented in electricity 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 co sts, and NGCC operational costs will increase with higher capacity factors due to additional maintenance. Commenters stated the EPA did not appropriately demonstrate the cost of achieving requirement of BSER. Commenters noted that Indiana's NGCC plants ope rated at a combined 53 percent capacity factor in 2012, which is a historically high level of NGCC utilization driven primarily by low natural gas prices. Commenters stated the EPA cannot reasonably expect Indiana's NGCC capacity factors to economically ex ceed 53 percent in years with higher natural gas prices than those in 2012 and added that, as expected, Indiana's average NGCC capacity factors were lower in 2013 than in 2012 due to increased natural gas prices.

State

- and area

- specific comments

Comment ers stated the CPP's re

- dispatch analysis ignores 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. Commenters stated that, in order to allow for Ohio to dispatch natural gas generating units at a 70 percent efficiency rate, dramatic industry overhauls would be needed.

Commenters noted that Ohio relies upon PJM to operate the bulk electric system and dispatch generation on a least

- cos t economic basis. Commenters stated that, as a restructured state, Ohio depends on PJM and does not use an IRP process to determine what classification of generation units must be used, or when generating units can and cannot run. Commenters stated that ma rket forces provide the necessary incentives for generating 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 distribution ut ilities or may operate as independent merchant generators. Commenters stated that, when determining which generators are required to ensure reliability, PJM considers cost and unit efficiency on a locational basis through SCED. Commenters stated the CPP su ggests that PJM would need to perform environmental dispatch in lieu of economic dispatch. Commenters stated this places PJM in an enforcement role for the 13 states and the District of Columbia within PJM's footprint. 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 dispatch 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 carbon

emitting EGUs to ensure that these units dispatch less frequently, or not at all, while at the same time pre

- serving the eco nomic market maintained by PJM. Commenters stated this contemplated construct completely ignores the fundamental principles upon which SCED was developed: costs for these units would be artificial in nature; unit efficiency would be ignored as no considera tion would be given to the technical difficulties associated with ramping

- up and ramping

- down units; and the SCED model would be decimated. Commenters opposed any such artificial adders or penalties to the SCED economic marketplace, as the goal of this eco nomic marketplace is to ensure the delivery of reliable electricity to its consumers at affordable rates. Commenters stated that a carbon penalty would drastically increase the cost of electricity to Ohio consumers and, if coal units are not being utilized efficiently and are not being dispatched to allow for cost recovery, these plants may close, creating reliability 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 economic 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 stated that section 1234(b) of t he Energy Policy Act of 2005 defines economic dispatch to mean "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." Commente rs stated that Colorado electricity consumers are served by multiple power systems which use sophisticated software and supercomputers in assigning load to specific generating stations to effect the most economical supply as demand varies. Commenters state d that dispatch 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 very narrow reliability emergencies. Commenters
state d the EPA is asserting the authority to require 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 regulatory purview and cited a technical support document to the rule:

Reduced generation is encompassed by the terms of the phrase "system of emission reduction" in Clean Air Act section 111(a)(1) because, in accordance with the above

- discussed definitions of "system," reduced generation is a "set of things" which 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 Pollution Emission Guidelines for Existing Utility Generating Units, at 13

- 14.)

Carbon price

Commenters stated that implem entation of Building Block 2 should not be achieved by means of artificial manipulation of dispatch processes. Commenters suggested that States should be encouraged to implement procedures to develop and promote 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. Commenters also suggested that market based mechanisms could be the favored approach for building blocks 3 and 4. Commenters stated that White tags and Renewable Portfolio Standards for example 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 ab ility to control dispatch directly, 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 Block 2, particularly in competit ive electricity markets like Pennsylvania. Commenters stated Homer City needs an alternative compliance mechanism to recoup its capital investments. Commenters referred to EPA modeling 55 and stated that, (1) due to rising natural gas prices the capacity fa ctor of existing NGCC declines from 52% in 2020 to 42% in 2030, (2) to overcome this decline, in its IPM modeling of Options 1 and 2, EPA chose to use a structure that put a price on carbon, and (3) in its policy cases, the capacity factor of NGCC units ri ses above the base case, but still does not reach 70%. Commenters stated that the EPA states that the NGCC capacity factor stays below 70% because states choose "alternative CO2 reduction strategies" other than re

- dispatch to meet their goals. Commenters

s tated that modeling of Pennsylvania's target emission 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" strategy reference d by EPA is the backing out of coal from the generation mix. Commenters stated that the fact that EPA uses a carbon price constraint to model its options illustrates the double

- edged sword of Building Block 2 for coal

- fired power plants. Commenters stated that, to demonstrate compliance 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

- fired units. Commenters stated that both
app roaches would impose fatal blows to coal units; the only difference would be timing. Commenters stated that the latter would be quick, but the former, establishing a price on carbon, would impose a slow death by stripping all cash from coal

- fired facilitie s, a fact confirmed by EPA's IPM model runs that, under Option 1 (state case), have Units 1 and 2 retiring by 2025 and margins for Homer City Unit 3 declining precipitously. Commenters stated that, through 2030, revenue for energy and capacity remains rela tively flat for Homer City Unit 3, while the carbon cost per MWh increases, which lowers Unit 3's energy and capacity margin on a $/kw

- yr basis from $105.56 in 2016 to $70.79 in 2030, which is lower than the Unit's fixed operation and maintenance costs of $73.33/Kw

- yr.

Comment 3 5 : Commenters supported an environmental dispatch approach.

Response 3 5 : The EPA disagrees that the 111(d) final rule mandates 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 struct ure 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 th e ability to shift emission rate achievement between performance periods. In response to additional358 analysis and many comments, we have modified the proposal and RIA ; the establishment of CO2 emission reduction standards is regionally based. The Building B locks 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 the CPP Final Rule supporting the final CPP.
The following are summaries of the specific public comments under this comment:

Commenter s stated that environmental dispatch limitation is an easily achievable and straightforward way for EPA to bolster the Clean Power Plan's efficacy and achieve greater CO2 reductions. Commenters stated there are no demonstrated advantages to the proportiona te re

dispatch 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 requ ires, EPA must adopt the environmental dispatch limitation approach described by the commenters. 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 percent capacity factor without jeopardizing electric system reliability. Commenters explained that 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 percent or higher in 2012.

Commenters suggested the EPA employ an environmental 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 reduce its dispatch only if additional NGCC capacity (up to 70 percent) remained after coal generation is reduced to zero. Commenters stated the EPA must reconsider the way it allocates reduced dispatch among the coal and O&G steam fleets. Commenters stated the EPA's current proposal 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 stringent emission limitation, since existing O&G steam units genera lly emit 20

- 30 percent less CO2 per 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 best system of emission reductions. Commenters referred to Table 4 in their comments and stated that, for example, in Louisiana, an environmental dispatch limitation approach would reduce the state's final emission target by approximately 6.5 percent, which is greater than the reductions for that stat e expected under Building Block 1. Commenters stated that, on a national level, this approach to dispatch limitation would reduce CO2 emissions by around 12 million tons per year, approximately one

sixth 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 operate at capacity factors more suited for lower

emitting 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 shou ld be restructured to set targets based on dispatch to the least

- emitting power source available at the time the energy is needed, favoring, in descending order, zero

- carbon renewable generation, most efficient natural gas generation, and least efficient g as generation. Commenters stated this least

- emitting dispatch hierarchy should replace a least

- cost coal

- to natural gas

- fired unit dispatch regardless even of the latter's relative efficiency within its source class. Commenters urged the EPA to adjust its Block 2 targets based on establishing this system as BSER for 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 in the amount of gas

- generated power and the construction of new NGCC facilities. Commenters stated that, according to the EPA, the two

block approach (heat rate improvement plus dispatching) results in a gas production increase of 19

- 22 percent, and its four

- block approach in an increase 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 capacity for the four

- block approach. 192 Commenters stated the EPA projects that the situation improves for 2030, where RE and EE begin to displace the increased natural gas generation: according to EPA, by 2030 the two

- block approach results in 5

- 17 GW o f new NGCC capacity, while the four

- block approach results in 32

- 35 GW less NGCC capacity relative to the base case. 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 th e 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 Proposed Rule through 2050 an d beyond. Commenters encouraged the EPA to analyze the dispatch proposal taking into account the full life cycle of greenhouse gas generation of both coal and natural gas. Commenters noted that natural gas generates about 40% fewer CO2 emissions than coal during combustion.

Commenters stated the current dispatch scheme creates 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 some fossil fuel use will be needed for some time to come, for reasons including overcoming challenges related to the intermittency of solar and wind generation. Commenters stated a least

- emitting dispatch hierarchy takes these factors into account. Commen ters stated dispatch to renewable energy would occur only when it is available (and thus would not affect reliability) but 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 four

block BSER approach, EPA's emissions target will chan ge, 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 greater likelihood that states would follow the path EPA sets. Commenters stated that a least

- emitting dispatch system would incentivize, rather than displace, investment and infrastructure build

- out for renewable energy.

Commenters stated there is no doubt that a least

- emissions dispatch or loading order is adequately demonstr ated. Commenters stated it would also incentivize Block 1 heat rate improvement measures within the existing power plant fleet. Commenters stated that a least

-360 emissions dispatch system is not a novel concept, rather, it is adequately demonstrated, as a sim ilar system is already in place in California, the country's most populous state, where renewable energy resources are being integrated into the loading order so as to generate the least possible amount of GHG emissions from the power sector. Commenters st ated that, under this plan, California has set a target to meet 33% of its energy needs from renewable resources by 2020. Commenters stated the system requires dispatch capabilities at renewable energy sources that allow them to decrease or increase their energy 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. Commenters stated that its loading order places energy efficienc y and demand response as its top priorities (further enabling integration of intermittent energy), and calls for the use of renewable resources and distributed generation over fossil fuel

generated power. Commenters stated that, similarly, the states parti cipating in the Regional Greenhouse Initiative have several years of experience with factoring CO2 emissions limits directly into their dispatch bids.

Commenters requested the EPA to model least

- dispatch generation's technical feasibility as well as its cost

- effectiveness, or explain why it will not do so. Commenters stated that costs and benefits are among the factors the EPA must consider when establishing BSER, and that EPA's proposal for coal

- to

- gas dispatch is based in large part on the current suppl y of cheap natural gas. Commenters stated that, as EPA observes, dispatch records show that the rate of dispatch from coal plants to natural gas plants has increased significantly during recent years as gas prices fell to historic lows (and as the current least cost dispatch scheme would dictate). Commenters stated that the EPA bases Block 2 on its prediction that the economic advantage of using natural gas will continue unabated and thus that dispatch to gas

- fired generation is BSER. Commenters stated that , in devising Block 2 the EPA did not consider integrating renewable energy into the dispatch hierarchy. Commenters stated the EPA did not calculate the costs of doing so, and it certainly did not take the social cost of carbon into account, an essential r equirement if renewable energy is to be measured against fossil fuels on a level playing field. Commenters stated that shifting Block 2 from a coal

- to

- gas dispatch system to a least

- emissions dispatch system is likely to have only modest price impacts. Com menters stated that RE costs are falling at impressive rates, and some RE is already cost

- competitive 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. EP A observes that:

• Several studies have found the cost of RPS

- driven RE deployment to be modest. One comparative analysis that synthesize[d] and analyze[d] the results and methodologies of distinct state or utility

- level RPS cost impact analyses found the

me dian change in retail electricity prices to be $0.0004 per kilowatt

- hour (only a 0.7 percent increase), the median monthly bill impact to be between $0.13 and $0.82, and the median CO2 reduction cost to be $3 per 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, lea st

- emissions dispatch would factor in availability for natural gas plants, consisting of planned and unplanned maintenance and unplanned outages, and for renewable energy, those events as well as the intermittent nature of some renewable energy generation. Commenters stated that,361 unlike EPA's proposal, however, least

- emissions dispatch puts renewable energy sources ahead of natural gas plants and creates a strong inventive to invest in emission

- free power generation. Commenters stated that incentivizing ren ewable energy in this manner would also support an expansion of emissions reductions that come from Block 3.

Comment 3 6 : Commenter s stated the EPA should abandon its proportionate redispatch approach in favor of environmental redispatch.

Response 3 6 : 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 supplemental proposal, commenters stated that, to the extent that a jurisdiction curtails dispatch from its 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 classe s 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 quantify the additional reductions that can be achieved by requesting data from the utilities and/or regulatory authorities in the territories.

Comment 3 7 : Commenter s 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 3 7 : The EPA disagrees that we have inadequately analyzed this issue. Our analysis and modeling uses current da ta on NGCC availability, which reflects historical differences in failure rates. See model documentation as http://www.epa.gov/airmarkets/powersectormodeling.html http://epa.gov/powersectormodeling

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

Commenters stated that, despite diligent maintenance 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 suffered 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 i ts NGCCs, PowerSouth's available capacity would be significantly diminished and fall short of the expected 70 percent capacity factor.362 Comment 3 8 : Commenters stated the Proposed Rule does not take into consideration time and costs impacts resulting from non

- Clean Air Act regulations that will impact the ability of states to require large

- scale fuel switching from coal to natural gas to achieve their CO2 reduction goals.

Response 3 8 : The EPA disagrees with the interpretation of the requirements of the 111(d) final rule

, and we disagree that we have not adequately considered 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 subs tantial 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 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 proposal and RIA ; the establishment of CO2 emission reduction stan dards 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 requirement s 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 the CPP Final Rule supporting the final CPP.

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

Commenters indicated the EPA's analyses failed to consider FERC rules and other non

- Clean Air Act statutory and regulatory requirements. Commenters stated that it is impossible to implement Building Block 2 because FERC regulation preempts many of the actions Building Block 2 assumes the States will take. Commenters (referenced NERC documents and) stated that (1) new interstate natural gas transmission facilities must receive FERC review and authorization, (2) FERC genera lly does not authorize new pipeline capacity unless customers have already committed to using it (i.e., have firm delivery contracts), and (3) pipelines are prohibited from charging the cost of new capacity to their existing customer base. Commenters state d that, to ensure that pipeline capacity closely matches the needs 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 custom ers 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 natu ral gas pipelines include the Clean Air Act, Clean Water Act, the Endangered Species Act, the Coastal Zone Management Act, the Fish and Wildlife Coordination Act, the Historic Preservation Act, the Rivers and Harbors Act, the Mineral Leasing Act, the Feder al Land Policy Management Act, and the Wild and Scenic Rivers Act. Commenters stated 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 decision s on 250 candidate species through 2018. Commenters stated that a host of federal, state, regional, and local approvals are necessary for pipeline construction to begin. Commenters noted that urban development has encroached on many existing pipeline right

- of

- ways, thereby making some expansions parallel to existing363 pipelines difficult to implement and noted that projects often are opposed by multiple stakeholders, including landowners, environmentalists, and others with competing interests. Commenters sugg ested that FERC, under the Energy Policy Act of 2005, may be able to streamline this process in order to facilitate expeditious development of pipeline capacity, or it may become even more time consuming and difficult to 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 existing natural gas pip elines to improve their safety. Commenters added that the EPA did not take into account its own pending regulations to eliminate polychlorinated biphenyls (PCBs) along pipeline segments with new non

- PCB materials. Commenters asserted that it is fair to ass ume that the application of such regulations will add time and costs to the development of the infrastructure required to support the new gas generation

- the EPA should have factored this into its analysis.

Comment 3 9 : Commenters stated that the EPA's a nalysis contains significant errors and data quality issues suggested EPA should withdraw the current proposal, address these concerns, and publish a new proposed rule for public comment.

Response 3 9 : The EPA disagrees.We have reviewed the calculations for Building Block 2 and believe these concerns are either incorrect

. The 111(d) final rule has been modified since proposal and the analysis was redone. See the Regulatory 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 that overstate the reductions in CO2 rates that building block 2 could achieve, even if implementation were possible. Commenters stated the net result of these errors alone (us ing EPA's method) is that building block 2's contribution to Texas's goal would be 60 pounds CO2 per megawatt

- hour less than EPA calculates.

Commenters stated that EPA's analysis contains an extensive 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 correct the litany of concerns or determine how these corrections alter state goal calculations, compliance strategies, reliability evaluations, and
cost

- benefit analyses is too complex to complete within 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 errors that directly impact the proposed goals. Commenters stated that substantially more natural gas generation will be required to meet the CPP's goals than EPA estimates. Commenters stated the EPA's calculations assume a 400 TWh/year shift to existing NGCC generation from coal (376 TWh/year) and older oil

- gas steam (64 TWh/year) and the EPA estimates that the NGCC market will increase from 29 percent of the country's energy in 2013 to 33

- 34 percent of the nation's energy f rom 2020

- 2030. Commenters stated that, for NGCC to be 35 percent of the country's total energy in 2020, 39364 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 underestimating the needed NGCC, EPA's CPP also underestimates the substantial investment in NGCC that will be necessary.

Comment 40 : Commenter s asked for clarification regarding un its un der use d 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 EPA treat units th at were in outages for 11 months of the year, but operated at 100% capacity for the 12th month, the same way that it treated units that operated for a full year at a n 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 representative 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 demand. In the preamble the EPA states that average capacity factor is 60% or higher during peak hours of the day, but in the TSD, the EPA states that average capacity factor is only approximately 50%" during peak hours. The commenters asked which is correct?

Comment 4 1 : Commenter s requested clarification of the items in the GHG Abatement Measures TSD, page 3

- 14:

Response 4 1 : The EPA t hanks the commenters for these comments. The TSD has been revised for the final rule. See the GHG Mitigation Measures TSD in the docket for this rule.

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

Commenters requested clarification of the discussion regarding the availability of NGCCs is confusing and seems to suggest that the availability of "advanced" NGCCs is higher than that of lower firing temperature NGCCs. Commenters recommended that the EPA clarify the discussio n.

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 the CO2 emission rate of U.S. coal power365 plants is stated to be 2,200 lb/MWhr and that of NGCCs is 907 lb/MWhr and page 3

- 10, footnote 53 which refers to CO2 emission rates of 2,354 lb/MWhr for coal and 926 lb/MWhr for NGCC.

Commenters referred to Table 3

- 6, stated the ba se case has an NGCC capacity factor of 52% which is significantly higher than the value in 2012, and suggested the EPA clarify whether this is due to the assumed impact of planned coal unit retirements 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. Commenters referred to the final sentence on page 3

- 10 regarding an expected increase in natural gas production of 20% betw een 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 noted that EPRI estimates 3.6 trillion cubic feet (TCF) per year have already been approved an d another 3.6 TCF is under review by DOE.

Commenters stated there is a mismatch between numbers in the reference document and the cost

benefit memo and provided the following information:

Page 3

- 11: "Adding in the existing sources that were not yet online in 2012 (under construction) increases total NGCC generation calculated in the goal 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 power production in 2030 will be 1,743TWh, which is 178% of the 2012 value. That implies a significant increase in natural gas consumption versus today. For 2020 EPA predicts NGCC power production will be 1,369TWh, which shows a mismatch between what is in this reference document and what is in the cost

benefit calculation memo.

Commenters disagreed with a calculation regarding the heat rate of NGCC units and provided the following information:

Page 3

- 12: "For comparison, NGCC generation growth of 45 0TWh (calculated in goal setting) would result in increased 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 Btu/kWh r. EPRI believes 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 additional 3.5 TCF of nat ural 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 increase by 50%. Although the amount of power produced by simple cycles might be large enough to account for this discrepan cy, the modeling results in the cost

- benefits memo show only a very small amount of power being generated by simple cycles.

Commenters recommended the EPA clarify the discussion on page 3

- 14, stating the discussion is confusing and seems to suggest that t he availability of "advanced" NGCCs is higher than that of lower firing temperature NGCCs.

Commenters stated that additional rationale would be useful regarding the discussion on page 3

- 20 of the assumptions that went into the EPA's IPM predictions. Comme nters referred366 specifically to an assigned CO2 charge to units that produced CO2 at a rate greater than 1,100 lb/MWhr.

Commenters suggested the EPA clarify the second sentence at the top of page 3

- 26 where it is stated: "This is because only 29 state goal s are premised on the existing 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."

Comment 4 2 : Commenters stat ed 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 new 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 adequately demonstrate that the re

- dispatch to new gas sources concept represents BSER. Commenters stated thus, the EPA is p recluded from applying this approach in the final rule.

Response 4 2 : The EPA disagrees. Our legal interpretation is provided, and we have conducted extensive technical and economic analysis to support this final rule. The determination of BSER does not depend on any technical analysis of construction of new EGU’s

. 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 for the CPP Final Rule supporting 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

- effectiv eness analysis that the EPA carried out for building block 2 at proposal.

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

Comment 1: Commenter s stated that the c ost

- effectiveness of NG in redispatch is constrained by high gas prices and the price response assumptions in IPM.

Response 1: The EPA disagrees

– we believe the IPM modeling is conservative and demonstrates that the goals of the rule are achievable . 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 fle xibility 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 until367 2022), and the ability to shift emission rate achievement between perfor mance periods. 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 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 preamb le 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:

Commenter s stated that the potential cost

- effective role of addi tional 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 response assumptions (i.e., gas price elasticity) in the EPA's IPM modeling anal ysis. The commenter s noted that the gas price forecast in the June 2014 IPM base case (adjusted to nominal dollars using a 1.5 percent annual inflation rate) starts at $5.70/MMBtu in 2020 and rises to $7.00/MMBtu by 2025. The commenter s noted, in contrast, that recent NYMEX prices (in nominal dollars) start at just $4.43/MMBtu and only rise to $4.84/MMBtu during the same period. The commenter s remarked that this means the June 2014 base case IPM prices are 30 percent to 45 percent higher than current NYMEX prices and suggests that the cost of production and quantity of gas resources underlying the IPM estimates are overly conservative compared to current market expectations. The commenter s added that since current NYMEX prices are well within the range of NY MEX prices over the last year, this conclusion is not the result of a temporary or unusual pattern of NYMEX prices, but a more basic shift. The commenter s noted that several proposed findings in the CPP are sensitive to the EPA's assumptions regarding gas price elasticity including the 70 percent ceiling for existing gas unit utilization in BB2 and the decision not to include new NGCC or gas co

- firing in the BSER determination and state goal calculation methodology.

References Cited:

192 Ventyx, "NYMEX Henr y Hub Natural Gas Futures" available at: http://www.ventyx.com/en/solutions/businessoperations/business

- products/velocity

- suite

Comment 2: Commenter s stated that t he EPA's analysis in GHG TSD using 2011/2012 NG prices is inaccurate.

Response 2: The EPA disagrees. Our analysis of the 111(d) final r ule as presented in the Regulatory Impact Analysis of the final CPP includes higher natural gas prices and EPA believes that the estimated costs are conservative. We believe 2012 is appropriate. See section V I.D of the preamble to the final CPP and the Regulatory Impact Analysis of the final CPP.

The following are summaries of the specific public comments under this comment:368 Commenter s 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 supporting the proposed rules

- 2012 is not representative of natural gas prices and, in fact, represents the lowest price year in the past 12 years. The commenter s recommended the EPA either select an earlier year where prices were higher or use an average of multiple years to capture the variabil ity in natural gas prices. Commenters provided a graph, which shows U.S. EIA plot of NG annual avg $/Mcf cost from 2002

- 13, showing 2012 as lowest cost during this period.

Comment 3: Commenters stated that t he EPA needs to consider the impact of firm capacity

contracts.
Response 3: The EPA disagrees that we have inadequately considered 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 affect ed 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 t he 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 proposal and RIA

– the e stablishment of CO2 emission reduction standards 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 gene ration 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.

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

C ommenters stated that the EPA needs to recognize that the links between power markets and pipeline construction make it difficult to develop the pipeline system in a way that a llows states to comply with the proposed rule. Specifically, the commenter s stated that the EPA's assumptions about increased natural gas use ignore the firm capacity contracts used in the industry. The commenter s noted that natural gas pipelines have trad itionally been financed through long term, firm capacity contracts signed by natural gas consumers, such as local distribution companies, utilities and industrial consumers, and that natural gas pipelines are built when demand for natural gas can be transl ated directly into these contracts.

Commenter s also noted that some power generators, especially in RTO/ISO markets, only recover costs when they run at peak, and so are unwilling to sign firm capacity contracts, but rely on more flexible and affordable n on

- firm or interruptible contracts. The commenter s 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
genera tors cannot pay the premium required to purchase firm pipeline service and remain competitive in wholesale electric markets. The commenter s referenced an example in the369 February 2014 EIA report on natural gas issues and trends in New England, in which Spectra Energy announced a capacity expansion of its Algonquin pipeline of 1 Bcf/day in 2011 but that, in 2013, the proposed expansion was redu ced by 65 percent to 0.33 Bcf/day, due to lack of interest in long

- term firm transport capacity contracts, despite identified reliability concerns related to insufficient capacity. The commenter s noted that the report additionally found that public utility commissions require utilities to seek approval for signing long

- term contracts and the rate changes required to pay for them, which increases the uncertainty of when, and if, pipeline expansions occur.

Comment 4: Commenters stated that the EPA needs to c onsider the competing demands on natural gas infrastructure when calculating achievable 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:

Commenter s stated that the EPA must consider the competing demands on natural gas infrastructure when calculating achievable NGCC utilization rates. The commenter s asserted the electric power sector competes fo r pipeline services with two other major natural gas consumers: gas LDCs serving residential/commercial sectors and industrial consumers. The commenter s added that consumption by the electric generators does not necessarily coincide with consumption in the natural gas transmission system. The commenter s 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 trad itionally demonstrate counter

- cyclical consumption patterns, helping facilitate greater sharing and efficiency in the use of pipeline capacity. The commenter s added that gas peak tends to coincide with the winter heating season, whereas electric peak usual ly happens in summer. Increased utilization of NGCC units to 70% as sought by the EPA, according to the commenter s , will likely result in competition between the electric utility and the LDC for the same gas infrastructure, thus the EPA needs to further an alyze this integrated supply issue.

The commenter s further stated that, traditionally, pipelines have been built through long

- term, firm contracts for the pipeline capacity. Because firm contract holders purchase for peak periods, the commenter s stated, t hey may have excess capacity that they will release or contract to others (using interruptible or secondary firm contracts). The commenter s 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. According to the commenters, t he increased use of natural gas by EGUs, industrial customers and distribution companies will increase additional competition for this finite existing capacity.

The commenter s asserted there are natural gas transmission constraints that will limit increases in natural gas

- fired generation in Missouri. For example, the commenter s 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 Energy Center. Assuming there is no other370 demand on Line Segment 235, asserted the commenter s , it does not have sufficient capacity to serve the simultaneous maximum hourly flows for a ll 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.

The commenter s stated the pipelines serving Missouri were designed to serve winter heating load and do not have the capacity to simultaneously serve winter natural gas heating load and coal

fired generation displaced to natural gas and an upgrade of the magnitude necessary to support the EPA's target could be substantial. Accordi ng to the commenters, c ost of generation would also be significantly higher for the generation displaced from coal to natural gas because natural gas is more expensive than coal and the increased demand for natural gas resulting from the EPA's proposed rul e will further drive up the price of natural gas.

Comment 5: Commenters stated that t he 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 the flexibility to develop plans that consider reliability and local circumstances, including other regulatory requirements and system requirements. The Building Blocks are not prescriptive (and c omments addressing Building Block 4 are not addressed because EPA has not to include the provision in the final Rule) , but rather was used to calculate CO2 emission performance 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 perfor mance 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 Measures TSD for the CPP Final Rule supporting the final CPP.

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

Commenter s stated that the EPA should take into consideration the impact FERC authority will have in the achievability of Blocks 2, 3, and 4, particularly with respect to cost impacts to utilities and consumers. The commenter s noted tha t 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 planning in addition to cost allocation reforms and other matters, whi ch could have implications for the achievability of Blocks 2, 3 and 4 as well as costs for states with utilities subject to FERC jurisdiction. The commenter s additionally noted that since FERC jurisdiction is limited in Texas, not all Texas utilities are s ubject to FERC Order 1000, which should be considered by the EPA in evaluating the potential emission reductions attributable to Blocks 2, 3, and 4.

Comment 6: Commenters questioned s tates' legal authority to set prices affecting dispatch.371 Response 6: 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. State are not requir ed to set prices in order to achieve these requirements. States may choose to meet the 111(d) requirements through a variety of ways, including methods that impact that costs of affected EGUs participating in electricity markets. ISOs/RTOs allow generator s to bid in their variable costs, including environmental compliance costs, into the energy market. In ISOs/RTOs where system operators dispatch the system in a least

- cost economic dispatch process, an affected EGU having higher costs will likely impact th e amount that the affected EGUs is dispatched

. There is ample precedent in other federal and state environmental programs which establish, for instance, allowance trading. Tradable allowances generally increase the costs of affected generators which in t urn impacts system

. See VIII.C of the preamble of the final CPP.
The following are summaries of the specific public comments under this comment:

Commenter s stated that the EPA should address, from a legal perspective, whether a state could or should be able to set prices that would influence the dispatch of the electric market.

Commenter s cited U.S. Court of Appeals for the 3rd Circuit opinion on case 13

- 433 0. Commenter s stated the case involve NJ's authority to arrange for the construction of new electric generators through a scheme focused on capacity prices and in which the 3rd District Court of Appeals overturned the state decision.

Comment 7: Commenters stated that IPM presumes regional trading.

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 Regulatory Impact Assessment of the final CPP.

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

Commenter s stated that the discussion of modeling results in the proposal regarding the magnitude of redispatch refers to a region's existing electric generating fleet, and such a reference is only meaningful if there is regional trading. The commenter s assert ed 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 economically viable option for any i ndividual state; and therefore, the EPA must reconsider this assumption.

Comment 8: Commenters stated that the IPM is inconsistent with economic utility practices.

Response 8: The EPA disagrees. We believes that analysis of the rule is appropriate and that we properly considered market practices. T he 111(d) final rule provides states with the flexibility to develop plans that consider reliability and local circumstances, including the circumstances of individual plants. The Building Blocks are not pres criptive, but rather were used to calculate372 CO2 emission performance rates. The EPA believes the IPM model to be useful in regulatory analysis, but the specific model results are not prescriptive for the CPP. States may choose any of a variety of approache s. 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, 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.

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

C ommenters stated that the IPM is inconsistent with economic utility practices. Commenter s stated that EPA's IPM analysis for Option 1 compliance for Arizona is the most relevant comparison, considering that Arizona has no firm plans for regional compliance at this time. Commenter s asserted that Pace Global finds the EPA analysis to be inconsis tent 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. Commenter s stated this large reduction in the overall plant utili zation at Springerville Generating would result in an economic outcome that would favor shutdown over operating the plant at average annual capacity factor of 40% over a 10

- year period. Commenter s stated it would average 30% over a 10

- year period.

Accordi ng to commenter s , Pace Global does not find this analysis to support Arizona's ability to maintain any more than a very minimum capacity of the existing coal fleet online beyond 2019 while complying with EPA's goals, particularly the interim goal. Commente r s stated EPA's analysis is flawed and disagrees with the EPA's conclusions that, under the proposed rule, Arizona could maintain a portion of its coal capacity beyond 2019 while complying with the interim and final goals.

Comment 9: Commenters stated tha t t he 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 and 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 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 incl udes, 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 many comments, we have modified the proposal and RIA

– the establishment of CO2 emission reduction standards 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.1373 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:

Commenter s stated that the EPA's cost effectiveness evaluation significantly underestimates the true economic impact of its proposal and that the wording in this section is misleading as the EPA's analysis is based on re

- dispatch at a representative, albeit hypothet ical, coal

- fired EGU to a representative NGCC EGU when, in reality, the EPA used the IPM to assess the costs of re

dispatch [79 FR 34864]. Therefore, the commenter s asserted, $30/metric ton represents an average cost across the entire modeling domain. This is an important distinction, according to the
commenter s , as BSER, including the cost effectiveness component, must be applied at the source level, defined as "any building, structure, facility, or installation which emits or may emit any air pollutant." [42 USC 7411(a)(6).]

According to the commenter s , 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 BS ER. Notwithstanding the legality of such an approach, since the EPA is establishing goals for each state as "binding emission guidelines" [79 FR 34897], it should, at a minimum, per the commenter s , calculate cost effectiveness values ($/metric ton) for eac h state. From that data, the commenter s 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 commenter s stated they estimated the cost effective ness of the proposal for Arizona using a method similar to the EPA's method. Using the results of modeling performed by PACE Global to compare the total cost and total emission reductions associated with compliance with the EPA's building block approach to a reference case, the commenter s 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 commenter s believed this a conservative estimate, as PACE did
not ru n a true business

- as

- usual case (i.e

., absent the CPP). The commenter s further estimated that $122/metric ton is not a direct comparison with EPA's estimate of $30/metric ton, as EPA's estimate was limited to only the re

- dispatch building block and that if their cost effectiveness estimate was limited to the re

- dispatch component of the proposal, the value would likely be higher.

The commenter s stated nothing in the docket explains how Arizona, a significant exporter of energy, would become a significant im porter by 2020. During a teleconference with EPA officials on September 18, 2014, the officials stated 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, however, the commenter s do not believe such a shift in interstate power transfers is likely to occur. The
commenter s added that EPA has provided no explanation to support this approach or the value or "fee" added to California electricity imports. If the EPA's assumption is wrong and Arizona is able to continue to export significant amounts of energy to California based on economic dispatch (or at least to serve load in Arizona), fossil generation in Arizona would increase,374 according to the commenter s , as would the cost to abate the resulting emissions to meet Arizona's stringent goal.

The commenter s stated that a flaw i n the EPA's modeling 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 the availa bility of individual units. Some of these commitments may not represent the most economical dispatch given the variability in loads across the grid during each hour, according to the commenter s . While the commenter s recognized that it would be difficult fo r EPA to capture that level of granularity, the commenter s believed EPA should, at a minimum, acknowledge that incorporating these elements accurately would increase the cost of compliance for each of these scenarios.

The commenter s also questioned the EPA 's constraints, or lack thereof, for low utilization of large coal

- fired EGUs. While the EPA claims that "IPM includes detailed representations of key operational limitations, such as turn

- down constraints," [79 FR 34864] the commenter s do not believe IPM' s turn

- down constraints accurately reflect economic realities of operating a large, coal

- fired unit at low capacity factor. The commenter s stated that EPA's compliance case show several units at SGS, which is operated by TEP, operating at annual capacity f actors far below what TEP would consider economical.

Most significantly, according to the commenter s , EPA's cost estimates failed to consider the remaining book value of assets forced to retire early. The commenter s stated EPA apparently dismisses strande d costs based on the notion that states could avoid them through the "flexibility" allegedly afforded in the rule. [79 FR 34897] The commenter s believe they are entitled to recover their capital investment, having approximately $1 billion in book value

rem aining on all of its coal

- fired generating assets, of which $739 million is subject to retirement under the Proposal that would need to be recovered. In addition, the commenter s asserted their customers would be paying for nearly $1.1 billion in new genera tion to replace the retired coal

fired plants. The commenter s concluded these combined costs would have a significant impact on retail rates.

The commenter s urged EPA to correct these deficiencies and re

- evaluate the cost effectiveness of Proposal, recogn izing the need for modifications to the final rule to maintain the desired cost effectiveness.

Commenter s stated that, as proposed, application of BB2 accounts for 77 percent of the required reduction in the CO2 emissions/net

- MWh in Arizona. The commenter s added that EPA assumptions result in an overstatement of the amount of coal and gas steam generation in Arizona (and likely other states) that could be displaced by NGCC generation starting in 2020. The commenter s asserted that the costs projected by EPA for implementation of the Proposed Carbon Rule must be reevaluated for Arizona and other similarly situated states.375 Comment 10: Commenters stated that EE/RE cost estimates are too high and cost estimate for natural gas are too low. Commenters stated that m odest corrections to the EPA's estimates would show that EE and RE are cheaper carbon

- reducers than 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 incre ases in natural gas fired capacity nor does it believe that there will be a large increase in natural gas consumption. See the Regulatory Impact Analysis of the final CPP.

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

Commenter s stated that because burning natural gas also releases carbon we must soon phase out electric generation from natural gas. Thus, the commenter s asserted, the proposal significantly understates the cost of BB2. An accurate estimate of the cost of switching to natural gas over the next 5

- 15 years, according to the commenter s , must incorporate the estimated cost of switching away from natural gas soon thereafter. The commenter s asserted that the true cost of switching to natural gas now is the cost o f that change plus the cost of replacing natural gas with renewables (the only feasible alternative) in a few years.

The commenter s 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 renewables are cheaper carbon

- reducers than natural gas. The commenter s asserted that switching to natural gas may burden consumers because the price of natural gas is expected to rise steeply

- 23% by 2030. Also, the commenter s believe that if the CPP spurs additional demand for natural gas, it could increase prices further, deepening the strain on low

- income households, whereas the cost of building renewable
gene ration continues to plummet and, once built, renewable 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 ability to consider these concerns. The 111(d) final rule requires that states develop plans that establish emission standards for affected EGUs. We a re 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 start of t he 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 proposal and RIA

– the establishment of CO2 emission reduction standards 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,376 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 a re summaries of the specific public comments under this comment:

Several commenters expressed concern about the economic impact of redispatch, including infrastructure. Commenter s stated that the EPA has not adequately analyzed the economic impacts and of NGCC redispatch and must evaluate stranded asset costs, state

- level employment impacts, and new infrastructure costs. Commenter s noted concern regarding stranded costs for existing retrofitted coal units and believed the addition of NGCC would exacerbate s tranded costs while raising rates to pay for new NGCC units.

Commenter s stated that, as a small business entity with only one generating unit, they have no other means to supply their customers, thus, redispatching from coal will increase the cost to

owner s/customers. The commenter s estimated the cost increase to be 10

- 20%, dependent on the decrease in their output. The increased cost, stated the commenter s , is due to operating below design output of the unit, which decreases efficiency (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,
commenter s stated concern that in moving from an "economic dispatch" to an "environmental d ispatch," units will be called to generate primarily based upon the emission profile of the unit. The commenter s stated this could be reconciled with economic dispatch if a carbon fee were added to each generator's costs to reflect its emissions profile, f orcing the costs of greater emitting generation higher in the merit order of dispatch.

The commenter s questioned whether there will be sufficient pipeline capacity to support this increase in natural gas generation and noted that pipelines have traditiona lly been financed with long

- term contracts

- often 20 or 30 years in length

- 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, accord ing to the commenter s , 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 vertically integrated markets). For example, the
commente r s noted that despite widespread recognition that New England needs additional pipeline capacity, the fundamental challenge has been how to finance this expansion when generators are reluctant to sign long

- term contracts. The commenter s stated concern that this challenge of financing adequate pipeline infrastructure in New England will be replicated in other markets because of the proposal's increased reliance 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 final rule. We believe we have offered sufficient guidance to states. The 111(d) final rule requires that states develop pl ans 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 flexibility377 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 many comment s, we have modified the proposal and RIA

– the establishment of CO2 emission reduction standards is regionally based. The Building Blocks are not prescriptive, and states may consider local circumstances as they develop their plans, including system reliab ility, 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:

Several commenters stated that the EPA had not adequately analyzed the economic impacts of NGCC dispatch. Commenter s stated that EPA guidance did not explain fully how an economical dispatch of NGCC will occur and the CPP did not take into consideration the mechanism used to require the operation or incentivize utilities under an economical dispatch model to operate NGC C plants. The commenter s requested that the final CPP specifically address how state plans and cooperatives will economically dispatch NGCC units to meet the CPP. The commenter s noted, for example, that the CPP should consider the 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 commenter s asserted that obtaining rights

- of

way is often difficult and time consuming and doing so hastily can create additional costs and risk. The commenter s 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 included 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 regulatory objectives. Accordingly, the commenters stated that the EPA must consider the economic consequences of stranded assets associated with the proposed redispatch, along with the impacts of local j ob 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 mandated by other CAA programs, such as the Regi onal Haze Rule and the MATS rule, other units predicted to retire are less than 10 years old. The commenters stated owners of these plants have not had sufficient time to recover the costs of these investments and that forced retirements would result in bi llions 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

- fired assets would have no salvage value, forced retirement of coal

- fired generation likely would mean bankruptcy and dissolution for many merchant generators.

Commenters stated coal

- fired EGU retirements as a result of redispatch to NGCCs would have signi ficant economic impacts on local economies. For example, the commenters asserted that the378 EPA projects that, by 2020, 5 of the 7 coal

- fired EGUs 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 economic impacts of these shutdowns as these plants are an important source of high

- wage employment, and most are located in rural areas where there are few alternative employment options. T he construction of new NGCCs, even if a viable option, according to commenters would not compensate for these impacts, as NGCCs require less than a third of the staff required to operate coal

- fired EGUs.

Comment 13: Commenters expressed c oncern regarding cost and availability of needed NG pipeline infrastructure.

Response 13: The EPA disagrees with the interpretation of the final rule

– it does not mandate specific capacity factors, 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, 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 an alysis and many comments, we have modified the proposal and RIA

– the establishment of CO2 emission reduction standards 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 Miti gation Measures TSD for the CPP Final Rule supporting the final CPP.

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

Commenter s expressed concern regarding the cost of additional natural gas pipeline infrastructure that will be needed through 2030. Commenter s stated that INGAA estimated that the U.S. and Canada will need 28,900 to 61,600 miles of additional natural gas pipelines t hrough 2030; INGAA and the Eastern Interconnection States' Planning Council projected that expenditures from 2014

- 2035 for new pipeline, compression, and pumping infrastructure would be about $10 billion per year; and the U.S. will need 1.4 TCF of new work ing gas storage capacity at an estimated cost of $12.5 billion. Commenter s 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, commenter s stated these numbers would be vastly higher if existing NGCC units were required to double their capacity factor and, if States cannot meet the emission reduction requirements EPA proposes for Building Blocks 1, 3, and 4, and more pressure is put on Building Block 2, these numbers will climb higher still.

Commenter s stated that generators in Pennsylvania must bid into PJM's capacity markets and do so on an economic basis. The commenter s believed the forced incentivi zing of natural gas over379 coal threatens to imprint a significant distortion on the market and is concerned if there is enough infrastructure and fuel supply available if this occurs. The commenter s noted that EPA estimates that this forced demand increase will drive up natural 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.

Comment 14: Commenters expressed c oncern that reduced power supply 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 plans that establish emission standards for affected EGUs. We are pr oviding 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 in terim 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 proposal and RIA

– the establishment of CO 2 emission reduction standards 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, oth er 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 su mmaries of the specific public comments under this comment:

Commenter s stated that to illustrate the importance of power supply diversity at the national level, IHS compared a base case reflecting the generation mix in regional U.S. power systems during the 2010

- 2012 period with a reduced diversity case. The commenter s noted that IHS found that the cost of generating electricity in the reduced diversity case was more than $93 billion higher per year and the potential variability of monthly power bills was 50 percent higher compared to the base case. Consequently, the commente r s 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 jobs compared to the base case and U.S. GDP would be nearly $200 bill ion less. The commenter s stated additional costs would arise if current trends lead to the retirement and replacement of existing power plants before it was economic to do so.

Comment 15: Commenters stated that the EPA n eed s to consider that fuel costs va ry nationally.

Response 15: The EPA disagrees. We do consider that fuel costs vary 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 flexibility380 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 many comments, we have modified the proposal and RIA

– the esta blishment of CO2 emission reduction standards 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 generat ion 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

, Chapter 3 of the GHG Mitigation Measures TSD for the CPP Final Rule supporting the final CPP and the R egulatory Impact Assessment of the final CPP

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

Commenter s stated that coal costs for serving electricity generation vary significantly between regions and that the EPA has bias ed its Building Block 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 commenter s noted that most coal sourced within Minnesota

comes from the Powder River Basin (PRB) of Montana/Wyoming. The commenter s stated that Minnesota's imported coal

- based electricity is also mostly fueled with lower cost PRB coal and North Dakota lignite. The commenter s referenced a table from the EIA November 20 14 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 Minnesota 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, according to the commenter s , is the natural resource being suited for strip mining. The commenter s stated that PRB and lignite also benefit from relatively che ap transport by rail across the Great Plains to Midwest utilities for electricity generation and mine

- mouth to generating unit operation.

In contrast, the commenter s asserted that natural gas pricing that may result from expanded operation of existing NGC C units is expected to be more uniform across the U.S., resulting in a much higher premium for compliance with the EPA's proposed 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 existing NGCC. The commenter s believe d the BSER cost

- effectiveness analysis should be recognizing 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 commenter s stated that EPA's Building Block 2 cost effectiveness analysis is not properly reflecting the energy

- based natural resources, power markets and associated economics in the upper Midwest.

The commenter s added that interim modeling (EGEAS September 17, 2014) analysis of the CPP performed by MISO indicated that EPA's Building Block 2 carries a cost premium of $53/ton of CO2 emission reduction when compliance is delivered at the MISO model s ubregion (state) level. The commenter s 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 commenter s asserted that this MISO modeled high cost reinforces how Minnesot a Integrated Resource Planning that includes CO 2 cost consideration designates existing NGCC for dispatch to support reliability for intermittent renewable resources and to serve peak customer demand periods rather than a base381 load dispatch capability. Con sidering that the cost premium to redispatch existing coal generation to existing NGCC exceeds the EPA's own cost effectiveness criteria, the commenter s stated that the EPA should delete the Building Block 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 Minnesota existing NGCC generating units.

Comment 16: Commenters stated that the c ost effectiveness analysis does not prope r l y take into account the workings of the wholesale energy market.

Response 16: The EPA disagrees. We believe our analysis adequately addresses the market, and, moreover, the rule does not compel the actions described by the commenter. 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 incl udes, 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 many comments, we have modified the proposal and RIA

– the establishment of CO2 emission reduction standards 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:

Commenter s stated that Block 2 redispatch from existing coal to existing NGC C operated at a 70% capacity factor represents the largest Minnesota contribution to the EPA's proposed BSER determination of the Minnesota CPP target due to factors including the relatively large amount of existing Minnesota NGCC capacity deployed to prov ide reliability support for intermittent renewable energy resources, reserves needed to quickly meet metro area peak customer energy demand periods and early action efforts by Xcel Energy under its Metropolitan Emission Reduction Program (MERP).

The comme nter s asserted that Minnesota Power currently 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 customer electricity needs. If EPA's CPP Block 2 requirements compel the redispatch from coal to higher priced natural gas, the commenter s stated utilities will be forced to curtail their self

- generation from coal and substitute existing NGCC from other areas within the state or region. Because this powe r is purchased in the wholesale electric market and not self

- generated, the commenter s stated it exposes utility consumers to considerable cost and availability risks. The commenter s stated that Minnesota utilities manage the risk of market cost exposure f or their customers by including a managed segment of purchased power in their generation mix. The commenter s asserted that Minnesota's IRP process requires that utilities consider and manage risk in their overall resource planning processes. The382 commenter s believe that compelled purchases of existing 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 n ot given adequate consideration to how wholesale electric markets work or how utilities manage price risk.

Comment 17: Commenters stated that BB2 assumptions do not recognize physical, financial, and regulatory constraints on the electric grid, electric reliability and the cost of energy to

consumers.
Response 17: The EPA disagrees with the interpretation of the final rule. The rule does allow states to consider the concerns the commenters express. 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, tradin g, 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 comme nts, we have modified the proposal and RIA

– the establishment of CO2 emission reduction standards is regionally based. The Building Blocks are not prescriptive, and states may consider local circumstances as they develop their plans, including system reli ability, 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 f or the CPP Final Rule supporting the final CPP.

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

Commenter s stated BB2 creates winners (gas plant owners) 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 limits of the CAIR and the utility MATS rule for units that will be prematurely closed, commenter s said. The EPA's proposal does not take into account the billions in stranded costs to consumers if this occurs, commenter s further added. The
commenter s asserted not assessing the cost impact is contrary to the EPA's own guidelines requiring cost impact assessment of a section 111 proposal. Commenter s stated t hat the EPA's BB2 does not recognize the need to capture the economic value of existing resources. The commenters asserted that Building Block 2 assumptions do not recognize physical, financial, and regulatory constraints that could have negative consequen ces for the electric grid, electric reliability and for the cost of energy to consumers.

Commenter s stated that among the practical problems the EPA has not addressed into its models

are:383 • Generator Ownership & Stranded Assets: The EPA's proposal suggests that massive redispatch of the entire electric generation 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 plants simply cannot become the type of load

- following unit necessary to meet EPA's expectations.

• Permit Constraints: Many coal plants have minimum load requirements to keep pollution control systems operating and many gas plants, designed for peaking purposes only, we re permitted with significant operating limitations to address local environmental impacts.

• Generator Location: Power generator location is a critical factor for electric reliability but is not addressed by the EPA's IPM model.

• Transmission Constraints: Se rious transmission problems 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 sh ortfalls that will serve to limit change in dispatch.

Similarly, commenter s concluded that the EPA should recalculate state goals to account for physical constraints, actual gas generation capacity and known pollution control investments. Additionally, the commenter s believe d states should have the flexibility to further adjust g oals for stranded investment, and physical and permit constraints that prevent or delay redispatch.

Comment 18: Commenters stated that the l ack of fuel diversity will lead to higher fuel costs and unreliability.

Response 18 : The EPA disagrees with the commenter’s interpretation of the final rule. The 111(d) final rule does allow states to consider transmission and natural gas distribution infrastructure. Additionally, we have postponed the start of the performance period in response to analysis and comments. The 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) requirement s. 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 betw een performance periods. 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 Building Blocks are not prescriptive, and states may consi der 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 r ule preamble of the CPP and384 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:

Commenter s stated that while the EPA believes that th e power industry can support higher gas consumption without additional pipeline infrastructure investments, NERC suggested additional pipeline capacity will be needed in Arizona, Nevada and New England states. The commenter s stated that increased natural g as power generation will require pipeline expansion to maintain a reliable source of natural gas, particularly during peak winter heating season. Pipeline constraints and growing gas and electric interdependency are challenges that will impede the electric industry's ability to ensure delivery of natural gas, according to the commenter s . The
commenter s asserted that the EPA did not consider the time frame to build new gas plants as well as additional pipeline capacity (a minimum of 3

- 5 years or more, to pla n, permit, sign contracts, finance and build additional infrastructure).

The commenter s asserted that the EPA does not value coal fired generation and seems to favor shutting down all coal. The commenter s stated that risks of losing the coal fleet will be an unstable grid, soaring electrical energy pricing due to lack of fuel diversity and the loss of economic growth. The commenter s suggested the EPA consider recent activities in Germany where they are building highly efficient coal fired power plants witho ut carbon controls after years of following the same policies the EPA is proposing today. The commenter s asserted it is not practical or economical to operate coal fired power plants at a 40% capacity factor; the cost to the ratepayer for supporting idle c apacity 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 not supportable.

Response 19: The EPA disagrees. We consider our ana lysis adequate. The study cited by the commenters does not model the provision of 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 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 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 proposal and RIA

– the establishment of CO2 emission reduction standards is regionally based. The Bui lding 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 :385 Commenter s stated that while the IPM suggests that the Proposed Carbon Rule produces a net positive outcome for Arizona, it uses incorrect assumptions and does not provide the level of detailed system modeling to identify the power system reliability issues and gas pipeline constraints that would arise within Arizona. The commenter s 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 assumptions are inaccurate. For example, in reviewing the results for Arizona, the commenter s stated EPA assumes that coal units can be shut down in one year and then brought back on line in future years, which is unreasonable. The
commenter s added that EPA also assumes certain coal units can be operated as cycling/peaking units, which is untrue for those units in Arizona.

The commenter s added that import capacity into Arizona from New Mexico, taken from a Western Electricity Coordinating Council (WECC) report, is oversta ted by over 3,000 MW. The
commenter s stated that in EPA's modeling about 90 percent of the imports to Arizona come from New Mexico, which would be substantially reduced if the proper import capability were used. The commenter s stated EPA did not consider t he cost of "stranded assets" in its analysis, which in Arizona alone could amount to $3.0 billion. The commenter s added that EPA did not consider the electric transmission and gas pipeline constraints within Arizona with adoption of the proposed rule. The commenter s believe EPA would have to factor in the significant costs associated with building additional transmission lines and pipelines in AZ when coal plants are shut down. The commenter s also asserted existing transmission lines may need to be retired before the end of their useful lives, which is another cost that must be considered in AZ.

The commenter s added that the inputs in the IPM differ from the assumptions made in the emission targets, creating a disparate result in that EPA is using the IPM to backstop the 111(d) emission targets; however, the two are using a completely different set of assumptions and inputs to do so.

Comment 20: Commenters commented on the c ost analysis at the state level and requested IPM clarification

. Response 20: The EPA disagrees with the commenter’s interpretation of the rule

– it does not, for example, require that the building blocks be implemented exactly as described in the goal setting nor does it require individual EGU owners to meet specific capacity factor go als. Because those specifications are not part of the rule, we have not modeled them. 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 h ow 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 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 proposal and RIA

– the establishment of CO2 emission reduction standards 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” of386 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:

Commenter s asked why did the EPA not perform modeling to assess the cost of redispatching NGCC to 70% capacity factor at the state level, not only nationwide. Commenter s 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 state level. The commenter s also asked for clarification of whether the IPM can restrict redispatch mo deling to the same owners. Finally, the
commenter s asked for clarification of the methodology 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’ interpretation 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 flexibility as to how they structure t hose 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 abi lity to shift emission rate achievement between performance periods. 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 Building Block s 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:

Some commenters were concerned with the costs of potentially stranded investments. Commenter s stated potential for stranded investments is not limited to application of BB2 in 2020 and that even if the implementation date for BB2 were extended to 2030, ful l implementation would result in substantial stranded investments in Arizona. For example,
commenter s stated that Unit 4 at the Springerville Generating Station commenced operation in December 2009 with bond financing of approximately 30 years with final b ond maturity in 2038. In addition, commenter s stated SRP recently completed 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 fina l bond maturity in 2041. The commenter s added that these stranded cost estimates do not include those that will be incurred by AEPCO, APS, SRP, and TEP for compliance with the Regional Haze rule.387 Commenter s stated that several existing coal

- fired units in Arkansas likely will be forced to retire as a result of the proposed rule, resulting in stranded assets for which cost recovery will be a significant concern for AECC and its members. The commenter s asserted that if a generating unit, which takes years and hundreds of millions (if not billions) of dollars to build, is forced to prematurely close and it has not yet reached the end of its useful life, then the owner(s) of that generating unit will be left with stranded assets. The commenter s added that if a u nit 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 decommissioning and the like associated with the closure.

Commenter s stated that Florida's ESPS depe nds primarily on load shifting from coal to gas

- fired generation for compliance and most of the reductions are front

- loaded to the 2020

- 2022 time period. The commenter s asserted the shift would result in the premature closing of many coal

fired units, whic h the Federal government through the Fuel Use Act required us to build and add pollution controls. The commenter s noted that FMEA utilities recently added $2 billion of "state of the art" air pollution control systems to coal plants to meet the emission li mits of the CAIR, CSAPR and the Utility MATS (UMATS) rules. The commenter s asserted EPA's proposal does not take into account the hundreds of millions of dollars in stranded costs for those units that must be paid by our consumers if those units are premat urely shut down, and also threatens electric reliability.

Commenter s asserted that application of BB 1 and 2 results in all coal and other steam boiler generation units being completely displaced by redispatch of natural gas at a higher capacity factor th an currently employed in Nevada. The commenter s 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 requirements for these affected units, the capability to burn fuel oil was removed. In addition, the commenter s asserted that a substantial investment has just been completed on each of these units to meet the state's January 1, 2015 BART compliance date. The commenter s stated NV Energy reason ably 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, commenter s stated that the EPA did not a dequately consider other compliance

- related expenditures such as NV Energy's North Valmy Generating Station MATS

- related investments to meet the April 2015 compliance date. The commenter s stated the remaining useful life of these units dictates that to avo id stranded investment in these units and to minimize costs to customers, NV Energy will be required to continue dispatching these units well into the interim compliance period of the CPP.

Commenter s stated that section 111(d) of the CAA requires the EPA t o develop regulations that allow states to consider, among other factors, the remaining useful life of the existing source to which the standard applies. The commenter s stated that while, arguably, the EPA will allow the states to take this aspect into con sideration in their state plans, in applying BB 1 and 2 in the standard

- setting process, the EPA effectively removes this consideration for the states as they struggle to meet the established interim targets with limited options. The commenter s suggested
t hat the EPA specifically add a fifth provision to 40 CFR section 60.5740(11), "supporting material" to include "materials demonstrating the state's analysis of the remaining useful life of388 the existing source to which such standard applies" to address situ ations where affected EGUs have made recent emission control retrofits or have significant remaining book life.

Comment 22: Commenters stated that there is a d isproportionate burden on states with perceived underutilized NGCC capacity.

Response 22: The EPA disagrees. We believe the comments do not apply 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 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 exampl e, 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 B locks 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:

Commenter s stated that while the proposed rule purports 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 period because it assumes Ark ansas it has a relatively large amount of "underutilized" existing NGCC capacity. Based on current fuel prices, the commenter s stated that the proposed rule's concept of "redispatch" from coal to natural gas will cost Arkansas ratepayers an estimated $75 m illion per year. The commenter s added that AECC expects that amount to increase over time as natural gas prices increase in response to higher demand and constrained supply.

The commenter s asserted Arkansas is penalized under the proposed rule because it h as 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 commenter s argued that such a burden on one of the smallest and poorest states in the country will hamper its ability to join in a regional compliance plan, further limiting its ability to offset its disproportionately high 44% compliance burden.

Comment 23: Commenters commented on the c ost an d reliability impacts of redispatch.

Response 23: 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. T he flexibility389 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 many comments, we have modified the proposal and RIA

– the establishment of CO2 emission reduction standards 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:

Commenter s stated that Arkansas has been identified to ac hieve 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 produced at natural gas plants. The commenter s

w ere concerned this increase wi ll result in either significant coal retirements or major reductions in coal utilization, which would result in increased electricity costs and compromised reliability.

Comment 24: Commenters stated that the s ignificant investments required, costs, and timeframe assumed under BB2 are unreasonable.

Response 24: The EPA disagrees. We do not agree with the interpretation of the rule, nor do we believe that the analysis referenced by the commenter 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 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 2020 until 2022), and the ability to shift emission rate achievement between performance periods. In response to additional an alysis and many comments, we have modified the proposal and RIA

– the establishment of CO2 emission reduction standards 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 Miti gation Measures TSD for the CPP Final Rule supporting the final CPP.

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

Commenter s stated that the BB2 requirement to increase the generation of existing NGCC units to a 70% capa city factor and displace generation from existing coal plants in the interim compliance period requires a profound shift in generation in Michigan that will require significant investment in natural gas supply infrastructure that may not be achievable in t he short time leading up to 2020. The commenter s asserted that dialing up capacity from 2012 levels to390 70% would increase NGCC generation in Michigan by 12.2 TWh, a 66% increase in natural gas generation for the state, according to EPA's building block calculations. Concerned about the feasibility and c ost impacts for this, the commenter s 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 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 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 periods. In response to additional analysis and many comments, we have modified the proposal and RIA

– the establishment of CO2 emission reduction standards is regional ly 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 infrastruct ure. 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:

Commenter s 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’ interpretation of the rule . O ur analysis addresses recognizes that different types of EGU’s perform different functions in the market. 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, f or 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 re sponse to additional analysis and many comments, we have modified391 the proposal and RIA

– the establishment of CO2 emission reduction standards is regionally based. The Building Blocks are not prescriptive, and states may consider local circumstances as the y 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 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:

Commenter s asserted that BB2 erroneously assumes that 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 generation and natural gas generation ser ve different functions. Commenters stated f irst, coal generators provide local reliability support, including the ability to restart without any electrical input, voltage stability, and ancillary services. Thus, the commenter s stated, certain coal faciliti es may be "reliability must run" units that cannot be retired without imperiling local grid reliability. For example, the commenter s cited a Western Electricity Coordinating Council study that stated:

The path rating for Path 8 [the Montana to Pacific Nort hwest corridor] is currently highly dependent on remedial action schemes that are directly 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 runnin g studies that dispatch renewable generation before coal

- fired and hydro generation. In reality, the rating on Path 8 may have to be decreased when these conventional resources are backed down, or turned off completely.

Second, the commenter s asserted tha t coal

- fueled EGUs have the ability to stockpile fuel onsite, whereas natural gas units receive their fuel through pipelines vulnerable to disruptions. The
commenter s noted that, according to FERC, during last winter's cold weather, numerous natural
gas ge nerators were forced to cease generation because of interruptions in pipeline deliveries, due to the physical inability of frozen pipelines to deliver natural gas and because suppliers cut off interruptible load to serve other load under much higher spot p rices. The commenter s stated EPA failed to consider these real and negative circumstances in determining that every state's "best" utility system should entail the wholesale substitution of natural gas for coal. The
commenter s added that, based on EIA data , coal prices have historically been low and stable, whereas natural gas prices have been volatile.

Comment 27: Commenters stated that t he EPA modeling does not properly account for transmission

- related constraints and costs.

Response 27: The EPA disagr ees. We recognized transmission related 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 flexibility as to how they structure those plans to achieve the 111(d) requirements. The flexibility incl udes, for example, the choice of approaches, trading, time to develop plans, additional time before the start of the interim performance period39 2 (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 proposal and RIA

– the establishment of CO 2 emission reduction standards 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. Commenter s stated the conclusions reached in the BB2 analysis that suggest Louisiana could, and should, improve its generator efficiency performance, and tha t the IPM assumptions and results simply reflect these efficiency opportunities are inconsonant with conclusions reached in prior LPSC investigations.

The commenter s stated that over the past decade, LPSC has investigated opportunities for better utilizin g 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 generation and ramping down ol der, less efficient natural gas

- fired steam generation, come at a cost of billions in transmission

- related and bulk power sector investments. The commenter s noted that LPSC's investigations were based upon very detailed multi

- area electric generation dispa tch modeling with utility

- specific data and operational input that go well beyond any generalized model like the IPM used in the development of the CPP.

In theory, the commenter s 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 generation are considerable. However, the
commenter s stated that equally important are the possibilities for lowering overall generation costs for Louisiana ratepayers by utilizing more efficient and lower

- cost natural gas based generation.

The commenter s added that while the EPA calculates costs based on the cost of compliance, it did not consider the upgrades in transmission required fo r the increase in NGCC dispatch nor consider the potential for significant stranded costs associated with the reduced production, or premature retirement of Louisiana's existing oil and gas

- fired steam EGUs. The commenter s asserted the midrange estimate for new transmission is $1.0 billion and associated stranded costs

- increased NGCC dispatch and decreased oil/gas steam generation (i.e

., stranded facilities costs) results in a potential mid

- range estimate of $986.4 millio n. According to the commenters, w hen these costs are added to the costs calculated for Building Block 1, the total potential costs eligible for recovery from Louisiana ratepayers increases to almost $3.5 billion.

Comment 28: Commenters stated that there will be h igher than anticipated costs due to transmission issues, natural gas prices and forced closures.

Response 28: The EPA thanks the commenter s

. The EPA believes that the 111(d) final rule provides states with the flexibility to develop plans that consider reliability and local393 circumstances, including infrastructure. 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 analysis, 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 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 a nd 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:

Two commenters stated that costs of BB2 may be higher than anticipated due to transmission issues, increased price of natural gas due to increased demand and forced closure of coal plants. Commenters stated that though NGCCs are not transmission

- constrained in New Mexico, capacity of pipelines and location of NGCC plants relative to electricity demand require further consideration and technical analysis. Commenter s stated that as natural gas demand increases, so will its price, especially in light of anticipated EPA rules addressing methane from oil and gas operations. Commenter s ass erted that reducing usage of coal

- fired EGUs lowers their efficiency and, thus, their cost

- effectiveness, while potentially increasing emissions of ozone precursors. Commenter s believe d this creates pressure for early retirements, raising the risk of stran ded assets and higher costs for electricity consumers.

Comment 29: Commenters noted f actors influencing power decisions

- regulatory/investment risks.

Response 29: The EPA believes that the 111(d) final rule provides states with the flexibility to develop plans that consider reliability and local circumstances, including providing market stability. The EPA reviewed the Lazard analysis for the final Rule. The Building Blocks are not prescriptive, but rather we re used to calculate CO2 emission performance rates. The EPA believes the IPM model to be useful in regulatory analysis, 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 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 Measures TSD for the CPP Final Rule supporting the final CPP.

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

C ommenters noted challenges faced in making energy investments. Commenter s stated that investment risk, price volatility, project size, time to market and sunk capital costs are important concerns in in resource selection, reinforced by the urgency of dealing with t he challenge of climate change. Commenter s stated the Lazard analysis provides estimates for key characteristics394 of deploying various low carbon technologies that have played an important part in the ongoing debate of resource selection, although they have not entered into the EPA analysis. Commenter s asserted that small, quick to market, nimble assets are considered much more attractive investments as they are more flexible and better able to meet small load increases more quickly and would be easier to fi nance. According to commenter s , 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 including assets that have different levels of risk, particularly when the risks are not positively correlated. Commenter s 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 balanc ed. In applying this framework to the evaluation of generation options, the commenter s stated that analysts frequently measure reward as kilowatts per dollar (a measure of economic efficiency), which is the inverse of cost. Commenter s believed that options that move the portfolio toward the efficient frontier should be adopted since they embody lower cost and/or risk.

Commenter s stated that decisions made by utility and independent power producers regarding the need for new generation can take years to deve lop and investments routinely exceed hundreds of millions of dollars, and their life expectancy spans 40

- 50 years. Thus, commenter s stated that investors and financiers look to stable markets/rates and long

- term contracts to minimize risk and justify these large investments. Commenter s believe d one of the greatest risks in recent years is the regulatory risk that puts those investment decisions in jeopardy. For BB2 to succeed, commenter s stated investors need clear, unambiguous signals from EPA that this
pr oposed rule is the last and final rule regarding power plant emissions. Commenter s believe d fuzzy rulemaking commitments and shifting standards hinder any plans to finance new gas

- fired EGUs and that investors are concerned that environmental groups will n ext challenge natural gas. Commenter s urged EPA to provide a clear regulatory framework whereby long

- term capital

intensive decisions can be made.

Comment 30: Commenters stated that c hanging 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 interpretation of the rule, and we believe the commenter’s analysis d oes not reflect the flexibilitie s of 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 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 2020 until 2022), and the ability to shift emission rate achievement betwee n performance periods. 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 Building Blocks are not prescriptive, and states may conside r 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,395 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:

Commenter s 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 commen ter s asserted PROMOD IV accounts for losses and congestion that occur in the grid and the constraints that these impose on the reliable operation of electricity markets, while any model that does not fully account for these factors on a regional and sub

- re gional level, including IPM, would underestimate the impact of the proposed rule. Additionally, the commente rs stated PROMOD IV allows for analysis to be conducted under current conditions and for forward

looking transmission cases to be incorporated into the dispatch algorithm, facilitating long

- and short

- term analysis.

According to the commenter s , PUCO's modeling demonstrates that the switch from economic to environmental dispatch, as a result of BB2, would cause wholesale market energy prices to be 39% higher in calendar year 2025 than prices would be without BB2. T he commenter s provided a graph ( titled: "Wholesale Market Impacts from the Clean Power Plan (based on 2025 projected powerflows and prices)" )

, which shows changes in marginal price per month . The commenter s asserted that BB2 compliance would cost Ohioans approximately $2.5 billion more for electricity in 2025 alone. The commenter s added that, when considering economic impacts beyond the price of electricity, the CPP would impose more strain o n 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 t he CPP's volatility snapshot is inappropriate.

Response 31: The EPA disagrees. We believe that our characterization of volatility is adequate. In response to additional analysis and many comments, we have modified the proposal and RIA See sections Chapter 3 of the GHG Mitigation Measures 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:

Commenter s stated the CPP seems to conflate the concepts of volatility and affordability in its attempt to depict expected p rice increases as within acceptable, normal limits. The commenter s asserted that while, historically, electricity prices exhibit a high degree of volatility, largely due to the volatile nature of fuel costs, it manifests itself in both the upward and downw ard direction. In 2008, according to the commenter s , energy price volatility resulted in significant decreases in end

- user consumer costs. The commenter s asserted that energy prices may be significantly volatile from year to year with no appreciable net tr end either upwards or downwards in consumer costs and believed that conflating the concept of volatility with affordability is insufficient justification of whether the economic implications of the proposed rule are tolerable.396 Comment 32: Commenters stated that there are u nique r edispatch c hallenges for SMMPA and the s tate of Minnesota due to lack of an NGCC in fleet.

Response 32: The EPA disagrees with the commenter’s interpretation of the final rule. The 111(d) final rule requires that states develo p 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, trad ing, 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 com ments, we have modified the proposal and RIA

– the establishment of CO2 emission reduction standards is regionally based. The Building Blocks are not prescriptive, and states may consider local circumstances as they develop their plans, including system re liability, 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:

Commenter s stated that Blocks 2 and 3 will significantly increase costs and impair their ability to provide affordable power to members. The commenter s believe d the assumption that utilities can increase the average utilization of existing and under

- construction NGC C is flawed with respect to SMMPA, as NGCC plants are non

- existent in its fleet. Thus, the commenter s asserted, there is no opportunity for SMMPA to redispatch among its own units under BB 2. If EPA insists on implementing BB 2, the commenter s stated they would have to depend on the purchase of NGCC generation from other utilities, resulting in significant additional costs under PPAs after having already invested millions of dollars in the construction and improvement of Sherco 3.

Comment 33: Commenters st ated that the EPA modeling does not accurately reflect the changing TVA fossil fuel

- fired EGU portfolio.

Response 33: The EPA has updated the database. In response to additional analysis and many comments, we have modified the proposal and RIA

– the estab lishment of CO2 emission reduction standards is regionally based. See section 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 t he final CPP. Commenter s stated that TVA, like most utilities and system operators, operates under least cost dispatch principles

- seeking to meet demand by dispatching lower

- cost generation resources before higher

- cost resources. With regard to energy oversight and rate regulat ion, the commenter s asserted that TVA and Tennessee are unique compared to other states. The commenter s 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

- fired EGU portfolio and past and future commitments made to retire and idle units in the state. The commenter s recommended EPA update its modeling with current data inputs prior to finalizing the guidelines.397 Comment 34: Commenters stated that the m odeling demonstrates that BB2, as proposed, is not

cost

- effective for electric generation.

Response 34: EPA believes the commenter’s analysis does not reflect 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 CPP

, Chapter 3 of the GHG 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:

Commenter s stated comparison of Model Run (b) with Model Run (c) shows that the EGEAS model selects installation of new NGCC capacity instead of operating existing NGCC capacity above a 15% capacity factor in 2020, resulting in new NGCC units operating at over 80%

c apacity factor in comparison to existing NGCC units, 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 commenter s , and encourage construction of new NGCC units that would not otherwise be necessary to meet load. The commenter s concluded that market dynamics of the proposal significantly disadvantages existing NGCC facilitie s, regardless of their emissions level relative to a new NGCC facility.

Comment 35: Commenter s commented on the c ost effectiveness of RPS

. 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 for the CPP Final Rule supporting the final CPP. The RPS in Wisconsin is outside of the scope of the final CPP.

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

Commenter s stated that their preliminary analysis shows that Wisconsin can meet EPA's CO 2 reduction targets by pursuing two compliance options, a 30% by 2030 RPS, or a statewide shift to displace coal with increased dispatch of existing natural gas units. While the 30% RPS will require significant construction of new renewable generation, the commenter s asserted it is cost

competitive with the natural gas fuel switching alternative by 2030 (though actual costs could vary widely depending on many variables that were not tested in this initial analysis). According to the commenter s , the 30% RPS s cenario will also result in highly diversified generation mix that will insulate Wisconsin's utilities and electric ratepayers against volatile fuel prices and potential CO 2 compliance costs.398 Comment 36: Commenter s stated that the c ost of compliance will lead to unit retirements.

Response 36: The EPA disagrees that the commenter’s assessment reflects the 111(d) final rule.

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

Commenter s stated that PJM analysis concludes that it would likely not be able to meet the winter peak requirement if comparable generator outages that occurred in January 2014 were to occur in the winter of 2015/2016 coupled with extremely cold temperatures and exp ected coal plant retirements. If market conditions continue to be depressed, the commenter s stated that generation resources on the margin that are forced to decide between investments to maintain viability or retirement, will choose retirement, further ex acerbating reliability concerns and consumer cost volatility.

Comment 37: Commenters stated that r edispatch causes economic harm and amounts to a ban on coal

- fired generation.

Response 37: The EPA disagrees with the commenter’s assessment of 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 flexibility as to how they structure those plans to achieve the 111(d) requirements. The flexibilit y 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 p eriods. 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 Building Blocks are not prescriptive, and states may consider local circums tances 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 t he 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:

Commenter s stated that the EPA's proposal to re

- dispatch coal

- fired ste am 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 commenter s asserted "environmental dispatch" creates winners (NGCC owners) a nd losers (coal unit owners) without regard to the associated economic harm. The commenter s believe d the rule amounts to a ban on a certain percentage of coal fired generation which is currently in use and operating to serve the country's energy needs.

C omment 38: Commenters commented on the t reatment of the emissions 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.399 The following are summaries of the specific public comments under this comment:

Commenter s recommended that the EPA allow NGCC units under planning and construction that are not subject to section 111(b) of the CAA requirements to emit CO 2 annual emissions reflecting unimpeded operation across their full operating range. The commenter s asserted this sort of unimpeded planning and operation would be allowed if the unit was subject to CAA section 111(b) NSPS requirements and stated that the d ifference between under deployment new NGCC heat rate performance and CAA section 111(b) NSPS affected unit heat rate performance is not significant enough to warrant impeding the operation of these under construction NGCC units. The commenter s suggested t he EPA 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 generating units and represent good CO 2 e mitting 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 transmission constraints and consumer costs

. Response 39: The EPA believes that the 111(d) final rule provides 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 perfo rmance rates. The EPA believes the IPM model to be useful in regulatory analysis, 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 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 fi nal 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:

Commenter s state d 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 commenter s further state d that the feasibility of higher NGCC utilization should be determined by modeling syste m

- wide transmission constraints. Given that the EPA is concerned with consumer costs, the commenter s state d that the EPA should carefully consider how locational marginal prices are affected in order to achieve these higher capacity factors and also says t hat 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 g as turbine peaking generator is limited due to insufficient gas supply and the inability to establish firm pricing

. Response 40: The EPA disagrees. Gas turbine peaking generators are not affected sources.400 The following are summaries of the specific public comments under this comment:

Commenter s stated that as a municipal generator Fremont has very little flexibility. Although the
commenter s said it has a gas turbine peaking generator, there is not adequate gas supply to dispatch that unit in the winter months. Also, because of the limited and unpredictable use of the peaking turbine, Fremont is unable to secure firm pricing for gas which res ults in higher operating costs, the commenter s explained. The commenter s added that fuel switching to natural gas as a fuel instead of coal at today's prices would result in a 40% increase in the cost per MW to generate the power. According to the commente r s , the increase does not count the capital cost 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 could easily exceed $15

- 20 million.

Comment 41: Commenter s sug gested there is an error in the data for Louisiana that calls into questions whether compliance can be met by states in a cost effective manner

. Response 41: The EPA disagrees with the commenter’s interpretation of the rule

– the IPM analyses of the propos al is not prescriptive. In response 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 flexibili ty 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 reliability, fuel diversity, the “useful life” of generation assets, other regulatory requirements 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 and Chapter 3 of the GHG Mitigation Measures TSD for the CPP Final Rule supporting the final CPP, and the Regulatory Impac t Assessment of the final CPP.

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

Commenter s stated that it has identified an inconsistency, in addition to those pointed out by the LDEQ, which casts further doubt on the validity of the assumptions included withi n 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, the commenter s noted that all of the coal or petroleum coke

- fired units in Louisiana, except for Cle co's Dolet Hills Unit 1 and Brame Unit 3, are designated as "Coal Unit Retirement." The commenter s 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 boil ers) to provide a total of 1,150 net MW of coal

- fired generation after 2020. The commenter s also noted that at a 100% capacity factor, these two units could provide only 10,074 GWH of coal

- fired generation; 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 still leaves 11,539 MWh to be served by coal

- fired units

- an amount that would require 1,550 MW of capacity operating at a n 85% capacity factor

- 400 MW more than the EPA spares from retirement. The commenter s stated401 that at the very least, this disconnect must be explained by the EPA, and at worst it calls into question the logic embedded in EPA's models.

Comment 42: Commen ters stated that t he EPA's assumptions substantially overstate the amount of NGCC generation that would be available technically or economically to offset the coal generation the proposal will retire or force off the grid

. Response 42: The EPA disagrees. In response to additional analysis 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 111(d) final rule requires that states develop plans that est ablish 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, trading, time to dev elop 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 consid er 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 ru le preamble of the CPP, Chapter 3 of the GHG Mitigation Measures TSD for the CPP Final Rule supporting the final CPP, and the Regulatory Impa ct Assessment of the final CPP.

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

Com menter s stated that there is no technical or economic evidence that NGCC power plants can sustain generation at a 70 percent capacity factor, as the EPA assumes. The commenter s stated that the EPA's assumption is derived by using an arbitrary $30/ton CO2 p rice (tax) as a reasonable cost a consumer should pay for fuel switching from lower cost coal generation to higher cost sources. The commenter s further stated that the EPA would fundamentally convert the current electric grid from an economic dispatch to a carbon dispatch model. The commenter s asserted that the EPA's assumptions also incorrectly use nameplate capacity rather than net capacity (i.e., the amount of output that can be supplied to system load), and that this error demonstrates a lack of underst anding of how electric utilities plan and operate to meet demand and insure reliability. The commenter s also asserted that as a result of this mistake, NGCC plants in many states will have to run at or well above 80 percent capacity. The commenter s also st ated that the EPA's analysis erroneously indicates that 11 states can replace all of their coal generation capacity with NGCC generation. Further the commenter s stated that the EPA's 2012 baseline inventory includes NGCC units that have been either out of service for several years or retired. The commenter s 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 co mmenter s finally stated that the EPA's assumptions substantially overstate the amount of NGCC generation that would be available technically or economically to offset the coal generation the proposal will retire or force off the grid.402 Comment 43 : Commenters requested that the EPA c larify how natural gas factors into reduction targets when coal plants are retired and transitioned to different gas plants

. Response 43: In response to additional analysis and many comments, we have modified the proposal and RIA. The final rule does not include new NGCC units. See sections V.A and V.D final rule preamble of the CPP, and Chapter 3 of the GHG Mitigation Measures TSD, and Chapter 3 of the Goal Setting TSD for the CPP Final Rule supporting the final CPP for t he EPA’s response to this comment.

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

Commenter s indicated that states like Kentucky, that are almost entirely dependent on coal and do not yet have new gas online, need more clarity on how the CPP addresses a transition in situations where coal plants are retired and transition into new gas. Ideally th e plan will factor both gains from shutting down coal plants and add back in the impacts of new gas when calculating compliance, the commenter s hoped.

Comment 44: Commenters commented on the impacts of the CPP on specific plants in Delaware.

Response 44: The EPA disagrees with the commenter’s interpretation of the rule, and we believe the commenter’s analysis does not reflect the flexibilities of 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 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 be fore 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 proposal and RIA

– the establishment of CO2 emission reduction standards 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” o f 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, Chapter 3 of the GHG Mitigation Measures TSD for the CPP Final Rule supporting the final CPP, and the Regulatory Impac t Assessment of the final CPP.

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

The commenter s stated that, for the Calpine Hay Road facility, the CPP would require increasing generation by 42 percent of the plant's capacity factor from 50 to 70 percent. The commenter s explained that these increases do not match the EPA's goal for a national averag e of 51 percent by 2030, and that the plant recently dropped its capacity factor to 43 percent in 2013 due to the limited natural gas supply in winter months. Regarding the NRG Indian River plant, Commenter s remarked that the CPP would require reducing gen eration 13 percent and reducing the capacity factor to 34 percent. The commenter s explained that the EPA is expecting coal

- fired403 power plants to hit a national average capacity factor of 73 percent by 2030, but the Indian River facility is currently tied f or the cleanest coal

- fired power plant in the country. The commenter s questioned why the EPA would want this facility to run at half the capacity factor of the national average. Finally, c ommenter s stated that the CPP did not account for a new power plant in Dover being constructed by Calpine and did not include emissions or power production for two small power plants in Dover.

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 and volatility.

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

Comment 1: Comment ers described w hy price volatility in natural gas due to the increase in demand by the power sector is not a concern

. Response 1: The EPA agrees to the extent that natural gas supplies are sufficient and increasing. The EPA believes that the 111(d) final rule provides 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 performance rates. 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 Measures TSD for the CPP Final Rule supporting the final CPP

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

Commenter s rejected claims that increased use of natural gas in the power sector will increase natural gas price volatility. Commenter s specifically rejected claims that natural gas is inherently volatile and should not be increasingly relied upon for power generation. Commenter s stated that none of the root causes of volatility would be exacerbated by increased use of gas in the power sector. Commenter s stated that natural gas producers and pipeline companies have invested heavily to enhance gas deliv erability and mitigate supply shocks.

Commenter s stated that concerns that increased natural gas demand "could add upward pressure on natural gas prices" are unwarranted. Commenter s referred to Figure 8, Henry Hub Natural Gas Price (2011$/MMBTU), which shows a range of different price forecasts relative to EIA's outlook since 2009. Commenter s stated that, as the EPA notes in the RIA, "current and projected404 natural gas prices are cons iderably lower than the prices observed over the past decade." Commenter s stated that recent EIA projections support continued growth in natural gas supply, and natural gas pipelines and infrastructure have the capacity to support this growth and quickly

r amp up production as needed. Commenter s 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. Commenter s stat ed that a stable and abundant supply of natural gas will provide for markets, making natural gas an attractive option for power generation, transportation, industrial and residential uses.

Commenter s stated that natural gas price volatility is defined as " sustained, unpredictable price movements" that cause uncertainty for both users and producers of natural gas. Commenter s stated that expected seasonal price fluctuations (e.g., due to greater demand for heating) do not constitute "volatility" in the proper use of the term. Commenter s stated that, apart from localized price impacts experienced in the Northeast during the polar vortex as a result of regional pipeline constraints, since 2000, the U.S. has experienced three noteworthy periods of price volatilit y: (1) the California energy crisis in 2000

- 2001; (2) the hurricanes of 2005; and (3) the price spike in 2008. Commenter s stated each of these events provided a different lesson in potential causes of price volatility: deliverability issues, supply shocks, and erratic market behavior. Commenter s stated that, in each case, as described below, circumstances have changed such that similar events, if they occurred today, would not lead to similar 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. This behavior significantly hindered "deliverability"

- the ability of suppliers to meet natural gas demand. As described previously in this section, deliverability of gas throughout the U.S. has improved markedly since 2000, with over 150 Bcf/d of pipeline capacity added from 2001 to 2011. The industry has continued to invest in additional pipeline
capa city, adding 2,400 miles in 2011 alone. A robust 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 deliverability problems.

• In the second period o f price volatility, extreme weather 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 Mexico. The price volatility caused by Hurricane Katrina is indica tive of a supply problem that bears no resemblance to the supply impact of potential expanded power sector demand. Long lead times for compliance with the proposed greenhouse gas regulations will give the market several years to anticipate the demand incre ase. With a hurricane, the market has only days to react. In addition, were another hurricane or major weather event to occur, we would expect very different fuel supply response. Increasing onshore unconventional natural gas production in diverse geograph ic locations combined with significant infrastructure investment to move that gas to markets has resulted in diversified supplies and redundancy in the system that would minimize the impact of regional weather events.405 • During the third period, a natural gas price rise followed general global commodity price inflation. Prices rose steeply in everything 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 expe ctation on the part of commodity traders that natural gas and oil prices were inextricably linked. But in the ensuing years, natural gas and oil prices in the U.S. have definitively decoupled from one another. The narrowing of the correlation range as show n 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 sharp increase in the price of oil

wou ld not have the same impact on the price of natural gas as it would have had historically.

Commenter s stated that, outside of these three anomalous events, prices in the period from 2000 to 2010 were relatively stable, and considering the mitigating factor s discussed above, there is nothing to suggest that increased use of natural gas in the power sector would cause a market disruption similar to these episodes. Commenter s stated this confirms that natural gas will remain a stable, reliable fuel source such that it is appropriate to rely increasingly on the fuel for power generation.

Commenter s stated that, in addition to the changes to deliverability and market pricing, production from shale formations distributed throughout the U.S. has fundamentally chang ed the industry's ability to respond to price signals. Commenter s stated that, in conventional production, higher prices drive producers to increase exploration, but the link and timing to actual production is lagged and imperfect. Commenter s stated produc tion from shale formations reduces exploration risk significantly, and allows producers to increase production far more responsively. Commenter s stated that, given the size of the technically recoverable resources in the U.S., producers will be able to respond quickly to market signals in order to meet increasing demand. Commenter s stated that, with the ability to react efficiently to price signal s, production volumes should further significantly reduce the risk of sustained, unpredictable price movements. Commenter s stated this is a major benefit of the size of the technically recoverable total natural gas resource base. Commenter s stated the rapi d replenishment of natural gas storage levels this past injection season is a perfect, real

- world example of how quickly producers are able to respond to market needs. Commenter s stated the 2013

- 2014 winter was severe and the rare, 1

- in

30 winter caused na tural gas storage volumes to be depleted to levels not seen since 2003. Commenter s stated that, due to significant production increases from natural gas producers, storage injections set weekly records throughout the injection season; the April 1 to Octobe r 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 natural gas prices and/or price volatility.

Response 2: The E PA disagrees with the commenter s ’ interpretation of the rul e, and we believe the commenters’ analyse s do not reflect the flexibilities of the final rule. The rule does not require specific EGUs to take specific actions , and we believe our analysis to be appropriate

. The406 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) requi rements. 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 achievemen t between performance periods. 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 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 f inal 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:

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 consumers and energy intensive industries will bear the brunt of these gas price increases.

Commenter s referenced a July 2010 APPA report and stated that if we fully implement this building block, it would double the amount of natural gas used in power production, which would necessitate increasing gas production from all sources in the market by 33%. Com menter s stated such an increase may be possible but would certainly have profound effect on market pricing and supply distribution as well as general competition for supply.

Commenter s stated the EPA failed to fully account for impacts to fuel price

- stabil ity in the evaluation of impacts resulting from removing coal generation from the generating portfolio mix. Commenter s stated that, due to the shift in the generating portfolio mix resulting from the proposed rule, delivered electricity costs will increase by between 12% and 17% between 2017 and 2031. Commenter s stated this increase in the costs of electricity would have a direct effect on NvMA's members, for whom electricity is already a substantial cost.

Commenter s stated that one example of risk associa ted 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. Commenter s stated spot market pricing is vol atile and usually higher than long term contract pricing.

Commenters claimed that the proposed rule will affect PUCs' statutorily

- defined rate

- setting and resource planning objectives. Commenters stated that EPA's application of its interpretation of its authority under Section 111(d) of the Act will likely force existing source retirements and the redistribution of electric generation from higher emitting, more affordable supply

- side sources to lower emitting, high cost supply

- side sources, which the comm enters believed will result in increased public utility rates and changes to utility resource plans.407 Commenters claimed that the proposed rule will affect PUCs' statutorily

- defined rate

- setting and resource planning objectives. Commenters stated that EPA's application of its interpretation of its authority under Section 111(d) of the Act will likely force existing source retirements and the redistribution of electric generation from higher emitting, more affordable supply

- side sources to lower emitting, hig h cost supply

- side sources, which the commenters believed will result in increased public utility rates and changes to utility resource plans.

Price volatility

Commenters expressed concern that the EPA's proposal for increasing the dispatch of natural gas combined cycle units will lead decreased diversity in electric generation and to high price volatility.

Commenter s expressed concern that the phasing out of older coal

- fired power plants by increasing electricity generation at natural gas

- fired power plan ts will increase historically volatile fuel prices.

Commenter s stated that such an unbalanced generation mix leaves Florida extremely vulnerable to natural gas price volatility and supply constraints. Commenter s , citing a November 2014 NERC report, stated that with greater reliance on natural

- gas

- fired generation, the resiliency and fuel diversification that is currently built into the electric system may be degraded.

Commenter s stated that EPA's proposal to increase the dispatch of natural gas combined

- cycle (NGCC) units up to 70%, with corresponding reductions in the output of coal plants, would expose consumers and energy

- sensitive industries to highly volatile electric prices . Commenter s stated that, without a diverse electric generation portfolio, sustained cold weather events such as those experienced in past winters could lead to natural gas supply disruptions that could compromise the electric system and could have serious adverse repercussions for energy security and electric reliability. Commenter s recommended that 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

.

Commenter s stated that Building Block 2 ignores the importance of portfolio diversity. Commenter s stated the retirement of coal

- fired EGUs places more emphasis on NGCC EGUs, thereby limiting portfolio diversity and creating significant vulnerability to n atural gas price fluctuations. Commenter s stated that natural gas prices have seen significant variability over time and provided a Chart 3 which shows natural gas price volatility from 1990 to 2012. Due to the historic price volatility, the commenter s sta ted it important to maintain portfolio diversity in order to minimize cost volatility to ratepayers. Commenter s stated that, while recently the United States has enjoyed low natural gas prices, those prices are likely to rise in the face of increased
compe tition for supply due to nationwide increased utilization of existing NGCC EGUs and construction of new NGCC EGUs. Commenter s stated that additional environmental regulation may also cause natural gas prices to rise.

Commenter s stated that, because the nat ural gas market 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 be408 particularly tru e upon the implementation of EPA's Proposed Rule, which would drastically increase the demand for natural gas, despite EPA's cursory statement otherwise.

Commenter s stated that, historically, natural gas prices are highly volatile and increased use of
natu ral gas for electricity generation is constrained by transmission capacity, particularly in the U.S. Northeast. Commenter s stated that, while the economics for increased natural gas generation are favorable presently, the history of natural gas prices in t he 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, commenter s stated the EPA is only increasing the likelihood of potential steep natural gas price increases that would be passed on to ratepayers across the country as higher electricity prices. Commenter s 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
p rices.

Commenter s 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. Commenter s stated the MISO has co nducted an economic

- only analysis that has estimated that in its region alone, the EPA proposal will cause the retirement of an additional 14 GW of coal units within the MISO footprint. While natural gas is likely to be substituted for lost inexpensive coa l resources, there will be a rush to gas as utilities and merchants scramble to fill the void with NGCC resources.

Commenter s expressed concern that the cost of spot energy can be difficult to control, especially during inclement weather. Commenter s noted that, during last year's polar vortex Hoosier Energy was subject to natural gas constraints and could 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.

Com menter s expressed concern that, while the recent natural gas renaissance has provided a stable and relatively clean fuel source, history shows the price and availability of natural gas to be extremely volatile over time. Commenter s noted that last spring d uring the polar vortex event, many municipal gas plants were called upon to generate but could not do so due to the unavailability of natural gas supply due to supply deficiencies and pipeline constraints.

Commenter s expressed concerned that natural gas is subject to substantial price fluctuations that create market uncertainty. Commenter s suggested the EPA should consider the consequences of using a price

- volatile fuel such as natural gas to meet our needs year

- round. Commenter s stated that renewable energ y is a more price

- stable form of electricity generation. Commenter s stated that natural gas is more price volatile than renewable energy or coal power generation, and is particularly susceptible to spiking during cold weather.

Commenter s stated that, whil e the EPA assumes natural gas prices will remain low and supplies high, the natural gas market is becoming increasingly volatile. Commenter s suggested the EPA lower the NGCC capacity factor to a more realistic goal.

Commenter s 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 adequacy409 requirements in PJM. Commenter s contended that PJM's existing coal fleet may not b e able to provide adequate flexible operations as most existing coal plants were not originally designed for load following and/or extended low output generation. Commenter s are also concerned that establishing a dispatch

- based mitigation goal that impacts other existing generation types without thorough consideration of the impacts to resource adequacy may significantly degrade reliability. Commenter s stated this concern is best exemplified by the experiences in the PJM region during the January 2014 polar vortex event, when a significant percentage of PJM's entire generation portfolio was out of service during that period which included 9,700 MW of gas generation (36% of PJM's total gas generation capacity) due to plant outages and gas supply disruption. C ommenter s stated that, despite these challenging conditions, PJM's robust generation portfolio was able to weather the period without major service outages. Commenter s stated they are concerned that, under a future scenario where the EPA's BB1 and BB2 prop osals have restructured the PJM generation portfolio, there may be significant declines in resource adequacy, reserve margins and less overall flexibility to manage an extreme cold weather event.

Commenter s did not agree that natural gas prices will remain relatively flat through 2030. Commenter s stated that, historically, natural gas prices have been volatile due to federal policies limiting the use of gas, imbalances between supply and demand, and infrastructure issues, among other issues. Commenter s prov ided Figure 4 showing the volatility of natural gas as compared to coal since the late 1990's. Commenter s stated the proposed rule would expose OMU's ratepayers to significantly more natural gas price risk. Commenter s stated the impact of natural gas price volatility was recently demonstrated during the Polar Vortex of 2014. Commenter s 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 30% higher than nor mal. Commenter s 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."

Commenter s stated the move to a greater dependence on natural gas places Florida and the City's el ectric grid at a greater risk to price spikes, due to the volatility of natural gas, or inability to meet demand if there is a significant curtailment of natural gas within the state, region or country (similar to that experienced by Florida and other regi ons during the oil embargos of the 1970's).

Commenter s stated that, as building block 2 is employed to displace coal, electric power and its consumers will be subject to large swings in fuel pricing. Commenter s stated TVA passes along all fuel costs used i n the production of electricity 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. Commenter s stated that natural gas pr ice volatility, in stark contrast to coal price stability, will be experienced by consumers every month through the fuel cost adjustment mechanism as the result of the proposed rule's building block 2. Commenter s referred to EIA data comparing the price fl uctuation between natural gas and coal and stated the price volatility of natural gas stands in stark contrast to coal's historically stable price. Commenter s stated this natural gas volatility continues in spite of growing natural gas production.

Comment er s expressed concern that increased use of natural gas nationally could lead to increased market dislocations, such those as seen in the winter of 2013

- 2014, as well as overall increasing prices and price volatility due to higher gas demand. Commenter s st ated that,410 depending on the magnitude of these Issues, there could be implications for maintaining reliable natural gas supply in the ERCOT region for electric generation in the future.

Comment 3: Commenter s stated that the increased reliance on natural gas that is associated with a 70 percent NGCC generation utilization rate in the CPP ignores the economic realities of procuring natural gas, as well as the physical challenges of fuel delivery to NGCC units.

Response 3: The EPA disagrees with the commenter’s interpretation 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 establish emiss ion standards for affected EGUs, but it not require that specific plants achieve specific capacity factors. We are providing states with substantial flexibility as to how they structure those plans to achieve the 111(d) requirements. The flexibility includ es, 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 many comments, we have modified the proposal and RIA

– the establishment of CO2 emission reduction standards is regionally based. The Building Blocks are not prescriptive, and states may consider local circumstances a s 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 a nd 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:

Commenter s stated that firm fuel arrangements and spot market natural gas procurement can be volatile and costly. Commenter s provided the following additional points:

The CPP is devoid of any analysis discussing the economic 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 standard due to their exorbit ant costs and practical difficulties. Natural gas suppliers are generally betrothed first to natural gas distribution utilities and their consumers regarding the delivery of fuel. Electric generators take a subordinate role to gas utilities even if the gen erator has a firm fuel contract. NGCC units that do not have firm fuel arrangements rely on the spot market to acquire fuel. This spot market can be volatile, especially during periods of high demand. This scenario presented itself during the polar vortex this past winter. Natural gas units that did not go offline during the polar vortex were required to purchase fuel at high spot prices during the month of January, resulting in a record setting amount of uplift payments in excess of $650 million in the PJ M footprint.

Comment 4: Some c ommenter s focused mainly on fossil portfolio diversity, while other s insist ed that portfolio diversity is critical

.411 Response 4: The EPA believes that the 111(d) final rule provides states with the flexibility to develop plans that consider reliability and local circumstances

. 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:

Commenter s stated the portfolio diversity of the 21st century must be a combination of renewable energy generation and d emand

- side resources including efficiency, demand response, storage, etc. Commenter s stated that actual diversity provides essential economic and reliability certainty that cannot be achieved through fossil fuel means alone.

Comment 5: Commenters suggested the CPP must maintain fuel diversity to minimize cost.

Response 5: The E PA disagrees with the commenter s ’ interpretation of the rul e, and we believe the commenters’ analyse s do not reflect the flexibilities of the final rule. 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, t he 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 add itional analysis and many comments, we have modified the proposal and RIA

– the establishment of CO2 emission reduction standards is regionally based. The Building Blocks are not prescriptive, and states may consider local circumstances as they develop the ir 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 th e GHG Mitigation Measures TSD for the CPP Final Rule supporting the final CPP, and the Regulatory Impa ct Assessment of the final CPP.

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

Commenter s stated the EPA's proposal to increase the 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 unregulated states, and would expose consumers and energy

- sensitive industries to highly volatile electric prices. Commenter s stated that, while West Virginia does not have natural gas combined

- cycle units, the impact of this building block on other states would lead to reductions of West Vir ginia's coal and electricity exports to other
states.

Commenter s stated that fuel diversity ensures competition and lower prices. Commenter s stated that, when demand increases throughout the US, in all industrial sectors, not just the utility sector, highe r gas prices will result in increased prices for electric power. Commenter s noted that EIA projects that the RFC region, which includes Ohio, confronts one of the highest growth412 demands for natural gas as utilities shift from coal. Commenter s stated that i t 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 price

- not to mention the specter of additional environmental and drilling regulations, whic h could have a serious impact on future production and price levels.

Commenter s stated that the lack of fuel diversity would negatively impact on cost. Commenter s stated that, by increasing reliance on natural gas, the proposed rule creates a market in whi ch many participants want the same product which will likely increase the price demanded. Commenter s stated the upper Midwest relies heavily on natural gas for winter heating, and it is also used in industrial processes such as ethanol production. Comment er s 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 nation have enjoyed in recent years. Commenter s stated that natural gas contra cts to fuel natural gas

- 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 providers to negotiate for higher p rices each time contracts are discussed for renewal.

Commenter s stated that mandating a 70 percent capacity factor will erode the system's ability to optimize around economics and ultimately drive up system costs for Southern Company customers because pre viously Southern Company has utilized its ability to dispatch its generation fleet to reliably serve customers in the lowest cost manner. Commenter s stressed the danger of disregarding the uncertainty of future fuel prices and the potential benefits of uti lizing a variety of fuels to mitigate those uncertainties. Commenter s indicated that Southern Company is dedicated to providing a diverse electricity generation portfolio to the benefit of approximately 4.4 million customers in the Southeast, nearly half o f whom earn less than $40,000 per year. According to the commenter s , in 2012, across the Southern Company system, fuel costs were reduced by over $1 billion by leveraging a diverse fuel mix to the benefit of its customers. 246 Commenter s added that while natural gas has been relatively 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 electricity supply when natural g as prices fluctuate. Commenter s stated that history, especially recent events 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 increasing its reliance on coal.

Commenter s stated that it is in the national interest for utilities to have the opportunity to maintain generation fleet divers ity in order to hedge against fuel price fluctuations, and thereby protect customers. Commenter s indicated that for decades available coal generation has mitigated against natural gas price increases and vice versa

- the wide pendulum swing of fuel
costs c an only be damped by maintaining a diverse portfolio of generation assets. Commenter s asserted that for Southern Company, a balanced generation portfolio is not merely an objective

- it is an obligation that comes with the Company's duty to serve its custo mers.

Commenter s 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 ana lysis showed that natural gas413 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 only 18 percent from coal, but under a higher natural gas price scenario, the comp any would minimize costs for its customers by generating only 28 percent from natural gas and 40 percent from coal. Commenter s indicated that the EPA's proposal would prevent utilities from continuing to develop a fleet that relies on diverse fuel mixes fo r the benefit of their customers. Commenter s provided a table depicting Southern Company's historical generation mix in terms of the percent contribution to total power generation by coal, gas, nuclear, and hydro/other over the time period of 2007 through September 2014.

Commenter s provided an example which c ommenter s characterized 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 Company's cust omers: Mississippi Power and Gulf Power's Plant Daniel Plant which consists of four generating 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 Units 3 and 4 approximately 486 MW (net summer capacity). Commenter s provided a figure showing the capacity factors for Plant Daniel's four units over the period of 2002 to 2013. According to the commenter s , the EPA's proposed rule would turn this historic trend on its head, mandating 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 burden of generation.

Comment 6: Commenters indicated that increased demand for natural gas will likely increase prices, thus raising costs for customers.

Response 6: The E PA disagrees with the commenter s ’ interpretation of the rule, and we believe the commenters’ analyse s do not reflect the final rule. We believe our analysis of natural gas prices 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, 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 many comments, we have modified the proposal and RIA

– the establishment of CO2 emission reduction standards is regionally based. The Bui lding 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, and the Regulatory Impact Assessment of the fi nal CPP.

The following are summaries of the specific public comments under this comment:414 Commenter s stated the costs of natural gas have historically been extremely volatile and, with the increase in the demand for gas nationally, are expected to increase. Commenter s stated the EPA has not adequately addressed the potential increase in the cost of compliance which is tied to the future price of natural gas.

Commenter s stated that increases in natural gas demand resulting from implementation of the Clean Power Plan are likely to raise gas prices and overall consumer prices nationally and in Arizona. Commenter s stated the EPA Building Block scenario would require a wholesale retirement of the coal capacity in Arizona, shifting the cost of fuel for ratepayers from coal to more expensive natural gas. Commenter s stated the impact of additional gas demand required for compliance would come at a time when exports (liquefied natural gas and pipeline exports to Mexico) are also growing rapidly. Commenter s referred to a study by Pace Global.

• Pace Global estimated costs of both fuel and purchased power for electric ratepayers in the Arizona Glide Path scenario and the EPA Building Block scenario. Commenter s stated that, noting the uncertainty associated with the long

term impacts t o 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. Commenter s referenced their Exhibit 22, which compares t hese costs, and stated the analysis shows that the current building block plan would cost electric ratepayers 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 time.

• Pace Global estimates that all other things constant, power sector consumption could increase from approximately 24 Bcf/d in 2015 to 47 Bcf/d by 2030 under the EPA Building Block scenario. Commenter s stated that Pace Global estimates that this incremental increase in national consumption levels would result in price increases nationally at the Henry Hub pricing point. When compared to a reference case outlook of Henry Hub pricing, commenter s stated the price increase under the Clean Power Plan i s 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. Commenter s noted Henry Hub pricing projections for the reference case and the EPA Building Bock scenarios are presented in Exhibit 24.

Comm enter s stated that natural gas utilities would be negatively affected by the Proposal. Commenter s stated that UNSG customers would be impacted by higher costs of service driven by a combination of higher gas commodity costs, transportation price increases, and storage development costs and provided the following additional information:

• The impact of gas commodity price increases alone, assuming an average increase in Henry Hub pricing of $1.35/MMBtu (PACE Global Assessment, Appendix B) between 2020 and 2030 , would be $18 million annually, totaling $200 million for 2020 through 2030.

• Transportation costs for UNSG customers would increase on an explicit basis, as well as from implied risk. Explicitly, the costs for transportation would increase415 as market dema nd 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 system expansion across all their users. Therefore, UNSG customers will bear the costs of recovery of new pipeline construction, even though their own demand is not expected to materially increase.

• Increased demand for transportation capacity will increase the bid price for available capacity. In addition to bidding higher ra tes for capacity, utilities and other system users also will be required to bid longer 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 duration ex pose utilities and other system users to additional risk due to unforeseeable future conditions.

• Commenter s 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 ensure reliability. When combined, these increases in commodity costs, transportation costs, and storage costs will increase both electric and gas ra tes for UNSG customers.

Comment 7 : Commenter s stated the EPA underestimated not only how much the proposed rule will raise electricity prices, but natural gas prices as well.

Response 7: The EPA disagrees. The analysis cited by the commenter does not reflect the final rule. The 111(d) final rule requires that states develop plans that establish emission standards for affected EGUs, and states may consider local circumstances as they develo p 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 r esult 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 Fina l Rule supporting the final CPP, and the Regulatory Imp act Assessment of the final CPP.

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

Commenter s referenced an EVA study (EVA, Energy Market 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 large part due to an almost 135% increase in the wholesale price of natural gas (100% in real dollars), from $2.82/mmbtu in 2012 to approximately $6.60/mmbtu ($5.63) in 2020" ; (2) these increases are due to baseline market and policy impacts between 2012 and 2020 as well as significantly increased pressure on gas prices resulting from recent EPA regulations on the power sector as well as the proposed rule; (3) America's indust rial sector would be hit the hardest, seeing their electricity and gas costs soar416 64% by 2020 over 2012 costs; and (4) the study notes that skyrocketing "operational costs in the industrial sector are of particular concern for energy intensive industries i n the U.S. such as aluminum, steel and chemicals manufacturing, which require low energy prices to compete."

Comment 8: Commenters generally stated the EPA's proposal would lead to significant increases in the cost of natural gas leading to severe economic impacts and that EPA has not adequately addressed infrastructure costs.

Response 8: The E PA disagrees with the commenter s ’ interpretation 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 emiss ion 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 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 proposal and RIA

– the establishment of CO2 emission reduction standards 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, t he “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 preamble of the CPP, Chapter 3 of the GHG Mitigation Measure s TSD for the CPP Final Rule supporting the final CPP, and the Regulatory Impac t Assessment of the final CPP.

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

Commenter s stated the EPA's proposal for increasing the use of na tural gas combined

- cycle units, in addition to 40 gigawatts of new natural gas combined

- cycle capacity that the EPA projects to come online form 2020 to 2030, will lead to significant increases in natural gas prices, well above the EPA's projections. Comme nter s 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. Commenter s stated their area has already seen increased costs due to renewable standards and mass associated plant closures. Commenter s stated their communities and consumers cannot afford another round of EPA

- related plant closures.

Commenter s stated the EPA's proposal would lead to a significant increase in the cost of natural
gas for both electricity generators and other consumers. Commenter s stated that the EPA's own projections demonstrate that this cost increase would be especially severe in the near term. Commenter s stated these increased costs will make it more difficult for companies to maintain low prices, more difficult for some families to make ends meet, and will lead to significant job losses in industries that are sensitive to the price of natural gas. Commenter s stated these impacts, in combination with the up to 49 gi gawatts of additional coal retirements that EPA417 projects by 2020 (Regulatory Impact Analysis at 3

- 32), could deal a severe blow to American workers.

Commenter s noted that the EPA projects that the Clean Power Plan will lead to further increases in delivere d natural gas prices of 7.5% to 11.5% in 2020 (CPP RIA, June 2014). Commenter s 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 Clea n Power Plan. Commenter s stated that the Henry Hub wellhead prices are a key determinant of future electricity prices. Commenter s stated the EPA's CPP will substantially increase electric prices for America's 65+ households. Commenter s stated the additiona l baseload generation capacity projected to retire due to the Clean Power Plan would increase the risks of brownouts, load curtailments, and other power disruptions in regions impacted by these retirements. Commenter s stated the existing EPA rules are alre ady driving up the costs of natural gas and electricity prices and the new proposal will add even more unacceptable costs.

Commenter s stated MRES expects future demand for transmission expansion to be great under the Clean Power Plan. Commenter s stated the time and money associated with expanding the natural gas infrastructure needed to fuel these expansions is beyond substantial, and has the potential to cripple the U.S. economy and put basic electricity service beyond the reach of the poorest A mericans. Commenter s stated the EPA has not included in its cost estimates the expense to build this essential infrastructure, and is a major shortcoming of its economic analysis.

Commenter s stated the proposed rule does not properly account for infrastru cture from either a timing or a cost perspective. Commenter s stated the costs of this shift in generation toward NGCC would require an unprecedented investment in infrastructure, including construction of new NGCC capacity, natural gas pipelines, and trans mission infrastructure. Commenter s stated that any new infrastructure project that would deliver electricity to northern Nevada is complicated by the predominance of federal lands; any such project would require lengthy National Environmental Policy Act an alyses and could trigger review under the Endangered Species Act.

Commenter s expressed concern that that prices of natural gas are projected to increase significantly, and this could affect millions of low

- income households where energy bills represent 10 percent or more of income. Commenter s 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 dollars), between 2012 and 2030 in th e reference case. Commenter s stated a Clean Power Plan that does 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 much less im pact on low

- income households than the draft CPP. Commenter s stated the trajectory proposed by the CPP is about the same as the natural gas reference case in EIA AEO 2014 (Table 13). Commenter s stated the price increases estimated there would cause signifi cant hardship to low

- income households, especially those using natural gas for heating, which is the case for about half of U.S. households. Commenter s stated the EIA estimates that residential natural gas prices will increase by almost 30 percent between 2012 and 2030, which could be devastating for low income households especially if the median household income continues the downward trend it has exhibited since418 about 2006. Commenter s stated increased use of natural 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 additional natural gas supply and pricing analysis including different model years and state

- specific analyses

. 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. I n response to additional analysis and many comments, we have modified the proposal and RIA. States may consider local circumstances as they develop their plans, including system reliability, fuel diversity, the “useful life” of generation assets, other reg ulatory requirements, competing demands for natural gas, 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 f inal CPP, and the Regulatory Impact Assessment of the final CPP.

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

Commenter s stated that natural gas is a globally traded commodity and the price will eventually more closely r eflect the global prices. Commenter s stated that 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 much higher based on global demand . Commenter s asked whether the EPA and Department of Energy (DOE) along with the Federal Energy Regulatory Commission (FERC) adequately modeled natural gas price scenarios given this likely market change?

Commenter s stated the 2012 model year does not take into consideration variations in natural gas prices and how states will dispatch NGCC units economically. Commenter s suggested the following analyses are needed: (1) natural gas pricing 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 each sta te 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 economic dispatch by states to facilitate the NGCC generation required to m eet emission targets.

Commenter s stated the EPA should evaluate any variance in natural gas supply or pricing under this proposal. Commenter s stated this variable needs to be explored through sensitivity analysis and reporting of potential costs. Commenter s noted that it has been well understood and documented within the electric power sector that natural gas supply and prices play a pivotal role in determining both the current and projected future electricity mix, as well as electricity costs. Commenter s s tated that the EIA, whom EPA relies upon for a number of key data points, routinely produces alternative scenarios in its Annual Energy Outlook to examine some of these alternative futures given the importance.419 Commenter s stated the EPA should conduct a t horough 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. Commenter s stated proposed rule will greatly increase demand for natural gas, creating upward press ure on prices and operating costs. Commenter s stated the EPA's modeling shows spot prices increasing by an average of no more than ten percent over the 2020

- 2029 period (79 FR 34865). This projected increase in gas prices is a major contributor to the incr ease in wholesale electricity prices EPA and others anticipate taking place as a result of the proposed rule. Commenter s stated the EPA views these projected impacts as not unreasonable because the price increases in question are well within the range of h istorical natural gas price variability (79 FR 34865). Commenter s stated that the fact that harmful increases in the wholesale price of natural gas have occurred before is of little comfort to the Indiana consumers who will bear the brunt of EPA's proposed rule. Commenter s referred to 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. November 2013. http://www.in.gov/iurc/files/Natural_ Gas)_Market_Study.pdf.):

From the customer perspective, the commodity price accounts for approximately 62 percent of the average residential bill in Indiana, with the remainder stemming from costs associated with the distribution system and trackers. Since the cost of procuring the natural gas in the open market is passed directly to the customer in the captive 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. T hus, 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 consumed. To put this in perspective, consider a customer who consumes 200 therms in a month (10 therms equal one mmBtu). For every $1/mmBtu change in the natural gas price, the customer's bill will change by $20.

Comment 10: Commenters stated the EPA needs to take several issues related to natural gas price volatility into account, adjust its assumptions, 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, infrastructur e 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 ci rcumstances as they develop their plans, including system reliability, fuel diversity, the possibility of extreme events, the “useful life” of generation assets, other regulatory requirements, competing demands for natural gas, and infrastructure. See sect ions 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, and the Regulatory Impa ct Assessment of the final CPP.

The following are summaries of the specific public comments under this comment:420 Commenter s stated this volatility has impacted not only the prices utilities pay for natural gas, but also the wholesale price of electricity. Commenter s cited several reported prices including above $200 per megawatt hour (MWh) during a brief cold spell in mid

- Dece mber 2013 and up to $237.75/MWh during the early January 2014 freeze, and stated that it is very likely further price spikes will occur as the demand for natural gas increases for electric generation. Commenter s stated that the polar vortex highlights the difficult economic reality NGCC units face when purchasing fuel: this economic reality is passed through to consumers, creating yet another unquantifiable, but potentially massive rate increase as a result of the CPP and impacting reliability as stated by NERC.

Commenter s stated the EPA needs to take several issues related to NG price volatility into account, adjust its assumptions, and then modify the states' emission reduction goals accordingly. Commenter s listed several factors that could put upward pre ssure on natural gas prices, including federal policies, short

- term imbalances between supply and demand, the availability of necessary infrastructure, and the potential for increased demand for gas by the transportation sector. Commenter s referenced a 201 0 study (APPA Natural Gas 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. Commenter s stated that EPA's Proposed Rule assumes that prices will remain relat ively flat, but nothing in the Proposal or Technical Supporting Documents addresses the question of whether shale gas production can actually occur at the levels needed to keep prices flat.

Commenter s stated that the Proposed Rule does not take into accou nt the fact that some natural gas supplies come from Canada and suggested that the EPA should consider how increased demand for Canadian natural gas could put upward pressure 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 their CO2 emissions.

Commenter s cited a July 15, 2010 Navigant Consulting paper on price instability in the U.S. Natural Gas Industry which concludes tha t "the vitality of and responsiveness of the supply

demand balance is the most important factor determining whether price volatility in either direction will occur." Commenter s stated that, while current natural gas supply is ample and prices are relativel y low, they are concerned this may not remain the case prospectively and, therefore request the Agency to ensure that its analysis of long

- term natural gas prices and the corresponding impact on future electricity prices takes into account historic natural gas volatility and the potential for future volatility. Commenter s 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.

Commenter s stated that the Proposed Rule does not factor 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 demand increases. Commenter s stated that the EPA needs to examine the com bined impact of greater use of natural gas for electric generation and manufacturing on supply and prices.

Commenter s 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 fixed421 price contracts; however, when situations arise such 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. Comm enter s stated the impact of this affects the users of natural gas as well as the price of electricity generated using natural gas.

Commenter s urged the EPA to more closely examine the complex dynamics of the natural gas delivery system and the potential im pacts of altering these dynamics on both natural gas and electricity costs to the consumer. Commenter s stated that, if NGCC units are required to operate at 70% capacity factor, the costs of natural gas to residential and industrial consumers could be impa cted in a negative manner. Commenter s 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. Commenter s stated that, in Ohio, residential and industrial n atural gas consumption represented 61% of all natural gas consumed in the State of Ohio in 2012. Given these numbers, commenter s stated, the EPA must consider the complex dynamics of the natural gas delivery market, the role of natural gas as an economic s ource of residential heating, if realistic re

- dispatch goals are to be set. Commenter s stated that because residential and electric power natural gas consumption patterns are typically 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. Commenter s noted they have significant concerns with even a projected 10% increase in delivered natural gas prices from this proposal alone.

Com menter s expressed concern regarding potential increases in natural

- gas prices caused by the CPP. Commenter s stated the EPA failed to fully assess the direct and substantial indirect impacts the CPP will have on the economy as well as the day

- to

- day functio ning of society. Commenter s stated that natural gas

- fired generation in Arkansas is expected to increase by 157%, thereby placing significant upward pressure on natural gas commodity and transportation prices, and these price increases are directly attribu table to the CPP Commenter s stated there could also be a significant increase in the price of natural gas causing harm to consumers and Arkansas businesses. Commenter s noted the EPA's own analysis of the CPP reflects a 12% increase in natural gas costs res ulting from plan implementation. Commenter s 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 performance levels," the technology assumpt ions have yet to be demonstrated as achievable at a reasonable cost or, in some cases, achievable at any cost.

Commenter s stated the market has recently seen a sharp increase in the volatility of market prices in regions where shale gas development has outstripped the infrastructure capability to deliver to markets where the gas is needed. Commenter s stated that price spikes in the northeast last winter, for example, exceeded $123.50/MMBtu. Commenter s stated that, as demand increases rapidly, this issue could become a much wider problem than in just the northeast; volatility could be very significant with growth in power sect or natural gas demand projected under the Clean Power Plan.

Commenter s expressed concern that the EPA did not consider the significant negative impact of price volatility on energy

- intensive, trade

- exposed (EITE) manufacturers. Commenter s stated that natur al gas prices are known for being relatively volatile and that sudden increases in422 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. Commenter s stated that the EPA's acknowledgement of an increase in natural gas demand prior to 2020, combined with a higher

- than

- expected industrial demand for natural gas, must push natural gas prices higher than EPA e stimates.

Comment 11: Commenters expressed concern that future regulations 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. I n response to additional analysis and many comments, we have modified the proposal and RIA. States may consider local circumstances as they develop their plans, including system reliability, fuel diversity, the “useful life” of generation assets, other reg ulatory requirements, competing demands for natural gas, 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, Chapter 3 of the GHG Mitigation Measures TSD for the CPP Final Rule supporting the fina l CPP, and the Regulatory Impact Assessment of the final CPP and the Regulatory Impact Assessment of the final CPP. The EPA considers the EIA Annual Energy Outlook 2015 cases for high and low oil and gas supply. Any comments regarding regulation of the nat ural 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:

Commenter s stated that EPA needs to look at the issue of future local, state, and feder al regulations on the upstream production of natural gas and factor them into the final rule's presumptions about the future of natural gas and the effects on electricity rates since such regulations increase the costs of doing business and would be passed on to natural gas users through higher prices. Commenter s stated that potential regulations include those to capture methane from upstream oil and gas production; controls for capturing other volatile organic compounds (VOC) from upstream natural gas prod uction; NOx regulations for new nonattainment areas where natural gas production did 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.

Commenter s expressed concern that increased regulation of the natural gas sector, including the primary tool for extraction, hydraulic fracturing or fracking, is already occurring, and there is no doubt that it will have some impact on the cost and availability of n atural gas in the future. Commenter s noted that the EPA recently issued the first federal emissions regulations for hydraulically fractured natural gas wells, as well as draft Underground Injection Control ("UIC") Class II permitting guidance for oil and g as hydraulic fracturing activities using diesel fuels and stated there is no indication that EPA has considered the impact of its own actions on forecasted natural gas prices in the proposed rule. Commenter s stated that State

- and local

- level regulation423 ha s included fracking bans and moratoria including, for example, a ban on fracking in Vermont and statewide moratoria in New York, Maryland, and North Carolina. Commenter s stated that, as a result, it is reckless and short

- sighted to rely so heavily on curre nt and projected natural gas availability and prices in proposing this rule.

Commenter s stated that simple economics indicates that, as natural gas demand increases, so will its price, especially in light of additional EPA rules expected in the near future addressing methane from oil and gas operations.

Commenter s stated that a related concern regarding natural gas prices is the EPA's plans for possible expanded controls over fracking and natural gas recovery. Commenter s requested the EPA to clarify its re gulatory plans for fracking operations prior to finalizing the CPP.

Comment 12: Commenter s stated the EPA should update the gas price and gas price response assumptions that it uses in its IPM compliance modeling.

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 they develop their plans, including system

re liability, fuel diversity, the “useful life” of generation assets, other regulatory requirements, competing demands for natural gas, 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

, Chapter 3 o f the GHG Mitigation Measures TSD for the CPP Final Rule supporting the final CPP, and the Regulatory Imp act Assessment of the final CPP. al CPP

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

Commenter s stated that the gas price response (i.e., gas price elasticity assumptions) built into EPA's IPM model appears to be materially higher than those reflected in the February 2014 NorthBridge analysis of the CATF Power Switch approach and the October 2014 Rh odium Group analysis of the CPP using the NEMS modeling platform. Commenter s stated that comparing the results demonstrates that the gas price response in EPA's IPM modeling is more sensitive to gas demand than either NEMS or the NorthBridge modeling platf orm by at least factor of 2 to 6. Commenter s stated that this indicates 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 res erves and, as a result, EPA's modeling could overstate the natural gas price impact of the CPP policy and needlessly constrain the potentially cost

effective role of additional use of natural gas in re

- dispatch of existing and new NGCC units as well as thr ough gas co

- firing in coal units.

Commenter s stated that since the base case prices appear high, the increase in gas prices forecasted in the policy cases may well also be overstated. Commenter s stated that if there is424 more natural gas available at relat ively low prices, then increased demand for natural gas may cause prices to rise by a smaller amount than forecasted in the IPM policy cases. Commenter s stated that this overstatement of gas prices raises the estimated cost of the CPP rule and can cause th e role of gas in the compliance mix to be understated. Commenter s stated that the assumed price forecast for natural gas in EPA's Integrated Planning Model modeling may not be sustainable in the future due to increased demand placed on this fuel for both h eating and electric generation, as well as offshore sales of liquefied natural gas.

Commenter s stated that the severity of Florida's projected natural gas reliance is unknown beyond 2025 because EPA has not published the parsed files for any other years; however, without these additional parsed files, EPA has not shown how this imbalance might worsen in 2030 and beyond. Commenter s stated that natural gas is a globally traded commodity and the price will eventually more closely reflect the global prices; t hus, 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 much higher based on global demand. Commenter s asked if the EPA and Department of Energy (DOE) along with the Federal Energy Regulatory Commission (FERC) adequately modeled natural gas price scenarios given this likely market change.

Comment 13: Commenters stated that multi

- year forecasts of the price of natural gas have consistentl y been inaccurate and that establishing a mitigation goal based on an assumption of persistent low gas prices is not a reliable or dependable 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:

Commenter s stated that establishing a mitigation goal based on an assumption of persistent low natural gas prices is not a reliable o r dependable approach to estimating capacity factors for NGCC plants over a long period. Commenter s disagreed with EPA that "changes in generation patterns have been driven largely by changes over time in the relative prices of natural gas and coal". Comme nter s provided data from the EIA and suggested that history indicates the NGCC capacity factor is a sensitive function of natural gas prices. As a result, commenter s stated that the EPA's assumption of high future NGCC capacity factors could be invalid if significant natural gas price volatility and increases were to be experienced in the future.

Commenter s stated that numerous industry studies demonstrate the historical volatility and unpredictability of natural gas prices. Commenter s stated that this inf ormation illustrates the danger of EPA's reliance on forecasted natural gas prices for its policy choice. Commenter s cited in particular, a June 2012 study completed by NERA which addresses the difficulty in accurately forecasting natural gas prices. Comme nter s stated the NERA study (1) details the random factors that affect natural gas supply and demand; (2) shows the historic volatility and unexpected changes in natural gas markets; and (3) identifies forecasting models that have proven to be poor indicat ors of the actual natural gas price with large errors and biases in the most widely used425 forecasts, including forecasts from the Energy Information Administration (EIA). Commenter s 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). Commenter s 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 gas from other sectors of the economy. Commenter s provided data indicating that natural gas prices have been historically volatile and unpredictable. Commenter s objected to the proposed rule because it relies on potentially erroneous projectio ns that may not only shift, but may drastically shift, thus exposing the reliability of the nation's energy grid to a highly volatile commodity.

Commenter s stated the EPA should not assume that present low prices will sustain their emissions reduction obje ctives. Commenter s stated that 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. Commenter s stated the EPA's analysis suggests that lo w natural gas prices will enable sustained operations at a high capacity factor, but this is a very dubious assumption. Commenter s explained that natural gas has a highly volatile price curve, and multi

- year projections are regularly inaccurate. Commenter s 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 many natural gas facilities had to curtail operations or sell power at abs urdly high prices.

Commenter s expressed concern (in agreement with EPRI's comments), that establishing a mitigation goal based on an assumption of persistent low gas prices is not a reliable or dependable approach to estimating capacity factors for NGCC p lants over a long period. Commenter s stated that, historically, natural gas prices have been volatile and that increasing utility reliance on natural gas generation would result in additional economical risk. The
commenter s 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 natural gas delivery system inadequacies.

Commenter s stated that the assumption that natural gas prices will remain relatively flat through 2030 fails to take into account the historic volatility of natural gas, the impact on price from future regulations on upstream production, or how increased demand will put upward pressure on prices.

Commenter s stated that, in establishing its NGCC capacity target, EPA should be sensitive to the long

- term impact on natural gas prices. Commenter s stated that, while the EPA contends natural gas prices will remain low going forward, t he EPA's projection suffers from the same uncertainties that have characterized natural gas pricing 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 long term price forecast will be different. Commenter s provided a graph which illustrated the price volatility for natural gas rom 1991

- 2013 as ranging from $1

- 14 per dekatherm. Commenter s stated that mandating reliance on NG CC units will increase the price of natural gas as both gas supplies and delivery capacity become constrained across the country. Commenter s stated that enhanced reliance on NGCC426 units as baseload capacity will put upward pressure on both wholesale and ret ail 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 retiremen ts directly, but instead on the availability of underutilized NGCC capacity.
Response 14: The EPA agrees to the extent that we we believe our 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 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:

Commenter s referred to the Brattle Group study, which points out, the rate of "voluntary" coal plant retirements is highly dependent on future natural gas prices which are impossible to predict, and stated that plant operators and state regulators are unlikely to as sign a probability of closing a plant by a certain date until a final determination is made.

Commenter s supported the EPA's determination not to base its goal

- setting calculations for reduced utilization of coal

- fired EGUs based on retirements directly, b ut instead on the availability of underutilized NGCC capacity.

Comment 15: Commenters expressed concern that NG price increases 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 na tural gas nationwide. In response to additional analysis and many comments, we have modified the proposal and RIA. States may consider local circumstances as they develop their plans, including system reliability, fuel diversity, the “useful life” of gener ation assets, other regulatory requirements, competing demands for natural gas, 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 Fina l 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:

Commenter s stated they found it difficult to identify 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 anticipating. Commenter s stated that the growth in international trade in natural gas facilitated by construction of LNG terminals in the U.S. and427 other major exporting countries could expose the power industry to significant price shocks or supply disruptions. Commenter s stated the EPA has failed to consider the impacts of LNG exports and increased non

- electric utility demand on natural gas supply.

Commenter s stated the manufacturing sector serves as an example of the unintended loss that would occur as the economic benefits of increas ed manufacturing in the U.S. economy would decrease due to LNG exports. Commenter s stated their analysis disproves the notion that the shale

- driven natural gas supply curve is flat and instead shows that it is upward sloping. Commenter s stated the result is that natural gas prices will rise under an extremely conservative demand outlook, such as the one projected in the AEO 2013 ER and, under a more reasonable demand forecast, gas prices will almost double from $3.3/MMBtu today to $6.3/M MBtu by 2030. Commenter s stated that layering in additional demand from LNG exports in the Likely and High Export scenarios would raise prices to $8.8/MMBtu and $10.3/MMBtu in 2030, respectively, assuming no price

- induced demand feedback. Commenter s stated that, at these higher scenario prices, growth in the three main sectors driving the natural gas economy going would be stunted:

Manufacturing: A significant, gas

- intensive sub

- sector exists that will be challenged in passing through high natural gas cos ts in the competitive, global market. This is illustrated in our ammonia case study. Manufacturers will look to establish new plants and relocate existing operations in more favorable gas markets around the world. The historical precedence of companies exi ting US manufacturing is well documented and can happen again if LNG exports rise too high. Electric Generation: For the electric sector, generation providers will migrate to other generation technologies, such as wind and nuclear, but only at higher relat ive costs. This will raise prices for the full spectrum of electricity 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 Figure 21, NGV HDVs are economical at delivered natural gas prices below $14/MMBtu at current diesel prices of $4.2 per gallon (See http://www.eia.gov/pet roleum/gasdiesel/). While this is well above our Henry Hub natural gas price forecast in 2030, the costs of pipeline transportation and compression and liquefaction services will raise the delivered price. CRA estimates that these costs could be $3

- 4/MMBtu

, which would put NGV economics at the margin under the High Export scenario.

Commenter s stated the LNG exporters are the most immune to higher natural gas prices, as Asian LNG import prices are tied tightly to an oil index, which currently trades aroun d $20/MMBtu. Subtracting the costs of liquefaction, shipping, and regasification (netback costs) of $6/MMBtu, commenter s stated that exports to Asia are attractive with domestic natural gas prices up to $14/MMBtu. Commenter s stated this netback price is we ll above our 2030 Henry Hub forecast price across all scenarios and, as a result, would induce LNG exports.

Comment 16: Commenters expressed concern that the switch of generating capacity from coal to natural gas driven by this rule would impair US manufa cturing.428 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 nat ural gas nationwide. In response to additional analysis and many comments, we have modified the proposal and RIA. States may consider local circumstances as they develop their plans, including system reliability, fuel diversity, the “useful life” of genera tion assets, other regulatory requirements, competing demands for natural gas, 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 Regulatory Impact Assessment of the final CPP.

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

Commenter s stated that introducing additional regulatory price signals to the market will likely increase both pricing and price volatility and recommended that EPA include a full range of natural gas pricing and price volatility in the economic impact assessment of this rule. Commenter s stated that the impact of higher natural gas pricing goes well beyond the cost of electricity as many manufacturing industries use gas as a fuel or raw material and recommended that EPA include these secondary cost impacts to manufac turing, as well as the heating cost impact for commercial and residential natural gas users, in the economic impact assessment for the proposed rule. Commenter s stated that most energy intensive manufacturing is located in states with low energy cost struc tures which will be most at risk for rate increases and recommended that EPA allow states the flexibility to mitigate the impact on energy intense industries, including flexible incentives for energy efficiency or cost offsets for increased energy prices.

Commenter s stated that the significant switch of generating 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 for geopolitical con siderations, has the potential to fundamentally alter the natural gas supply supply/demand equation, increase natural gas pricing volatility, and impair the US manufacturing renaissance from its full potential as a job

creating engine of economic growth. C ommenter s stated that current natural gas export growth in Australia provides a cautionary scenario in this regard. Commenter s stated that, in Australia, significant growth in natural gas production has been accompanied by a tripling of wholesale natural g as prices in the domestic market due to the explosive growth in Australia's natural gas export market. Commenter s stated this is occurring even with the recent repeal of Australia's carbon tax and without the concurrent pressures of an electricity generati ng base that is rapidly shifting to natural gas fuels, as is contemplated by the proposed 111(d) rule. Commenter s stated these pressures in the US would have a significant detrimental affect not only on the broad US manufacturing base but specifically on t he production of secondary (recycled) aluminum given the role natural gas as a key input into the secondary aluminum recycling process.

Commenter s stated the proposed Clean Power Plan focuses on electricity, but the increased use of natural gas by power in dustry to comply also will put upward pressure on natural gas costs, an important energy source for South Carolina manufacturers429 Commenter s stated the EPA failed to assess the economic effects on other economic sectors from higher natural gas prices or pot ential gaps in the incremental natural gas supply. Commenter s noted that many sectors of the economy rely on natural gas and have increased natural gas consumption since pre

- recession levels, including the power, industrial, and transportation sectors. Com menter s stated that natural gas exports will begin to coincide with the accelerated retirement of coal generators. Commenter s noted that (1) four liquefied natural gas export projects approved so far by DOE have the capacity to export 7.1 bcfd of natural g as by 2018, amounting to more than 10 percent of the current daily 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. Commenter s stated the EPA's analysis does not even touch upon, let alone analyze, any of these market developments and how the proposed rule w ill affect the economic sectors and residential customers that depend upon natural gas.

Commenter s stated that recent history provides more than ample experience on the scope and depth of the consequences of over

- relying on natural gas. Commenter s stated that, between 1997 and 2009, the natural gas market experienced five significant 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. Commen ter s stated this occurred even when natural gas demand fell

- but prices increased by 160 percent. Commenter s 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 se ctor

- more than three times the overall growth in natural gas demand by all sectors. Commenter s concluded that there is little question of the direct correlation between manufacturing job losses and higher and more volatile natural gas prices during this pe riod

. 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 Labor Statistics ).

Commenter s stated Nick Akins, 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 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 14 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 emphasis on natural gas could increase the cost of fertilizer for farmers and ranchers and that development of new transmission lines, natural gas pipelines and electrical generation facilities co uld 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.430 States may consider local circumstances as they develop their plans, including system reli ability, fuel diversity, the “useful life” of generation assets, other regulatory requirements, competing demands for natural gas, and infrastructure. Regarding the price of natural gas on the impact of fertilizer, EPA believes that demand impact of the 11 1(d) final rule will be relatively small, as we believe the price impact on natural gas of the rule will be small. 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 f or the CPP Final Rule supporting the final CPP, and the Regulatory Impact Assessment of the final CPP. Regarding 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, considering the flexibility afforded to states

- including trading and additional time before the start of th e interim performance period

– to develop plans that consider reliability and local circumstances such as gas infrastructure and competing demands for natural gas. The 111(d) final rule does not require states to construct transmission or natural gas infra structure 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 VIII.G of the final rule preamble CPP and the Regulatory Impact Analy sis of the CPP final rule.

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

Commenter s stated farmers and ranchers could be affected in another, more direct way by any wide volatility in natural gas prices. Commenter s stated 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 vital input for farmers and ranchers to grow crops. Commenter s s tated that, while natural gas prices are currently low, thanks to technological developments (such as hydraulic fracturing) that appear to have opened up large supplies, the future availability of adequate natural gas supplies comes into question as activi sts continue to increase pressure on regulatory agencies to oppose fracking. Commenter s stated that, if new supply sources be restricted while utility demand is increased, we could see increases in the price of natural gas that could raise input costs for farmers.

Commenter s 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. Commenter s stated that natural gas is the largest cost in manufacturing commercial fertilizer used to grow crops and that increases in natural gas prices will have a corresponding impact on the price of commercial fertilizer.

Commenter s 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. Commenter s stated that, as such, farmers and ranchers will either lose property and/or the ability to fully ut ilize portions of their property.

Comment 18: Commenter s expressed concern that the EPA has not accounted for impacts at efficient, low

- emitting generators of combined heat and power.431 Response 1 8 : The EPA disagrees with the commenter s ’ assertion that the rule will cause these CHP units to shut down. The rule does not affect such units and will not have the price impacts alleged. See the R egulatory I mpact A nalysis of the final CPP

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

Commenter s stated Verso's gas turbines at two facilities in Maine generate power for the electrical grid when it is most needed. Commenter s stated that, with limited natural gas supplies in the region, their costs can skyrocket in winter, surpassing revenues. Commenter s stated that natural gas costs in Maine, particularly peak prices, can be expected to escalate further as a result of the Car bon Pollution 111(d) Rule. Commenter s stated the gas turbines could become too costly to run or maintain, forcing Verso to buy more electrical power and making the company less competitive. Commenter s 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 increases in NGCC generation will increase demand for gas and may increase the frequency of spikes in gas prices in areas with constrained supplies.

Response 19: The EPA disagrees to the extent that we believe our analysis appropriately considers natural gas supplies, infrastructure and competing demands. The I PM 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 develop th eir plans, including system reliability, fuel diversity, the “useful life” of generation assets, other regulatory requirements, competing demands for natural gas, and infrastructure. See sections V.A, V.D, VIII.A, VIII.C.1 and VIII.G.2 of the final rule pr eamble 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 case during the Polar Vortex experienced in the winter of 2013

- 14 when spot prices spiked to historic levels. Comm enters recommended the EPA include consideration of secondary uses and localized price impacts in its analysis of natural gas fuel supply. Commenter s noted an EIA report that indicates natural gas fuel prices have a history of volatile pricing for local di stribution company customers in Tennessee and stated that this is an area where EPA should devote additional consideration in its analysis.432 Comment 20: Commenter s recommended the EPA provide a "safety valve", granting relief from the State's CO2 targets if natural gas prices increase by more than 10% above the price projections used by the EPA to prepare the Rule.

Response 20: The EPA thanks the commenter s

. The EP A disagrees with the commenter s , particularly with the claim that the rule is the primary cause of gas price changes, when there are many factors that are entirely outside the rule. We believe t he impacts from the rule on natural gas prices will be modest. See the Regulatory Impact Analysis of the final CPP

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

Commenter s stated the natural consequence of the Proposed R ule 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. Commenter s stated that, if the supply of natural gas is interrupted or the cost of gas rises beyond predications, the consequences may be profound. Commenter s concluded that some form of safety value is necessary to allow for the continuation of coal

- fired capacity to be used in such instances.

Comment 21: Commenter s stated the EPA should account accurately for the efficacy and cost of switching from coal to natural gas, which will likely 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 response 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 Meas ures TSD for the CPP Final Rule supporting the final CPP, and the Regulatory Impact Assessment of the final CPP. In response to additional analysis and many comments, we have modified the proposal and RIA

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

Commenter s stated the climate benefit of switching to natural gas is doubtful, and the cost is extraordinary because we must soon phase out natural gas, a factor that EPA fails to consider. Commenter s stated the EPA shou ld sharply reduce the Clean Power Plan's reliance on natural gas. Commenter s stated there is little if any room for natural gas in a proposal that replaces fossil

- fuel generation incrementally by using the emission

- reduction strategies that come at lowest cost to consumers.

Comment 22: Commenter s provided the following comments and asked the EPA to clarify several points which relate to specific sections and pages of the Technical Support Document (TSD)

-- GHG Abatement Measures, Chapter 3.433 Response 22: The EPA thanks the commenters for these comments. The TSD has been revised for the final rule. See the GHG Mitigation Measures 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 the 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 from the 2012 eGrid data file provided in the docket.

• On page 3

- 10, footnote 53 says the $15/ton CO2 price 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 o f numbers cited as coming from the same data file.

• The final sentence on page 3

- 10 cites an expected increase in natural gas production of 20% between 2012 and 2020 as a reason the United States can accommodate an increase in the average NGCC capacity fac tor to 70%. EPRI suggests that it is important to evaluate what is expected to be consumed by the LNG export facilities which have recently been approved. For example, EPRI estimates 3.6 trillion cubic feet (TCF) per year have already been approved and

ano ther 3.6 TCF is under review by DOE.22 EPRI recommends EPA clarify its assumptions for the potential magnitude of LNG exports to the potential price of natural gas.

• On page 3

- 11: Adding in the existing sources that were not yet online in 2012 (under constr uction) increases total NGCC generation calculated in the goal 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 power production in 2030 will be 1,743TWh, which is 178% of the 2012 value. That implies a significant increase in natural gas consumption versus today. For 2020 EPA predicts NGCC power production will be 1,369TWh, which shows a mismatch between what is in this reference doc ument and what is in the cost

- benefit calculation memo. Page 3

- 12: For comparison, NGCC generation growth of 450TWh (calculated in goal setting) would result in increased gas consumption of roughly 3.5 TCF for the electricity sector. There is a miscalculat ion here based on what 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 electri c power sector consumed 9.1 TCF of natural gas 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 increase by 50%. Although
t he amount of power produced by simple cycles might be large enough to account for this discrepancy, the modeling results in the cost

- benefits memo show only a very small amount of power being generated by simple cycles.434 • The discussion on page 3

- 14 regardi ng the availability of NGCCs is confusing and seems to suggest that the availability of advanced NGCCs is higher than that of lower firing temperature NGCCs.

• Page 3

- 20: In the discussion of the assumptions that 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 rationale for this charge and at this particular level would be useful.

• Table 3

- 6: The base case has an NGCC capacity factor of 52% which is significantly h igher 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: At the top of the page it is stated: This is because only 29 state goals

a re premised on the existing 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 confusin g and should be clarified.

Comment 23: Commenter s asked for clarification regarding the EPA'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 Measures 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 capacity", why do the utilization rates not equate with unreserved capacity on a long

- term basis?

• What line packing considerations did the EPA take into account?

• Why did the EPA not analyze the integration of storage capacity? How might this f urther 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 usage rates.

• Why didn't the EPA consider how extreme events and seasonal change s in demand for natural gas influence gas prices and availability?435 • 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 prices, then says EIA averages
year

- to

- year ch anges 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 th e EPA provide state & regional estimates?

3.2.7 Co

- firing

In a notice of data availability (NODA) issued October 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 sect or.
This section addresses comments on the potential inclusion 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 concep t that building block 2 could be expanded to include natural gas co

- firing at existing coal

- fired boilers. Some of these comments also involved other means for increasing the use of natural gas to displace coal.
Response 1: Based on a review of the comment s the agency decided not to develop the concept of including gas co

- firing at coal

- fired EGUs as part of building block 2. Our rationale is discussed in further detail in section s 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 co

firing or new NGCC units in states' baselines.

Commenters observed that gas co

- firing, as a unit

- specific contro l 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 r eduction goals, but should not be part of BSER. Also, commenters said, simultaneous inclusion of co

- firing with re

- dispatch could lead to double counting of potential emission reductions.436 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 state baselines even tighter and the ultimate standard even harder to achieve.

Commenters stated that coal

- fired CHPs are unique and sale of power to the grid may be necessary to rec over 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. Commenters said that the feasibility and potential cost of co

- firing natural gas with existing coal and other fossil fuel

- fired power plants is highly dependent upon the particular characteristics of an individu al power plant. Commenters added that the same variance in feasibility and cost is also true for the relative proximity and availability of natural gas to existing power plants that do not currently utilize natural gas. As such, commenters said that the EP A would not be able to apply a simple methodology to every state for what percentage of existing coal, oil, and 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 analy ze each fossil

- fuel fired power plant individually 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 take weeks to mon ths of in depth analysis from a broad array of market experts and engineers, and conducting such an analysis for hundreds of power plants would take years and tremendous manpower. Commenters concluded that the proposed alternative is impracticable within E PA's given timeline.

Commenters supported in part the approach that would treat the increased use of natural gas "comprehensively" rather than considering separately the potential to re

- dispatch. Commenters said increasing natural gas utilization includin g co

- firing of natural gas with coal would reduce the emission rate of an affected EGU and be particularly valuable in states without significant potential to shift utilization towards underutilized NGCCs. To the extent that more implementation strategies can enhance states' flexibility in reaching their targets, commenters favored inclusion of co

- firing as a potential compliance tool. Commenters pointed to the new data and analysis in the NODA that shows that co

- firing meets the BSER cost criterion.

Comme nters supported clarifying the compliance option of co

- firing coal plants with natural gas as discussed in the NODA, Section III. B. 1. "Stringency 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 states with NGCC generation of 12% to 55% of existing steam generation, but commenters did no t support such narrow criteria to be met in order to use the co

- firing option. Commenters suggested 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 imp lement confidently in a state plan, 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 Ot her Gas units should not be added into the cohort437 of units expected to achieve a target capacity factor. Particularly in New York, commenters said, Other Gas units are typically used for specific system reliability purposes.

Commenters suggested a goal set ting strategy that represents the BSER should include redispatch to new NGCC; consideration of the ability to co

- fire or interchangeably burn natural gas at existing steam generating units; and redispatch of remaining coal and oil generation to existing NG CC, up to a 75% capacity factor, based on average annual capacity. The
commenters suggested (1) optimizing the emissions reduction potential of this building block while limiting the potential for unintended outcomes; (2) capitalizing on the increase in ne w NGCC capacity nationwide that will occur through market 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 existing steam generat ing units. The
commenters stated these suggestions should be implemented together to preserve the overall stringency of this building block. The commenters stated the combination of the recommendations results in a demonstrated level of achievable emission reductions, accountability, and flexibility consistent with states' 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 satisfies the other requirements of BSER as long as the system's costs are not "exorbitant." Commenters said that the number of existing and planned conversion projects already taken, absent any regulatory carbon pollution mandate, is strong e vidence that the costs are reasonable. In addition, commenters said, the EPA's own data demonstrate that conversion to natural gas generates 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 are 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 f ull range of benefits associated with conversion are taken into account. Commenters referred to modeling by ICF using IPM and stated that, if the EPA adopts the changes NRDC recommends, natural gas use will fall over the 10

- year period.

Commenters believe d that the adoption of a minimum value for Block 2 that accounts for co

firing natural gas in steam EGUs would be a fair means to make Block 2 emission reductions stronger and fairer. If the EPA does not adopt this revision to Block 2, commenters agreed th at 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 Block 2 values for states

. Commenters stated that Block 2 should be revised such that a 12% shift from coal

- fi red generation to natural gas

- fired generation (i.e., re

- dispatch, co

- firing natural gas in steam EGUs, and new NGCC) would serve as the minimum floor for each state vis

- a

- vis Block 2. B arring the EPA's adoption of such an approach, commenters said that na tural gas co

- firing should be part of BSER that undergirds each state's ultimate emission goals. Commenters said that the EPA could reasonably incorporate a 20% natural gas co

- firing rate for facilities that are so equipped as an element of the BSER (e.g., part of the assumptions underlying Block 1 or 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 achievement of that particular level by each state.438 Rather, commenters stated, all of the Building Blocks together synthesize the assumptions that lead to each state's goal. While not all stea m EGUs will necessarily co

- fire natural gas, commenters concluded that co

- firing should be incorporated into and provide the basis for the state goals in the final Clean Power Plan.

Commenters stated that EPA proposes to make building block two more string ent 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 d esignating co

- firing or new NGCC construction as BSER would effectively redefine the source by re

- designating coal

- fired EGUs as natural

- gas fired EGUs. Commenters stated that EPA cannot simply redefine an entire source category in an attempt to reduce emi ssions from that category. Commenters stated that second, EPA cannot designate new units as a component of the best system of emission reduction for existing units and to do so would impermissibly blur the clear statutory distinction between new and existi ng units. Commenters stated that third, as EPA itself recognizes, the costs 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 co

firing 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, meanwhile, would be as high as $81 per metric ton, and therefore, it would be unreasonable to designate these e xorbitantly costly alternatives as the "best system of emission reduction (considering the cost of such reduction) that has been adequately demonstrated for designated facilities.

Commenter s stated that in its Notice of Data Availability, EPA requested com ment on whether it should consider the potential to co

- fire with natural 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 options (increased use of existing NGCC plants,

re

- dispatch from coal to new NGCC plants, and co

- firing). Commenters stated that the power sector is already dep loying these methods, making clear that they are both adequately demonstrated and reasonable in cost. Commenters stated that these methods will also achieve carbon pollution reductions along with reductions in other harmful pollutants that threaten wildlif e, such as sulfur dioxide, NOx, and mercury.

3.2.8 New NGCC

This section discusses issues related to shifting generation from existing units to newly constructed NGCC plants as part of Building Block 2.

Commenters have raised a number of issues related to this subsection which are organized by topics (comments) below. Responses are provided for these topics.439 Comment 5 1 : Commenter s 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 1 : The EPA has not adopted the minimum floor approach for the fin al 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:

Commenter s said that it is inconsistent with the CAA 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 div ersity and cost effectiveness. Commenter s added that calculating Building Block 2 on a regional basis is an arbitrary way for the EPA to increase the stringency of some states' goals and downplay disparities in state targets. Commenter s said that electric utility companies design, operate, and dispatch their systems across state and regional boundaries, and these systems should be afforded the flexibility to comply as a system. Commenter s concluded that the calculation of Building Block 2 should support thi s approach, not further complicate it.

Comment 2: Commenters allege that EPA fails to understand RTO

- Operated Capacity Markets and Claim these markets Pose Significant Barriers to New Generation Resource Development and Thus to Implementation of the Propo sed Rule.

Response 2: The EPA believes it understands and has properly treated the role of these capacity markets, and disagrees that they are a barrier to compliance with this rule. EPA cites these markets as examples of one component of how EGUs can 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 markets have been a component of revenue for the development of new NGCC and other new capacity to replace retiring coal capacity in regions like PJM. This rule concerns the CO 2 emissions from existing sources, and is not directly related to the development of new capacity, as new NGCC capacity is not part of BSER for th is rule. The EPA modeling for this rule also does not project significant new NGCC capacity will be required for compliance with this rule. See Chapter 3 of the GHG Mitigation Measures TSD for the CPP Final Rule supporting the final CPP, and the Regulator y 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 explicitly include the construction of new natural

- gas units, under the portfolio approach, compliance with the proposed guidelines will likely require a partial turnover of the existing fleet and the construction of new natural

- gas fired generation resources. Commenters said, such resources will be needed both to replace reti ring coal plants and meet the flexible ramping needs required to support an increase in intermittent renewable resources. Commenters said, this section discusses how the RTO

- operated mandatory440 capacity markets will greatly impede such new natural gas gener ation and are also likely to pose barriers to new renewable resources, as described in 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"). Commenters 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 added 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 implement. Commenters said EPA misunderstands, however, how those markets function. Commenters said EPA asserts that in states where RTOs manage markets, the RTOs "administer auctions for forward capacity" in which generators "all compete to provide potential resources for meeting the projected demand for electricity services." Commenters said only two of the five RTOs administer such auctions.

Commenters stated that RTO capacity market s are extremely controversial and subject to many pending legal disputes. Commenters said many FERC stakeholders have argued for years that RTO capacity markets have failed to serve their intended basic function, i.e., to procure capacity needed for reliab ility 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 the core design and purpose of RTO capa city markets. Commenters said individual RTOs are likewise continuously making alterations that seek to correct identified flaws in existing capacity markets. Commenters said that consequently, it is not reasoned decision

- making for EPA simply to assume th at RTO capacity markets can take on the new function of advancing the Proposed Rule's objectives.

Commenters said that EPA needs to withdraw the Proposed Rule, fully engage with FERC regarding these issues, and revise its Proposed Rule to reflect the actual market conditions under which any Section 111(d) regulations would be implemented. B. RTO

- Operat ed Mandatory Capacity Markets Have Not Been Effective in Leading to the Construction of New, More Efficient Resources at a Reasonable Cost to Consumers.

Commenters stated, there are numerous flaws in the mandatory capacity markets that have made them ineff ective and costly constructs that will likely 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 combined

- cycle natural gas plant.

• The vast majority of the revenue collected through capacity markets has been paid to older, existing units, although many older plants have paid off much of their fixed costs and are therefore earning windfall profits. For example, only 9 percent441 of the $72 billion in revenue committed through the PJM capacity markets is for new resources, demand response, or energy efficien cy.

• Financing of newer units at a reasonable capital cost 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 technology types or specifi c locations on the grid. As a result, critical needs are not addressed, including adequate flexible ramping capability to match the variability of renewable resources, reliability gaps created by retiring coal plants, and the coordination of natural gas in frastructure and delivery with the significant expansion of natural gas generation. The RTOs often create systems of side payments to ensure reliability, such as direct payments through what are known as reliability

- must

run agreements to coal plants to re main in place to ensure reliability.

• Capacity markets use zonal price differentials on the theory that higher prices will act as a "signal" for the development of new generation or transmission. But such higher prices are not effective signals because owne rs 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 processes 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 environmental rules.

Commenters st ated, the ineffectiveness of the capacity markets as a tool in resource development was confirmed by a recent study by Christensen Associates commissioned by the Electric Markets Research Foundation. Commenters said, the study's authors concluded that RTO markets "do not and cannot address long

- term capacity 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 resources. Commenters sa id, 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 Create Direct Impediments to New Resources.

Comme nters 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 have some type of MOPR or "buyer

- side mi tigation" (BSM) that imposes a floor price on offers to sell from new resources, making it more difficult for these new plants to clear the auctions.

Commenters stated, when mandatory capacity markets were created, the states, public power, and cooperativ e utilities negotiated specific and express exemptions from these MOPRs in PJM442 and ISO

- NE for resources built by load serving utilities to self

- supply their own loads. Commenters said, while FERC initially approved these provisions as just and reasonable, in 2011, the Commission effectively stripped these self

- 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 provisions allowed load

- serving utilities to exercise "buyer

- side market power." Commenters believed these arguments are unsubstantiated and the MOPR in these RTOs is an unnecessary and inefficient barrier to entry. Commenters said, these RTO proposals and their acceptance by FE RC overturned previously negotiated agreements and provide a dramatic example of the absence of a commitment by RTOs to respect all stakeholder interests.

Commenters stated, the impetus for these rule changes was actions taken by several states located wit hin 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 control of their energ y resource future and protect their residents from high electricity prices. Commenters said, New Jersey, Maryland, and Connecticut all established competitive bidding processes for the procurement of capacity in their states using long

- term bilateral contr acts. Commenters said, fearful of the lower prices that would result from the entry of new generation resulting from these state efforts, owners of existing power plants sought to block this new generation by obtaining approval from FERC for a significant tightening of the MOPRs in PJM and ISO

- 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 addition, FERC also determined in 2012 a new, more efficient natural

- gas plant under long

- term contract in the NYISO was subject to mitigation because the plant had an unfair advantage by signing a contract that reduced its risks and was procured through a "discriminatory" process that was only o pen to new generation.

Commenters stated, imposition of a MOPR and BSM makes it more likely that new resources will fail to clear the capacity auctions and that the 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 ability of state utility commissions to ensure reliable servic e in their states, but they also raise barriers to resource development by public power utilities, because a MOPR greatly increases the financial risk these entities face in constructing or procuring new resources. Commenters said, these rules are therefor e impediments to the development of new, cleaner resources, potentially including renewable energy.

Commenters stated, in separate cases, federal district courts in Maryland and New Jersey also invalidated these state contracts because FERC has jurisdictio n over wholesale power rates and states cannot take actions that impact wholesale power markets. Commenters said, these decisions were appealed to the U.S. Courts of Appeals for the Third and Fourth Circuits, and both Circuits upheld the district court dec isions.

Commenters stated, not only do the mandatory capacity markets impede implementation of the Proposed Rule by erecting barriers to new resource development, but further jurisdictional complications exist where the utilities were restructured at the retail level and therefore no longer own the generation. Commenters said, such "retail access states" tend to be located in RTOs with443 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 subject to state price regulation. They do not have any obligation to serve customers (load) and face minimal price regulation at the federal level. Even without consideration of CO2 emission reduction objectives, the combination of RTO

- run energy markets and domination of merchant generators has led to significant difficulties in providing longer

- term investment incentives to maintain p roper levels of generating capacity.

Even in markets with fully

- regulated, vertically

- integrated utilities, the challenges of integrating CO2 reduction policies will be significant, but those utilities have the means to balance all of the options and deve lop a comprehensive strategy to meet 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 driven by competing firms in respon se to short term price signals (and expectations of future short

- term price signals)."

Commenters stated, FERC Commissioner Tony Clark aptly 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 Northeast part of the country, the politics and the levels of government and the stages of restructuring or not restructuring and how they match up offers a very unique set of challenges beca use you just don't have some of those command and control type levers that you have in some other regions 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 impe ded by mandatory capacity market rules.

However, commenters stated, the Proposed Rule does not directly address this concern. Commenters said, instead it notes that "states committed to Integrated Resource Planning (IRP) would be able to establish their C O2 reduction plans 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 later states that "in the U.S. electricity system the d emand for electricity services is met, on both a short

- term and longer

- term basis and in both regulated and deregulated contexts, through integrated consideration of a wide variety of possible options, coordinated by some combination of utilities, regulato rs, system operators, and market mechanisms." Commenters said, these vague and 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 i mplement these guidelines without significant reforms to the mandatory capacity markets.

Comment 3 : Commenters stated that considering new NGCCs, or any new sources, as part of a BSER or compliance process for existing sources is clearly contrary to Sect ion 111.444 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. S ee 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 existing 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 stationary combustion turbines source category is NGCC technology (where the proposed federal standard is 1,000 pound o f carbon dioxide per gross MWH for larger turbines).

Commenters stated that considering new NGCCs, or any 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 ne w source cannot be an existing source, or vice versa. Commenters said that because existing sources, when modified or reconstructed, become new sources, those sources would no longer be existing sources subject to Section 111(d), state plans, or state stan dards of performance.

Commenters stated the preamble (see NPRM, 79 Fed. Reg. at 34923) misses a vital point because by focusing solely on the "mass emission reductions from affected EGUs" it ignores the emissions that will be created by the new NGCCs, whi ch should bear on a determination whether the state has achieved the required level of emission performance. Commenters added that this approach is consistent with the EPA's treatment and concerns related to sources gaming the system by making modification s to escape coming under the emission targets. Commenters noted that a potential exception is the implementation of Smart System Dispatch because it is preferable to have the price that the EPA determines 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. Commenters said that while this alternative would not be as economically efficient as a non

- discriminatory application of the carbon price, it would not have the significant detrimental emissions impacts discussed above. Commenters said with a
pre

- determined uniform price, the new NGCCs will not artificially reduce the carbon price necessary to achieve the target reductions at existing EGUs. Commenters stated that new NGCCs would still shift emissions from existing EGUs to new EGUs, but as long as the carbon price is maintained, the overall reductions due to coal to gas re

- dispatch should be maintained. Commenters noted that in the NODA, the EPA requested comment on whether it should designate a minimum level of re

- dispatch that can occur in each state because states with little existing NGCC capacity could still build new NGCC capacity to reduce the use of coal

- fired faciliti es. Under such a mechanism, commenters noted, the new units would necessarily need to be treated as affected units, and their emissions should be included in calculating compliance with the EPA's goals. Commenters asked the EPA to clarify that this approac h applies in all
states.445 3.2.9 Regional approach

This section discusses issues related to use of a regional approach to building block 2 to account for interstate generation shifting

.
Commenters have raised a number of issues related to this subsection wh ich 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 th e state level redispatch approach 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:

Commenter s said that the EPA's proposed meth odology to calculate re

- dispatched generation assumes that each state must have the existing NGCC capacity to increase output in the amount needed to reduce emissions from existing coal units in the same state. Commenter s said that this metric ignores the reality of interstate power flows (which the EPA elsewhere recognizes) and misses an opportunity for NGCC generation in one state to displace coal generation in a neighboring state. Commenter s said that calculating re

- dispatch on a regional basis would inc rease the amount of re

- dispatched generation by 104 TWh (or 24%).

Commenter s said that section 111(d) rules permit the Agency to recommend the contours of an allowance system that could be adopted by multiple states. According to commenter s , many states h ave asked for such guidance.

Commenter s stated EPA should recognize that for some states, a regional budgeting approach will make more sense than using RECs for compliance. Therefore, the commenter s believe d states should be allowed to enter into multi

- state agreements that allow for emissions budgeting so long as the emission reductions are verifiable and not being claimed by another entity or
state.

Commenter s supported a regional approach because it would more accurately calculate the availability of underutilized NGCC capacity nationwide and more fairly assign emission reduction obligations across the states. Commenter s stated that existing power plants are

c omponents of a complex and interconnected electricity grid that stretches across state lines. Commenter s agreed that the EPA's final guidelines will 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. Commenter s provided several examples of this interconnectedness, including ISO

- NE, New England's regional transmission organization, which includes 300 generating plants and 8,00 0 miles of transmission lines. Within each ISO system,
commenter s noted that plant dispatch and electricity flows are determined not by individual state regulators but by ISO

- NE rules and bidding activities, and these factors should determine the actual am ount of existing NGCC capacity that is available for re

- dispatch under Block 2.446 Commenter s presented a calculation of the coal dispatch limitation that occurs if the available existing NGCC capacity in nine states that are served by the Midwest Independen t System Operator ("MISO") are considered as a group. According to commenter s , a regional allocation of

re

- dispatch under Block 2 would produce little change in the overall limitation on coal generation, but would provide for a more even allocation of emis sion reduction obligations between "low impact" states, such as North Dakota and Indiana, and "high impact" states, such as South Dakota, Michigan and Minnesota. Commenter s stated that this approach would also facilitate regional cooperation by limiting th e difference between rule's impact on states that are "winners" and those that face a more challenging regulatory burden.

Commenter s noted that applying the same concept to five of the states served by the Western Electric Coordinating Council (WECC) resu lts in an additional 11 million MWh of reduced coal generation. Commenter s added that it also redistributes 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 other hand, which would otherwise be expected to eliminate all of its existing coal

- fired generation.

Commenter s said that the preceding examples illustrate a more simplified calculation process (i.e., assume that all of the un its in the states are part of MISO or WECC, which is almost, but not completely correct.) Commenter s recognized that it may be more appropriate to organize and evaluate generating capacity on a sub

- regional basis. Commenter s recommended that the EPA evalua te the available underutilized capacity on the 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 in a given system, commenter s said that each unit's assumed available limitation can then be incorporated in the calculation of the emission targets for the state in which that unit is located.

Commenter s similarly noted that a regional methodology is a way of making the t argets for building block 2 more equitable across states; it would increase targets for states with little existing NGCC capacity (such as West Virginia and Kentucky) and ameliorate targets for states with large excess capacity (such as Texas and Florida). Commenter s added that a regional approach would also more consistently align with ongoing grid operations and electricity dispatch decisions. Commenter s concluded that regionalization of the gas re

- dispatch targets would be more consistent with how the EP A calculates the renewable energy building block targets. Commenter s noted that the stronger renewable energy targets proposed in the comment and summarized elsewhere in this document were developed on a bottom

- up approach from the state level, but they ca n be easily regionalized in a similar manner for consistency.

Commenter s favored the regional scenario because New Hampshire grid operators have engaged in considerable re

- dispatch involving shifting generation among various fossil fuel

- fired units within and outside the state. Commenter s concluded that the impact of meeting New Hampshire's need should be evaluated on a regional level.

Commenter s acknowledged while that regional plans will be complex and time

- consuming to develop, they will be needed to pr ovide the lowest cost solutions. Commenter s appreciated the EPA's recognition of the disparate impacts between states that have invested in NGCC and those447 that have not. Because most generation is operated in order to meet regional needs, commenter s said t hat it makes sense to apply building block 2 on a regional basis as well.

Commenter s recommended that the EPA calculate the emission reduction potential for redispatch on a regional, rather than state

- by

- state, basis. Commenter s 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 specific 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 their targets; likewise, states whose targets do not include a re

- dispatch component, or for which this component is small, are less likely to rely on measures in this bu ilding block. Commenter s stated that the EPA's assumption in calculating potential emission reductions from re

- dispatch of coal to NGCC also does not comport with the reality of the bulk electricity system, because coal in one state could be re

- dispatched by NGCC in another.

Comment 2: In comments on the Tribal & Territorial supplemental proposal, commenters supported the use of a regional approach applying to Tribal lands and described the benefits.

Response 2: The EPA decided to not include the state level redispatch approach 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 said that not only would a regional (rather than state

- by

- state) approach to Block 2 correspond with how the electric sector actually operates, it would ensure significantly greater emission reductions, since coal

- heavy states with little or no NGCC capacity would be expected to import cleaner generation from neighboring states that do have excess capacity. According to
commenter s , nowhere is this "fix" more appropriate than on tribal nation lands, which function as "islands" of generation under the EPA's proposal. Commenter s noted that, of the three nations affected by the supplemental proposal, the Navajo Nation and Ute Tribe have a combined 4.5 GW of privately owned coal

- fired capacity but no NGCC capacity, while the Fort Mojave Tribe has over 700 MW of NGCC

- fired capacity but no coal units. Commenter s said that the EPA's approach calculates no emission reductions under Block 2 for any of these three nations. Far from "islands," commenter s stated, the plants that are hosted on these lands export the vast majority of their el ectricity to ratepayers in other jurisdictions and could easily be expected to reduce their dispatch in accord with the available NGCC capacity in nearby states.

Commenter s calculated the impact on the emission rates of the privately

- owned EGUs located on Navajo and Ute lands if the underutilized NGCC capacity that is available in the region is used as a proxy for anticipated coal unit retirements, as EPA has done elsewhere. As proposed by the EPA, generation from coal units located in Arizona would drop f rom 24 million MWh/yr to zero, while under the regional redispatch approach, 9.4 million 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 app roach, while achieving greater reductions than the448 EPA's proposal, would also balance the reductions that APS will need to make between assets in states and on tribal nation lands.

Commenter s said that the appropriate emission rate for tribal nation lands , applying the EPA's Blocks 1 and 2 but employing factually documented assumptions about the available HRI improvements at the affected units and more realistic assumptions about the availability of existing NGCC capacity to offset curtailments of coal

- fir ed 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. Commenter s said that this rate should be further adjusted to reflect the EPA's Building Blocks 3 and 4, as described elsewhere. Accordi ng to commenter s , 1,292 lbs CO 2 /MWh may seem to be a large difference from the EPA's proposed emission rate of 1,993 lbs CO 2 /MWh for the Navajo Nation, however, if one Navajo Generating Station unit closes by 2019, a possibility the EPA has discussed, and if the lost generation is replaced by renewable energy or energy efficiency while the remaining coal

- fired units on Navajo land achieve the calculated HRI improvements, the Navajo Nation's emission rate will be 1,500 lbs CO 2 /MWh. Commenter s said that the N ation would be able to meet its target with modest additional emission reductions through coal curtailment or RE development.

Commenter s added that a regional approach is especially useful in the context of Indian country where a single tribal jurisdiction may not encompass both coal and NGCC generation, and therefore coal to gas re

- dispatch within such a jurisdiction would not be possible unless a regional approach were adopted. Commenter s stated that a regional approach would enable tribal areas to take a dvantage of the flexibility to switch to cleaner generation resources and reap the benefits of doing so.

Comment 3: Commenter s said that the EPA did not fully consider the logical retirement of coal units when they determined goals on a state

- by

- state basis.

Response 3: The EPA disagrees . In response to additional analysis 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 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 start of the interim performance period , and th e ability to shift emission rate achievement between performance periods. Neither the Building Blocks nor the IPM runs are prescriptive

- states may consider local circumstances as they develop their plans. See sections V.D, VIII.A, VIII.C and VIII.G of th e 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:

Commenter s said that setting goals on a state

- by

- state 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 on the opposite side of a st ate line simply due to449 the target for the first state being lower than the target for the second. For instance, commenter s said, in the IPM run illustrating the regional compliance 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. Commenter s stated that coal

- fired ge nerating units are expensive, long

- lived 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 shareholders of IO Us, members of cooperatives and customers of public power districts will continue to pay for the asset as well as any new generating units built to replace its output.

Commenter s noted that the service territories of the Entergy operating companies (utilit ies) have a higher percentage of existing NGCC capacity (relative to load) than most other regions. Under the Proposed Rule, commenter s said that Entergy's utility states (Arkansas, Louisiana, Mississippi, and Texas) are required to reduce emissions signif icantly even though its utility fossil average emissions/MWh already is below the standard for new NGCCs. According to
commenter s , this approach also ignores the fact that Entergy is in an interstate power pool balancing authority, MISO, whose MISO load re presents approximately 24% of MISO TWh, but they include approximately 45% of the NGCC redispatch potential within MISO. Commenter s said that allocating this potential more broadly across a larger region would reduce the collective compliance obligation of the Entergy states without weakening the overall standard.

Comment 4: Commenter s stated that a critical problem with the CPP arises from the fact that responsibility for meeting and enforcing targets appears to be left only with the states.

Response 4: The EPA disagrees. States are required to submit plans to the EPA, but the rule applies to sources. The EPA believes states have the 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:

Commenter s stated that the proposed 111(d) regulations require individual states to meet and enforce their required emission rates, while regional organizations, RTOs, ISOs or groups of states are not expressly provided this authority. Commenter s believe d that this apparent conflict in state obligations and enforcement versus an allowance for regional approaches is at the heart of one of the major problems with the Clean Air Plan

- the electric utility industry throughout the United States, with few exceptions, opera tes on a regional or multi

- state basis. Commenter s indicated that this is true in both traditionally regulated areas of the country with large multi

- state companies like the Southeast (e.g., Southern Company, Duke Energy) and Northwest (Bonneville Power Ad ministration and PacifiCorp), and in RTO centralized markets that cover much of the rest of the country. [ Commenter s noted that exceptions include California, New York and Texas ISOs which operate within single states. ] Commenter s provided a figure showing the extent of power flows among states, noting that Maryland imports a high proportion of its power needs (almost 50%), Wyoming exports almost twice as much power as it uses within the state, and all other states are between these extremes.450 Commenter s in dicated that this means that state and federal regulators, and both vertically

integrated utilities and RTOs/ISOs with responsibility 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. Commenter s stated that whether all 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. Commenter s 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 currently allow for a delay in meeting the initial 2020 emissions targets. Commenter s added that the NODA requests comments on a potential ph ase

- in of building block 2, which presumably would give more time for regional approaches to be considered.

Commenter s stated that the multi

- state nature of grid operations also holds the potential to be disrupted by a state

- by

- state compliance approach in unintended and detrimental ways. Commenter s suggested the following issues:

• A state that looks solely to itself to ensure compliance, and institutes restrictions for generating power within the state (and increasing its emissions) to export outside the st ate, would result in no one being able to look within that state with confidence for possible power purchases

- even if purchases might be needed for system reliability.

• And what if utilities or independent power producers within a state not subject to
st ate jurisdiction act on their own in ways that increase costs or emissions, or reduce reliability, in other parts of the interconnected network? Has the EPA provided states the authority to override existing governance of these different entities?

• And wha t incentives are there in the future for that state to consider expanding transmission interconnections with other states? If this state is not interested in exporting power, then why would other states be interested 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 scope currently derived from multi

- state operations of electric networks. Planning and operating reserves would have to be increas ed to reflect less dependence on neighboring systems.

Commenter s stated that to some degree, building block 2 will be easier to implement in the traditionally vertically

- integrated markets (the areas not covered by RTOs or ISOs) because in these markets ut ilities remain regulated as to generation output by the state public service commissions, and state regulated utilities are the ones who make dispatch decisions within the states. According to the commenter s , even though state regulators in regulated state s 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 plants could operate in a given period similar451 to what is done with respect to other pollutants. Comme nter s indicated that instead of dispatching the lowest cost mix of generation at any point in time (within reliability and security constraints), utilities could dispatch based on plant emissions to meet the EPA environmental requirements

- known as enviro nmental dispatch. Commenter s said that this form of dispatch would result in higher costs because plants would need to operate out of economic merit order, but it is one of the few options. Commenter s 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 limiting the hours per year coal plants can operate. Commenter s stated that there are significant equity issues in the se determinations if there are plants with multiple owners within the state: How does a state decide which plants must close or limit operations to meet the state requirements? Commenter s indicated that once the decisions are made, utilities would then use economic dispatch the best they could with generation remaining available to the system in any period.

Commenter s stated that in either of these cases

- where a utility itself alters dispatch or the state determines allowable periods of operation

- inefficiencies 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 lower cost options for dispatch to reduce emissions might be available in another state. Commenter s added that to this extent, traditional vertically

- integrated utilities operating in mult iple 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 dispatch under supervision of state regulators, they do have a c learer path to implementation of the CPP than do the RTOs and ISOs.

Comment 5: Commenter s argued that a regional system is the only way to completely eliminate potentially serious inconsistencies in the operations of power plants in different states.

Resp onse 5: The EPA decided to not include this state level redispatch 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:

Commenter s stated that the ideal approach would be a regional, market

- based system that is harmonized across all states sharing a regional power market. Commenter s added that coordination across states is most easily achieved if states convert to a mass

- ba sed standard and implement a flexible, market

- based approach to compliance. Under an emissions trading program, commenter s said, emissions reductions could be traded freely across states. Alternatively, commenter s said, if states chose to achieve complianc e via the introduction of a carbon tax or fee, a uniform regional emissions tax or fee would result in cost

- effective dispatch.

Commenter s discussed rate

- based and mass

- based standards in a regional context in which the dispatch of electricity production a cross a multi

- state region is centrally coordinated.

Commenter s noted that in any electricity system, plants 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 the high demand conditions in which their452 capacity is needed. Commenter s said that the introduction of an emissions regulation alters a fossil

- fueled power plant's variable operating costs and can thereby affect the mer it

- order of dispatch. Commenter s said that recent analysis by Bushnell et al. (James B. Bushnell, Stephen P. Holland, Jonathan E. Hughes, and Christopher R. Knittel. 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 alternative policy designs on system dispatch and associated power sector outcome and summarized some of their findings.) Commenter s noted that although the analysis is calibrated usi ng data from a specific region and year (the western interconnect in 2007), the main results apply with generality.

Commenter s stated that the following analysis assumes that all states use a market

- based approach to meet their compliance obligation. Under a mass

- based system, commenter s 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 with emissions rates below the standard can sell compliance credits to the plants with emissions rates that exceed the standard.

Commenter s discussed how the simulated power system dispatch is affected under a regionally coordinated rate

- based or mass

- based standard. Under the mass

- based regime, commenter s said, "regionally harmonized" means that the regional target is simply the sum of the individual states' emissions targets, with an alternative interpretation that emissions trading is allowed across all states in the region. In either case, commenter s continued, the analys is assumes that permits are allocated via an auction, grandfathering, or some combination of these two approaches and that auctioning and grandfathering have identical impacts on marginal production incentives. Under the rate

- based regime, commenter s said that a "harmonized" regional target is defined by summing the mass

- based targets across states (to define the numerator of the target) and dividing by the sum of baseline generation across all states. Then, in each case, commenter s said, the dispatch model is used to identify the permit price that clears the market and therefore brings the region into compliance.

Commenter s described F igure 1 (titled: "Changes in the merit order of electricity generating units with no regulation, a region rate

- based regime, and a regional mass

- based regime") to illustrate how these policies affect plants' operating costs. Commenter s 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 under the rate

- based approach. Commenter s said that one should not infer from this that social costs are higher under the mass

- based standard. According to commenter s , the private variable costs indicated in the graph are comprised of variable input costs (e.g

., fu el) and compliance costs, whereas social variable costs are comprised of variable input costs and the external damages from emissions.

Commenter s said that lower electricity prices under the rate

- based standard reflect the fact that a
rate

- based standard c onfers 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 approach compared to the mass

- b ased approach. If consumer prices under the rate

- based standard fail to reflect the full social cost of electricity production, commenter s said that the level of electricity production, and the overall costs of achieving any mandated level of reductions, w ould be higher under the rate

- based standard. This453 means, commenter s stated, that while producer variable costs are lower under a rate

- based standard, a mass

- based approach will provide a more cost

- effective approach for achieving emissions reductions.

Com menter s said that the second general result to highlight is that, whereas the introduction of an emissions regulation changes the merit order significantly 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, commenter s said, some coal plants are replaced with low

- cost gas plants at the bottom of the merit order. Thus, commenter s stated, the main difference between the regionally coordinated mass

- based target and regionally coordinated rate

- based target lies in the level (versus dispatch order) of production.

Commenter s also considered a scenario where the stringency of the standard varies across states in a regional power system. Commenter s conti nued to assume that the form of the standard does not vary and all states convert to a mass

- based standard. Whereas the mass

- based scenario in Figure 1 is based on the assumption that a single mass

- based standard applies to all plants in the western U.S., commenter s said that in the present scenario individual states have their own targets and there is no possibility of trading compliance obligations across state boundaries. In this case, commenter s said that it is important to keep in mind that electricity will nevertheless be traded among states within a regional power system.

Commenter s described Figure 2 (titled: "Changes in the merit order of electricity generating units with a regional mass

- based regime and individual state

- level mass

- based regimes") t o illustrate how variation in stringency across states affects the merit

- order in this case. Commenter s said that Figure 2 illustrates how a lack of coordination or linkage between states with different mass

- based standards significantly alters the order o f dispatch. For example,
commenter s said, technically identical coal plants that sit side

- by

- side in the reference merit order (the black line) are impacted very differently under the uncoordinated policy if they are located in states with very different e missions standards. Plants in states with relatively aggressive standards see operating costs increase relative to the reference case, commenter s said, whereas coal plants in states with much less stringent standards move to the front of the dispatch order

.

Commenter s said that any re

- ordering of the dispatch order that is due to inter

- state differences in the stringency of emissions standards, versus real differences in the emissions intensity of production, will undermine the efficiency of power

- system op erations. Commenter s stated that this underscores the importance of allowing for trades in emissions across states in the same electricity market.

Commenter s 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. Commenter s said that Figure 3 (titled: "Changes in the merit order of electricity generating units"), which illustrates one such hypothetical outcome, where the three WEST Coast states adopt a shared mass

- based system, while all inland western states adopt a shared rate

- based target.454 Commenter s noted that the average effect of the policy on plant

- level variable operating costs (as perceived by firms) is lower under the hybrid scenario as compared to the scenario that features a regional emissions cap, and this is true in both the mass

- based and rate

- based states. Intuitively,
commenter s 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, commenter s said we should expect to see a re

- allocat ion of production towards the rate

- based states because the rate

based regulation subsidizes gas production. Commenter s 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, commenter s noted, increasing imports from rate

- based states becomes a low

- cost option for complying with the mass

- based standard imposed by the coastal region.

Also, according to commenter s , the states may face strong incentives to choose different compliance approaches (i.e., rate

- versus mass

- based). Setting aside concerns about the administrative and process costs of coordinating compliance across states, commenter s said that regional coordination is not the most likely outcome given incompatibilities in economic incentives. Notably, commenter s said, it can be in a state's interest to choose the opposite regulatory mechanism as their neighbors, and this is true regardless of whether carbon allowances a re traded between the states. According to commenter s , Figure 3 illustrates this point quite clearly. Commenter s noted that, conditional on the coastal region adopting a mass

based standard, the inland states will want to adopt a rate

- based standard in ord er to enhance their opportunity to increase exports to the mass

- based states. Commenter s added that the coastal states will benefit from increasing imports from the inland states because this reduces the cost of complying with the mass

- based standard. In o ther words, commenter s 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 export power that could lower their own individual compliance c osts.

Comment 6: Several commenters said that the "regional" approach to natural gas is inconsistent with energy markets and exceeds the EPA's authority.

Response 6: EPA disagrees. The final rule is consistent with regional economic dispatch as practiced by RTOs and other system operators. The final rule is consistent with existing forms of environmental regulations that are currently fully incorporated into system planning and dispatch, from long term planning to short term dispatch decisions. The fina l 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 discussion 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:

Commenter s said that the EPA's proposal to redispatch to NGCCs, whether on a state

- by

- state basis or on a regional basis, impermissibly intrudes upon the exc lusive jurisdiction of FERC455 under the FPA. Commenters agreed that the EPA does not have the legal authority to control dispatch of electricity to the grid. Commenters stated that the proposed regional approach is an arbitrary, artificial way to increase th e stringency 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 goal of accommodating the differences in state generation mi xes.

Commenter s said that a regional approach poses significant complexity with respect to how regions would be determined as well as the allocation of shares to states within each region. Commenter s added that a regional approach would add another subjective element to the goal computation. Commenter s stated that the EPA has not provided any details on how regions would be determined or how shares would be allocated among the states within a region. If a regional approach is used to determine NGCC capacity availability, commenter s said, a regional approach must also be used to determine how much coal

- based generation is available to be displaced. Finally, commenter s noted that the electric system is p lanned and built as an organized and coordinated structure, largely independent of state boundaries.

Commenter s added that their analysis showed that applying BB2 on a regional basis would reduce the amount of coal generation remaining after redispatch in the West region from 109 million MWh to 21 million MWh. Commenter s believe d that such a drastic reduction by 2020 or even 2030 would be completely inconsistent with section 111(d) and the EPA's goal of maintaining the reliability and affordability of the electric system.

Commenters stated that the proposal to redispatch NGCCs across a region is unreasonable, because it fails to consider limitations on the states' abilities to mandate redispatch to natural gas. Commenter s said that it is not reasonable to c onsider regional scenarios when establishing goals for state plans. Commenter s believe d that changing economic dispatch to environmental dispatch of specific EGUs, which is integral to the EPA's unique attempt to move outside the fence to effect CO2 reduct ions, is an extreme and unwise move away from the existing dispatch scenario. Commenter s 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 env ision on a regional level. Commenter s agreed that this proposal would be difficult to accomplish without robust analysis of the supporting infrastructure that would make such dispatch feasible, and a regional approach to dispatch is not warranted under thi s proposal.

Commenter s explained that System Operators generally dispatch electricity regionally on a least

cost basis, so states whose transmission facilities are under the operational control of an RTO or ISO cannot unilaterally impose redispatch to natu ral gas. Commenter s 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 natura l gas. However, commenter s said, there is no way for a state to know the prices at which other states, who also would be motivated to bid generation from coal into the market at a high price to discourage its dispatch, are bidding in their coal

- fired units

. Commenter s concluded that individual states would have no way to ensure that their coal generation is bid into the system at a price that results in the level of dispatch needed to comply with the state goal.456 Commenter s said that the only way in which st ates could ensure that all coal

- fired generation is fairly and predictably dispatched across an RTO or ISO is by entering into voluntary, multi

- state contracts. Commenter s said that these contracts must include all states in the RTO or ISO region
to ensure that all coal

- fired generation is bid into the market at the same price, but this would be difficult, if not impossible, for states located in multiple RTO or ISO regions. Commenter s described an example of such states that would have to enter into multiple state plans, which the
commenter s thought was unrealistic.

Commenter s said that the EPA's approach ignores the ownership of NGCC units, and it assumes that the utilities that own f ossil steam generation will be able to purchase energy from NGCC merchant generators. Applying Building Block 2 on a regional basis would exacerbate this problem commenter s added. Commenter s concluded that a regional approach would presume that a state rel iant 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 surrounding states, commenter s said that this may not be possible even if the necessary infrastructure were in place.

Commenter s said that resource selections are determined, in part, on a utility's customer load. According to commenter s , new resources are added only if there is suffic ient load to justify the need for additional resources or in response to a state's energy policies. Commenter s stated that the proposed regional approach reduces states' flexibility to accomplish emission reductions and could force customers to pay for add itional resources simply to accomplish a shift to natural gas resources. Commenter s added that a regional approach may also serve to discourage increased utilization of renewable energy and end

- use energy efficiency programs. Commenters ’ experience in deve loping and operating renewable energy over the last decade demonstrates that significant emission reductions can be achieved without dictating quotas for certain types of generating resources. Maintaining this flexibility in resource planning is critical f or states and utilities as they implement the final rule commenter s concluded.

According to commenter s , calculating Building Block 2 values on a regional basis would be complex, and the EPA has not provided any details on how regions would be determined o r how shares would be allocated among the states within a region. In the BSER formulation,
commenter s said, the EPA treats natural gas and coal generation as two sides of the same coin; therefore, if a regional approach was used to determine NGCC capacity availability, a regional approach should also be used to determine how much coal

- based generation is available to be displaced.

Commenter s opposed using a regional approach to the application of Building Block 2. Commenter s stated that there are already s erious flaws in the EPA's application of Building Block 2 on a state basis, and using a regional basis would simply exacerbate some of those issues. According to commenter s , a prime example is the failure of the EPA' goal calculation to recognize the impac t on gas pipeline and electric transmission system infrastructure needs that would result within a state if coal generation were to be shifted to existing NGCC. Commenter s said that applying Building Block 2 on a regional basis in the EPA's goal calculatio n model would compound this failure by not considering whether the necessary electric transmission and gas pipeline infrastructure exists to support such interstate energy transfers within whatever region the EPA chose to use.457 Commenter s stated that the ex isting infrastructure for natural gas delivery and electrical transmission may be overstressed by the radical shift called for in Building Block 2 and that reliability and resource adequacy are primary concerns. According to commenter s , the North American Electric Reliability Corporation (NERC) recently completed an evaluation of the impact of the CPP on reliability and resource adequacy. With respect to expanded use of natural gas, commenter s said that the NERC concludes that "[p]ipeline constraints and gr owing gas and electric interdependency challenges impede the electric industry's ability to obtain needed natural gas services," in its November 2014 report titled Potential Reliability Impacts of EPA 's Proposed Clean Power Plan. According to commenter s , the NERC identifies several areas of concern regarding continued reliability of the electrical system, including: 1) the shift toward more natural gas consumption in the power sector will result in a power industry that is increasingly vulnerable to natura l gas supply and transportation risks; 2) more natural gas generation will likely create the need for additional pipelines, which will require sufficient lead time in order to plan, negotiate contracts, permit, procure, and build new pipeline and associate d natural gas processing facilities; 3) additional transmission line capacity will be needed that require sufficient lead times for planning and construction; and 4) impacts on grid reliability will occur requiring additional time to plan and build transmi ssion infrastructure to maintain acceptable margins of reliability assurance.

Commenter s added that the Western Electricity Coordinating Council (WECC), which covers a region that includes Nevada, has undertaken a study of the CPP on regional electrical s ystem reliability and resource adequacy. That study has not been finalized; but commenter s said that the WECC identified areas of concern in an August 2014 project planning document titled, EPA Clean Power Plan: An Overview of WECC's Phased Approach 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, commenter s 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. Co mmenter s 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 goal

- setting needs to be based on each state's individual circumstance s after sufficient analysis of reliability and resource adequacy has been completed.

Commenter s added that the EPA's alternative approach to Building Block 2 calculations amounts to a mandate to burn a minimum amount of natural gas, and the EPA has not mad e a determination that justifies the imposition of a mandate for natural gas use as a component of BSER. Commenter s said that although the mandate would ostensibly be used only to determine the target for Building Block 2, for practical purposes, the actua l implementation of state goals would have to mirror the targets in the other Building Blocks to a very large degree. Commenter s said that any predefined amount of natural gas usage would be arbitrary and would lock states into a specific technology and fu el

- potentially to the detriment of cleaner fuels

- which would further reduce state flexibility and go against principles of fuel neutrality and cost effectiveness.

Comment 7: Commenters generally opposed using a regional approach to building block 2.458 Response 7: EPA disagrees. The final rule is consistent with regional economic dispatch as practiced by RTOs and other system operators. The final rule is consistent with existing forms of environmental regulations that are currently fully incorporated into system planning and dispatch, from long term planning to short term dispatch decisions. The final rule builds on the proposal and includes provisions to support trading mechanisms, both in terms of the BSER and in terms o f planning and implementation

. See the discussion 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 b y calculating it on a regional basis (or modify the way it calculates state goals by imposing a minimum level of re

- dispatch). Commenters believe d that to do so ignores the fact that every state and region has unique generation portfolios that reflect spec ific energy demand requirements and resource availability.

Commenter s similarly did not support the regional approach (or a minimum level of re

- dispatch), preferring the proposed approach under which a state'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. Commenter s stated that it does not seem reasonable or fair to set a state's goal for building 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 commenter s’ stat e (Iowa) and Iowa's utilities have no input or control. Commenter s observed 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 emissions, and asserted that 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 var ying impacts on
states.

Commenters referred to the NODA and stated that, since the ERCOT region is an island located entirely within Texas' borders with very little interconnection 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 path 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 potentia l impacts on Texas, Mississippi and Louisiana and the difficulty for these states to achieve compliance by 2020. Commenters stated that, given the importance of coal to these states, any relaxation of requirements is appreciated; however, what EPA has prop osed in the NODA will ultimately do nothing to alleviate the harms that the Rule Proposal and BSER Block 2 will inflict on these states. Commenter s referred to the NODA and stated that, EPA's proposed revisions to Block 2 stringency are largely illegal, provide little relief to coal

generating units, and may actually increase stringency on coal electricity generators. Commenter s stated that, since th e EPA has not provided specific proposals or explanations regarding the use of natural gas "more comprehensively or holistically," they are unable to comment further.459 Commenter s stated the EPA must consider state

- and source

- specific factors in establishin g the Building Block Two targets. Commenter s objected to the regional approach suggested in the NODA to the extent it would assume NGCC capacity can be made available in a state where such capacity currently does not exist.

Commenter s stated the other Bloc k 2 alternative approaches offered in EPA's NODA should not be applied in the final guidelines because these need to be better justified, details clarified, and outcomes analyzed and issued for public comment. Commenter s stated that requiring a minimum lev el of natural gas dispatch may not be technically supportable as the BSER. Commenters said that the regional approach may not qualify as BSER and/or has not been adequately demonstrated. Commenter s added that the regional approach may not qualify as the BS ER, and it also poses significant complexity with respect to how regions would be determined as well as the allocation of shares to states within each region. Commenter s stated that such a determination is not supportable, since individual states have limi ted existing NGCC capacity and there are constraints on building new capacity.

Commenters stated that there are important local limitations and constraints on distribution and generation that must be accounted for in determining dispatch. As an example, co mmenters 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 from alternative sources can be transmitted to all consumers. Commenter s 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 con ditions that vary 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 reinforced by the numerous errors EPA made in

con nection with the four Building Blocks in the proposed rule.

Comment 8: In comments on the Tribal & Territorial supplemental proposal, commenters stated the Navajo Nation is opposed to either regional application of Building Block 2 goals or setting a min imum level of gas usage for all jurisdictions, as these would require excessive cost and impose severe economic hardship on the Navajo Nation.

Response 8: The EPA decided to not include this provision in the final CPP, as detailed in Section V.A of the fin al rule preamble of the CPP.

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

Commenter s stated the Navajo Nation agrees with EPA that because there are no natural gas combined cycle plants on the Navajo Nation, there is no need to apply Building Block 2. Similarly, commenter s noted that the Navajo Nation economy is highly dependent on the us e of Navajo coal, a tribal trust asset.

Commenter s said that under the Proposed Rule, all states and jurisdictions have the option of participating in a regional section 111(d) program if they believe that it is in their best interest;460 therefore, the EPA d oes not need to require a regional application of any of the building blocks. Commenter s added that the proposed rule allows jurisdictions to establish their own regional trading programs which can help to even out differences between states.

Commenter s st ated that in the proposed supplemental rule EPA correctly concluded that building block 2 is not applicable on the Navajo Nation because 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
commenter s stated that this concept presents numerous achieva bility standards if applied to the Navajo Nation, however EPA should not expand the type of natural gas facilities in its determination of the best system of emission reduction to include coal firing with natural gas. Commenter s oppose d the inclusion of c oal firing natural 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 commenter s stated that the Four Corners units are currently equipped with the ability to combust a small amount of natural gas for start

- up operations and early flame stabilization, however the amount of heat input from natural gas combustion is limited to a small fraction of the total heat input to the units. Commenter s stated that an enormous capital investment to modify the boilers and increase the natural gas supply infrastructure which would also take numerous years to complete, would be necessary to achieve a material reduction in carbon emissions f rom coal firing natural gas and such actions simply cannot be rationalized or cost justified.

Comment 9: Through RGGI, commenter s asserted that participating states implement coordinated CO2 emission budget trading programs that, in aggregate, establish an overall limit on allowable CO2 emissions from affected EGUs in the participating states.

Response 9: The EPA decided to not inc lude this provision 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:

The commenter s stated that RGGI already provide a framework 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 programs. For example, the commenter s noted that from 2009

- 2012, the 9 RGGI states have invested auction proceeds of more than $700 million in programs that lower costs for energy consumers 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.pdf).

Commenter s asserted that while the EPA cites RGGI as an example of a model program, the RGGI states voluntarily adopted a multi

- state program that taxes emissions of CO 2 , but Congress ha s not provided the authority to the EPA to tax CO 2 emissions, nor can the EPA force states to tax CO 2 emissions. Commenter s stated that the EPA should not use the RGGI approach as an461 example program since the RGGI approach relies on voluntary carbon taxes that cannot be legally forced upon a state.

Commenter s cited recent FERC testimony before Congress 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 like, and we also don't have a sense for what a Federal implementation plan or a Federal compliance plan would look like."

Commenter s stated that, although the EPA has said that the y will offer flexibility to states, potential plans seem to rely in some part on a combination of cap and trade, like a regional gas house initiative like they have in the northeast, some sort of reliance on energy efficiency and demand response resources, a shuttering of coal plants and, at the same time, pivoting towards heavier reliance on natural gas, perhaps some sort of renewable portfolio standard in the state. Commenter s stated this looks like what one of the regions, New England, has already been g oing through.

To implement a regional approach, commenter s 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 re liability system and sometimes very high cost for electricity aren't exported to other regions of the country, and overcoming that could be a challenge. Commenter s concluded that the national experts charged with reliability, FERC, recognized the RGGI prog ram has experienced growing pains as it was implemented. Commenter s 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: Commenter s noted that the proposal to use a regional approach, combined with the rule's promotion of nuclear as an emissions

- reducing resource and the concern placed on preserving existing capacity, opens up the possibility that states would turn to regional emissio ns programs that permit use of nuclear as an offset to fossil fuel generation.

Response 10: The EPA decided to not include this provision 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:

Commenter s stated that such programs would both limit the extent of CO 2 emission reductions by providing an alternative regulatory compliance mechanism for fossil fuel plants, and they would limit the growth potential of renewables by flooding the market with emissions credits. Commenter s stated that replacement of state rene wable portfolio standards with so

- called "clean" energy standards that include nuclear would have a similar effect.462 Commenter s described previous efforts to create regional emissions

- reduction programs, but none of them reached fruition. Commenter s noted t hat the long

- established opposition to renewable energy and emissions regulations in the Southeast and the unique level of commitment among states in the region to developing new nuclear, could provide conditions for regional implementation plans that util ize nuclear as a primary compliance mechanism for achieving state goals. In so doing, commenter s said, states may be able to achieve the goals, not by reducing CO 2 emissions significantly, but by "diluting" their emissions rate with additional nuclear capa city. According to commenter s , this possibility 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 accur ate calculation of the costs and environmental impacts of nuclear could create a biased yardstick by which to evaluate state implementation plans.

Commenter s recognized that regional approaches may be advantageous, especially considering that all but five states participate in RTOs with interconnected electricity grids. Even though establishing a regional emissions program would relieve states of none of their obligations to meet the CPP's mandated emissions goals, commenter s said that the adoption of regio nal compacts that utilize emissions offsets and non

- BSER resources could encourage the preservation of fossil fuel generation sources and uneconomical low

- /zero

- carbon resources. Such an outcome could both limit emissions reductions that would otherwise be possible and lead states to put off investments in new infrastructure and innovation, commenter s added, leaving them unprepared to make deeper reductions in emissions after 2030. Commenter s encouraged the EPA to set forth guidelines for how states may str ucture regional greenhouse gas programs to reflect best practices and to optimize emissions reductions and cost

- effectiveness. Commenter s stressed that programs that adopt emissions offsets should be strictly limited, and those that include nuclear as an o ffset option should be disqualified.

Commenter s said that the draft rule notes that rate

- based approaches could result in nuclear power receiving disproportionate support over renewables, but does not set a guideline or standard to regulate the extent of r eliance on nuclear in states' implementation plans. Without such guidance, commenter s were concerned existing reactors would receive benefits that are intended to support deployment of sustainable technology, drive innovation, and produce cost efficiencies and that could distort renewable energy credit (REC) markets. Commenter s said that the draft rule's incorporation of 6% of states' existing nuclear capacity in the computation of state goals would encourage states to include nuclear as an offset in such p rograms. According to
commenter s , that would require states to set higher offset limits, in order to credit resources that are effective at reducing emissions or converting or removing greenhouse gases from the atmosphere. Doing so, commenter s said, would effectively increase the amount of carbon emissions by enabling fossil fuel generation sources to buy their way to compliance rather than by reducing emissions. In states such as Illinois and South Carolina, in which nuclear approaches 50% of the states' e lectricity generation, commenter s noted that just 6% of nuclear would account for nearly all of the 3.3% of CO 2 emissions from fossil fuel generation sources

- without, however, removing a single pound of CO 2 from the atmosphere. Even in states with lower proportions of nuclear capacity, commenter s added, the effect would be the same, just to a lesser degree. Commenter s stated that the EPA may not be able to directly regulate regional emissions compacts under the CPP, but it can define the way in which meas ures states include in their CAA section 111(d) implementation plans are credited toward compliance. In the final rule,463 commenter s concluded, the EPA should establish guidelines defining what aspects of regional emissions programs will count toward complia nce.

Comment 11: Commenters noted a recent FERC Order recently upheld by the U.S. Court of Appeals for the DC Circuit which updated and enhanced 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:

Commenter s said that the U.S. Court of Appeals for the DC Circuit recently unanimously uphel d FERC Order 1000, which updated and enhanced requirements 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 Blocks 2, 3 and 4 as well as costs for states with utilities subject to FERC jurisdiction. South Carolina Public Service Authority v. F.E.R.C., Cause No. 12

- 1232, decided August 15, 2014 (D.C. Ct. App. 2014). Commenter s said that it is unclear whether the EPA assessed the impa cts of FERC Order 1000 and other FERC orders in its evaluation of building blocks 2, 3 and 4, particularly with respect to cost impacts to utilities and consumers. Commenter s added that since FERC jurisdiction is limited in Texas, not all Texas utilities a re subject to FERC Order 1000, which should be considered by the EPA in evaluating the potential emission reductions attributable to building Blocks 2, 3, and 4.

Comment 12: Commenter s did not believe that defining regional renewables targets will address the problem with cross

- state crediting, as states may choose to fund renewable energy projects outside of regions with which they have an agreement for their SIP.

Response 12: The EPA decided to not include this provision 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:

Commenter s said that having pre

- defined regions would reduce flexibility and limit the cost

effective options available to states. In order to address the issues raised by stakeholders with crediting in

- state generation purchased by other states, commenter s said tha t the EPA should allow states with renewable resources to net their renewable generation sold out

- of

- state against their targets. Commenter s said that this approach will allow compliance while also avoiding double

- counting.464 Comment 13: Commenter s believe that the alternative regional approach 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 commenter s . In response to additional analysis and many comments, we have modified the proposal and RIA . The Building Blocks are not prescriptive but the EPA believes that the 111(d) final rule establishes reasonable CO2 emission performance rates. The rule require s 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, 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.A, 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 Rule supporting the final CPP

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

Commenter s suggested that, for reasons of burden

- sharing, the EPA should adopt a minimum performance level requirement for coal

- fired EGUs commiserate with a 20% reduction in emissions intensity for coal. Commenter s stated that this value is about 1.75 lb/kWh and

re commended this in place of the proposed reassignment of NGCC capacity to states currently without NGCC.

Comment 14: Commenter s stated the proposed rule places Florida in a southeast region with Kentucky, North Carolina, South Carolina, Tennessee, Mississi ppi, Alabama, and Georgia.

Response 14: The EPA decided to not include this provision 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:

Commenter s stated Florida's import transmission capability is limited to approximately 3,800 MW, or 6.6% of total capacity. Commenter s concluded that Florida's geographical location and corresponding energy import limitations should minimize reliance on r egional dispatch hypotheticals and confine Florida's redispatch increases (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 ap proach to BB2 would work.465 Response 15: The EPA decided to not include this provision 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:

Although this approach might better resemble the way 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 transmission capacity among states, how the approach would impact individual state goals, how regional NGCC resources would be allocated in the context of individual state compliance det erminations, how it will address the fact that different ownership structures and contractual arrangements for NGCC facilities will affect each unit's ability to reduce the need for other generation elsewhere, and other questions. Commenters stated that th e EPA must provide the required technical and economic analyses before proceeding with a regional approach. Commenters added that in addition to providing more information, the EPA must solicit additional comment on this proposal before deciding to adopt i t in the final rule. Commenter s 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 would be applicable based on application of the regional approach and other building blocks.

Commenters added that because the EPA lacks the authority to require redispatch, it is precluded from setting standards in any final rule utilizing this approach.

Commenter s stated that a crit ical 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. Commenter s indicated that the EPA suggests that regional implementation is viable,

r eferencing specifically the northeastern RGGI or California's cap and trade program (which has been made available to regional and Canadian participants), both of which are voluntary programs that the states have adopted, but says nothing about whether or what changes to these existing programs would be necessary to meet the proposed requirements. Commenter s identified two issues with the California program: (1) they assign carbon emissions from imports to the state to the first seller in the state, which w ould 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. Commenter s also noted that RGGI uses a mass

- based emissions target that is regionally based and does not require individual states to meet state emission targets as long as they have bought sufficient credits from someone else in the region. Commenter s asserted that the EPA should provide further guidance in its final rule on how existing regional frameworks need to be modified and how or if new regional frameworks can be established.

3.2.10 Setting a f F loor

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 to this subsection which are organized by topics (comments) below. Responses are provided for these topics.466 Comment 1: Commenters express ed s upport for setting a floor for NGCC redispatch

Response 1: 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:

Some commenters supported the alternative approach the EPA proposed, in which a minimum level of generation shi ft from coal to gas would be adopted for each state. Commenters stated that it is important to take advantage of the potential 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 occur in all states with coal

- generation, not just those with underutilized existing NGCC capacity. Commenter s urged EPA to consider ramp rates up to and including a continuation of a 5% per year shift rate, the 1

- year historic average. Commenter s supported setting the minimum floor at the 12% suggested by EPA in the NODA.

Commenters recommended that the EPA adopt as a component of BSER, a minimum level of generation shift from higher

- emitting to lower

- emitting 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 electric and natural gas sector modeling. Commenters stated the EPA should as sume that at least 2% of a state's coal use shifts to natural 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

- utilized existing NGCC capacity in a state (or other pathways of coal to gas transition) would allow for a greater redispatch between coal and gas, that higher level should be used to set the state'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 stated that the EPA must maintain symmetry between the target setting and compliance.

Commenters asserted that states (and likely sources) will have significant flexibilit y in choosing which combination of measures to employ to meet their applicable targets and indicated they will urge states to rely as much as possible on efficiency and renewables to achieve compliance, in order to avoid or limit expanded reliance on natur al gas. Commenter s 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 flexibility is carried through in the final rule.

Comment 4 2 : Commenters stated that they do not believe that the EPA should establish a minimum value as a floor for the amount of generation shift that can be achieved via Building Block 2.467 Response 4 2 : In the final rule, the EPA does not use the floor approach to Building Block 2. See Preamble Section V.D for Building Block 2 and Sections VI and VII for determination of performance rates and state goals.

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

Some commenters did not support the setting of a minimum level as the EPA proposed. Commenters stated the suggested BB2 alternatives in the NODA are unlawful, unsupported, and unworkable. Commenters believed EPA's alternative s are equally, if not more, unjustified than the originally proposed BB2. This commenters objected 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 accurately 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

accura tely project the development of new NGCCs. The commenters stated that any mandated shift in generation, from coal

- fired units to natural gas

- fired units, is thus arbitrary.

Commenters indicated that in section III.B.1 of the NODA, the EPA identified a pote ntial approach regarding additional use of natural gas under 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 approach from the June 2014 proposal, in which regional availability of NGCC generation would be considered, rather than just in

- state availability of NGCC generation, when setting building block 2 targets.

Commenters indicated that it did not support either of th e alternative approaches. Under the EPA's proposed approach, a state's baseline and goals 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 powe r plants, not new ones, the commenters said. Given this, it does not seem reasonable or fair to set a state's goal for building block 2 premised on shifting generation to NGCC units that do not exist in the state based on the amount of NGCC generation in a nother state, in the commenters’ opinion. The commenters believed it also does not seem reasonable or fair to base a state's goals on a theoretical potential 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 emissions. The commen ters 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.

Com menters stated the EPA should not modify the way it calculates state goals by imposing a minimum level of redispatch or redefine BB2 by calculating it on a regional basis because that would ignore the fact that every state and region has unique generation portfolios that reflect specific energy demand requirements and resource availability. Commenters believed, as proposed in the NODA, EPA's new approach mandates burning a minimum amount of natural gas with no determination justifying the imposition of natu ral gas use as a component of BSER.468 Moreover, the commenters stated that although the mandate would ostensibly be used only to determine the target for BB2, for all practical purposes, the actual implementation of state goals would have to mirror the targe ts in the other building 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 to the detriment of cleaner fuels

- further red ucing state flexibility and against principles of fuel neutrality and cost

- effectiveness.

Commenters recommended the BSER determination should 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 wher e there are reliable coal

- fired generation units with useful lives beyond the BB2 phase

- in period of 2020

- 2029. The commenters were concerned that a minimum level of NGCC utilization would create market distortions, preventing a utility from providing the least

- cost resources to its consumers, especially during times of natural gas price volatility, and would increase prices. The commenters stated that a floor would require a significant build out of electricity generation and transmission, as well as the n atural 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 floor 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 utilize NGCC technology.

Commenters said BB2 punishes states that burn more natural gas for electricity generation and rewards states that burn les s, and that EPA is seeking to fix this by forcing redispatch to NGCC units that do not exist. The commenters believed the only reasonable solution to BB2 is to remove it (along with the other three building blocks) 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 calculating it on a regional basis because every state and region has unique generation portfolios that re flect specific energy demand requirements and resource availability.

Commenters recognized that requiring a minimum could help ensure overall U.S. grid reliability, but stated that given the potential costs associated 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 Pacific Northwest may require the development of additional natural gas

- fired generation to compensate for the lim ited 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 margin 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 nec essary if the proposed baseline and emission

- rates proposed for Pacific Northwest states were modified to accommodate the region's dependence on hydropower generation. The469 commenters said that review and decisions related to generation resource planning in frastructure are best led by existing authorities in concert with utilities.

Commenters supported the inclusion of new NGCC in BB2, but asserted that the proposed 12% floor for redispatch in states with low or no existing NGCC capacity would have limited i mpact. The commenters declared that its analysis indicates that the proposed 12% floor would only apply to nine states and add a small amount of additional NGCC generation

- about 30,000 GWh nationwide. The commenters suggested that, in lieu of a floor, EP A consider deriving new state NGCC capacity targets using the national compound average 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 pipe lines, as well as the potential to re

- power existing coal EGUs..

Commenters noted that Wyoming has little NGCC generating capacity and stated that it is not clear why this disparity should be an administrative 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 than adopting an arbitrary minimum for gas consumption, the commenters stated it makes more sense to develop a complete und erstanding of those difficulties and address them. Commenters referred to their letter to the EPA dated December 16, 2013 and stated that, while the premature closure of coal fired EGUs will likely result in the construction of new NGCC capacity to meet ex isting demand, it is not clear whether this new NGCC capacity would or should be constructed 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 rather than coal, which is not a replacement of the existing unit with an NGCC unit, and it is not a use of gas that is in any way the efficiency equivalent of a new NGCC unit. Commenters added that the most recent construction by PacifiCorp of n ew 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 material ly altering the scale of the task confronting the state. The commenters believed the entire section 111(d) program will cause a contraction of Wyoming's economy, due to the impact on its coal industry, the premature retirement of a major portion of its coa l 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 Wyoming electricity sales in 2012.

According to commenters, such a mandate restricts the abi lity for states to identify flexible compliance mechanisms by dictating certain resource utilization outcomes. Commenters concluded that such determinations do not fall within the scope of the EPA's authority under the Clean Air Act, with commenters adding that such determinations are the purview of state utility regulators. Commenters said that the EPA should consider 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 states without existing NGCC units, by the building block 2 requirements.

Commenters added that this area of the NODA reflects a misunderstanding of the manner in which deregulated energy markets operate, and that EPA coul d only recognize new NGCC in470 their feasibility projections via a carbon tax through IPM, which the commenters fundamentally disagreed with. The commenters stated that the concept of a minimum "floor" level for generation shifting, and Building Block 2 in i ts entirety, must be abandoned.

Commenters recommended that EPA not include new NGCC into section 111(d) target setting or compliance. The commenters supported EPA allowing the segment of new NGCC generation that outperforms the section 111(b) NSPS to 'cou nt' 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 setting for EPA's proposed 70% capacity factor target for existing NGCC. The com menters added that EPA should eliminate the BB2 target component for Minnesota, giving deference to the Minnesota established Integrated Resource Planning process, which is already giving consideration to fuel diversity, cost and environmental profile, inc luding 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 determinations.

Commenters stated that RTOs may b e required to accelerate development of NGCC facilities to meet the re

- dispatch requirements of BB2 without assurances that the 70% utilization rate under BB2 can be met.

Commenters recommended that EPA allow NGCC units under planning and construction that are not subject to EPA's 111(b) requirements to emit CO2 annual emissions reflecting unimpeded operation across their full operating range. The commenters added that this sort of unimpeded planning and operation would be allowed if the unit was subject to 111(b) NSPS requirements 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 construct ion 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 p opulation of generating units and represent good CO2 emitting performance regardless of CO2 NSPS not being applicable. The commenters said that EPA should, in turn, allow the units to operate unimpeded by CPP requirements currently under proposal.

Comment ers recommended that the EPA eliminate its Block 2 requirements of imposing greater Block 2 targeted natural gas dispatch on less impacted states (e.g., assigning a minimum portion of state generation to NGCC) completely for states that utilize an integrat ed resource planning (IRP) process, allowing power market conditions to continue to establish optimal least

- cost conditions for dispatching natural gas resources. For states without an IRP process, commenters said that the EPA should eliminate the portion of prospective existing NGCC capacity factor dispatch that supports preserving electric system reliability, operating intermittent renewable energy resources, or for service periods during which NGCC serves peak customer demand, system reserve requirements and system spinning reserve 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 near zero at least until new NGCC generation is deplo yed that is able to replace the services of existing NGCC, considering that today's IRP471 deployments and wholesale markets show optimized performance at existing NGCC utilization levels.

Commenters said that the aspects of the NODA for which comment were so ught 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. The commenters said that it appears any easing of the interim goals will be offset with stri cter goals 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 recalculating state goals or offset the growth opportunities that m ay be afforded in BBs 3 and 4.

Commenters were concerned that inclusion of a minimum level of natural gas co

- firing and new NGCC deployment as components of the BSER would raise the cost of the Proposed Rule considerably and potentially expose the rule t o increased legal risk. Commenters were also concerned with additional risks that might compromise electric reliability or complicate compliance with local, regional, or state regulations. Commenters said that, according to the EPA, the cost of reducing em issions through re

- dispatch 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

- fi ring for states with low Block 2 requirements do not trigger corresponding reductions in emissions targets for states with little or no NGCC generating capacity, then EPA will essentially be punishing low

- NGCC states as a means to merely appease high

- NGCC capacity states, which is not only inequitable, but is simply not allowed by the CAA. The commenters stated that although some states are treated inequitably under the Rule Proposal, EPA should not increase the stringency of guidelines in low

- NGCC states t o eliminate "significant disparities" between states. The commenters stated that the Rule Proposal puts states in competition for an arbitrarily limited amount of allowable CO2 emissions, with the agency illegally placed as an arbiter of fairness and equit y, a situation which is neither codified nor contemplated in any regulatory 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. Commenters stated t he EPA should not adopt the suggestions advanced in the NODA to expand the definition of the NGCC fleet to include co

firing or new NGCC units in states' baselines (79 FR 64549

- 50).

Comment 2 3 : C ommenter s agreed with NODA approach for minimum floor of 12% on a regional basis.

Response 2 3 : 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:

Commenter s stated the block 2 & 3 goals are inequitable and require more of states that have already heavily invested in NGCC and RE, such as Texas, while requiring relatively less from472 those states that have not, such as Kentucky. The commenter s believe d that due to the interconnected nature of electricity markets, EPA should reapportion the emissions reduction obligation, increasing the stringency of the goal for states like Kentucky while reducing the stringency of the goal for states like Texa s, which has significant under

- utilized NGCC capacity. The commenter s 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 bur den by an equivalent amount for those states with higher amounts of NGCC capacity. The commenter s believe d that the minimum value of 12% suggested by EPA in the NODA appears reasonable and should be established on a regional basis. The commenter s stated th at by basing the minimum floor on a regional basis, 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 4 : Comm enter s expressed o pposition to setting a floor for the Navajo Nation.

Response 3 4 : 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:

In comments on the Tribes and Territories supplemental proposal, c ommenter s 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 capacity because try ing to apply a minimum transition to natural gas in an effort to achieve more of a "one size fits all" approach to BB2 ignores the costs and availability of fuels in a given state and the necessary infrastructure to deliver it. For example, the commenter s asserted Navajo Nation coal is local to the mine and, at roughly $5/ton, costs only about $0.28/MMBtu. The commenter s believe d the suggested "one size fits all" approach ignores the recent investments that have been made in coal generation and would push m ore coal generation (and the associated investments) toward an uneconomic state with stranded assets. The commenter s added that the "one size fits all" approach ignores recent investments made in coal generation and would push more coal generation and asso ciated investments, toward an uneconomic state with stranded assets.

Comment 4 5 : Commenter s state d that t he EPA should not adopt the "minimum level of generation shift" concept.

Response 4 5 : 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:

Commenter s stated that because the Tribes and Territories Supplemental Proposal incorporates concepts introduced in the CPP, including its NODA , it is important to address the concept of473 "generation shift" within these comments in the context of the EPA's acknowledgment that there are no NGCCs on the Navajo Nation. The commenter s opposed the use of a minimum level of NGCC generation, whether that is in the form of existing or new NGCC units as part of BB2. The commenter s 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
commenter s stated these units can combust a small amount of natural gas for startup operations and early flame stabilization, but the amount of heat input from natural gas combustion is limited to a small fraction of the total heat input to the units. The commenter s asserted that achieving a material reduction in carbon emissions from co

- firing would require an enormous capital investment to modify the boilers and increase the natural gas supply infrastructure. The
commenter s believe d this effort not cost justified, especially considering the extremely small load demand in the Navajo Nation. The commenter s stated that the EPA should not expand the types of natural gas facilities in its determination of BSER to include co

- firing natural gas.

Comment 5 6 : Commenters expressed o ppos ition to setting a floor based on national averages

, suggest e stablish ing a floor on a state

- by

- state basis.

Response 5 6 : 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:

Commenter s 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 commenter s believe d BB2 targets must consider each state's individual circumstances and not be based on a national average. If the EPA is determined to establish BB2 targets based on the na tional average, the commenter s stated the EPA should hold the total level of gas use the same, thereby increasing the BB2 requirement for states with little or no NGCC capacity and simultaneously reducing the requirement for states with excess capacity. Th e commenter s believe d this approach would 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 equitable treatment.

Commenter s s tated that EPA should limit the amount of anticipated NGCC redispatch under BB2 for New York (and similarly

- situated states) due to constraints that limit the ability of these states to implement BB2. The commenter s suggested the EPA establish a floor base d on a percent of total in

- state generation after the application of BB2: for example, a collective floor of 12% coal and oil/gas steam units based on total generation, and then not apply the NGCC redispatch component of BB2 beyond that level.

The comment er s stated the EPA could limit this provision to those states demonstrating that system constraints or reliability requirements prevent them from achieving the level of redispatch initially anticipated by BB2. The commenter s believe d this approach would ac hieve the greatest level of dispatch realistically supported by existing fossil sources while allowing states the flexibility to meet reliability and gas/electric system constraints, and maintain some amount of474 ongoing fuel diversity. Consistent with the N ODA, according the commenter s , 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 on e

- third of that amount, reducing the amount generated by oil/gas or coal units to 12% of its total generation. Alternatively, the commenter s suggested the EPA could limit the application of BB2 to New York in recognition of the geographic and system topolo gy constraints of NY's electricity system.

Comment 6 7 : Commenter s state d i nfrastructure concerns and question ed the definition of "region".

Response 6 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:

Commenter s believe d adopting a floor will increase pressure to add new generation in states that currently have no NGCCs and that if the EPA does adopt a floor that it not be initiated until necessary infrastructure to interconnect and deliver new generation resources is in place. If the EPA decides to consider regional availability in the establishment of BB2 targets, the
commenter s believe d the definition of "region" should be based on the boundaries of organized markets since this best matches how generation is dispatched and how enabling transmission infrastructure is planned.

Comment 7 8 : Commenter s state d t he starting point for the EPA's revised analysis of the CO2 effects of redispatch in 2020 should be no lower than the historical maximum capacity factor for NGCC.

Response 7 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:

Commenter s 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, the Agency will need to determine the amount of NGCC capacity achievable by 2020. C ommenter s recommended that the EPA s elect a maximum utilization/capacity factor that is no lower than the level that each state or region has achieved historically. C ommenter s specifically recommended that the EPA use the average of the highest monthly utilization/capacity factors achieved d uring the winter and summer seasons during the years 2011 through 2013 in calculating the portion of the CO 2 emissions reductions targets achievable through BB2 redispatch. C ommenter s state d this would reflect the times of greatest NGCC production during t he multi

- year period for which the EPA has real information,475 and would also take into account the differing availability of pipeline capacity during the winter and summer seasons.

Comment 8 9 : Commenter s state d questions regarding goal recalculation.

Response 8 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:

Commenter s asked if the EPA will recalculate the mass goal for each state and communicate the result before the state plan deadline, if an NGCC floor is established in the final rule. C ommenter s also asked if the number goal will be less than that included in the or iginal proposal if the RE/EE fossil offset is established in the final rule.

Comment 9 10 : Set natural gas ramp rate at 5% per year.

Response 9 10 : 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:

C ommenters urged the EPA to consider natural gas generation increases (i.e., ramp rate) of 5% per year, the historical average over the last 10 years, when considering gas and electricity pr ices in the evaluation of the total costs of the BSER targets. Additionally, commenter s stated that the ramp rate should reflect the needs for additional infrastructure to support increased gas use through the three respective pathways, which may be differ ent for the different pathways. Commenter s added that it had assessed a more conservative 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
commenter s did not have time to co mplete additional modeling at higher ramp rates. Nonetheless, commenter s urged the EPA to consider higher shift rates, up to and including a continuation of 5%, the 10

- year historic rate.

Comment 10 1 1 : Commenter s suggested a dopt ion of a minimum 2% annual conversion rate for Tribal Nations and U.S. Territories.

Response 10 1 1 : 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:476 Regarding the Tribal and Territories Supplementary Rule, commenter s urged that the EPA, in setting the targets for power plants in Indian Country and U.S. territories, apply the 2% annual conversion. This approach or some other approach that incorporates the opportunity for switching to lower

- emitting fuels and achieves e quivalent or greater reductions is particularly important, according to the commenter s , given that BB2 would not otherwise apply to these facilities given the lack of existing NGCC plants in these jurisdictions. The commenter s asserted lack of existing fac ilities within the jurisdiction does not reflect a reduced opportunity to switch to lower

- emitting fuel sources.

Comment 11 1 2 : Commenters express ed s upport and opposition to redispatch approaches in the NODA.

Response 11 1 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:

Commenter s stated that there is significant opportunity to reduce emissions from affected sources by shifting to natural gas generation in all three ways noted by the EPA

- shifting generation to existing NGCC units with additional capacity, shifting generation to n ew NGCC units or by co

- firing, and by repowering existing coal

- fired EGUs with natural gas. The
commenter s 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 ov erall approach and would better reflect the actual system that states have used to achieve emission reductions.

C ommenters opposed the redispatch approaches in the NODA. Commenter s opposed the redispatch approaches as well as the proposed alternative appro ach and co

- firing as a consideration in lieu of, or addition to shifting from coal to natural gas. The commenter s believe d the approaches could make the goals less achievable. The commenter s asserted new resources are developed based on demand, cost and cu rrent conditions, thus it is not possible for EPA to develop realistic assumptions regarding development of natural gas resources through 2030. Even if it were possible, the commenter s stated it would be infeasible to apply on a uniform basis across states . The commenter s appreciated EPA attempting to create greater equity between states in terms of goals but believed introducing inherently arbitrary assumptions will create different inequities between states.

Commenter s stated the BB2 alternative approache s in the NODA should not be applied in the final guidelines because these need to be better justified, details clarified, and outcomes analyzed and issued for public comment. In particular, the commenter s believe d requiring a minimum level of natural gas d ispatch may not be technically supportable as the BSER.

Comment 12 1 3 : C ommenter s noted negative impacts of co

- firing.477 Response 12 1 3 : 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:

Commenter s stated that co

- firing natural gas with coal, as discussed in the NODA, would require significant investment, leading to higher cost of electricity. The commenter s stated that contrary to the assumption used in the EPA's analysis that coal

- fired units run at full load and could benefit from co

- firing, most units do not run at full load. The commenter s also stated that moving coal

- fired or co

- fired units away from ba seload operations into more of an intermediate or load following mode will decrease any gains in power plant efficiency envisioned in Building Block 1. The commenter s stated that ramping co

- fired units 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 1 4 : Projected emission rates for gas

- fired EGUs should be based on combined cycle turbines.

Response 13 1 4 : 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:

Commenter s supported the Agency's decision not to include 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 emission rates from gas

- fired EGUs. The
commenter s stated their own analysis found that only 18 of 583 gas

- fired EGUs had heat rates that exceeded 250 MMBtu/hr and a 5

- year average gross generation greater than 240,000 MW

hr, which are the criteria EPA used to identify gas

- fired units included in its proposal.

Comment 14 1 5 : Any 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

Response 14 1 5 : 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:

Commenter s stated that if the EPA expands BB2 to include some minimum level of generation shift from higher

- emitting to lower emitting sources for all states containing some fossil steam generation, then it should take the path in which the 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 commenter s stated that the EPA's existing proposal already raises substantial concerns about infras tructure adequacy, reliability and478 stranded investments; therefore the commenter s would not be in favor of an expansion of the total amount of re

- dispatch required.

Comment 3 16 : Commenters were concerned about the interplay between BB2 and the CPP's objec tive of encouraging re

- dispatch from higher

- emitting generating units to lower emitting generating units.

Response 3 16 : The EPA has revised the approach to implementing BB2 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 Setting 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 fleet. Commenters said that although it would be feasible to construct new NGCC plants for commissioning on or near the start of the compliance period, building block two on ly considers re

- dispatch to NGCC plants already in operation. Commenters noted that early acting states that have already made substantial progress in phasing out oil and coal generation are faced with the potential economic burden of re

dispatching existi ng 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 address this inequity, where the re

- dispatch is lim ited only by the lack of in

- state NGCC capacity, commenters said that a minimum floor of re

dispatch should be attributed to the states to recognize likely cross state transfers of NGCC generated electricity to even out the compliance burden and more accur ately and equitably set the goals as among regions and states.

3.2.11 Glide Path

This section discusses issues related to the time line for implementation of the CPP and whether a more gradual glide path is needed for building block 2.

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

Comment 1: Some commenters were concerned about the a bility of s tates t o m eet the p roposed
g lide p ath t ime l ine

, while other commenters said that additional time is not needed.

Response 1: The EPA thanks the commenters. The 111(d) final rule requires that states develop plans that establish emission standards for affected EGUs. The rule provides states with substanti al 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,479 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 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 Measures TSD for the CPP Final Rule 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 Proposed Timeline to Comply with the Interim Goals

C ommenters 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.

Commenter s asserted that the proposal tries to do too much too fast. C ommenter s believe d that state limits are too stringent and they offer a wide and differing level of compliance for many different states. Additionally, the commenter s complained that, as others have pointed out, the limits are front loaded, so you really have to actually achieve most of what is required by 2020, not 2030.

Commenter s asserted that additional time is needed to comply with the proposed rule and to allow utilities more flexibility in the near

- term to meet the initial targets, and to lower cost and other impacts on electric utility consumers. According to the co mmenter s , while there may be a perceived glide path between 2020 and 2030, they are concerned that the proposed rule does not address the sharp drop in emissions that must be achieved prior to 2020. C ommenter s reported that, in Arkansas, a 37% decrease in CO2 emissions prior to 2020 must be achieved in order to maintain the average CO2 emission rate of 968 lb/MWh from 2020 through 2029 (estimate assumes that the current emission rate of 1,634 lb/MWh does not change until 2020). C ommenter s reported that Arka nsas 's interim goal for 2020 through 2029 is 968 lb/MWh, and the final goal in 2030 is 910 lb/MWh. C ommenter s reported that, in order to meet the interim goals and 2030 targets, the large majority of emissions reductions must be made prior to 2020. C omment er s stated that, because utility forecasting and generation planning are long

- term prospects, they will effectively have to comply with Building Blocks 1 and 2 prior to 2020, in order to achieve the interim goals.

Commenter s argued that forcing the re

- dis patch of NGCC 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 higher electricity costs to the consumer. According to the comme nter s , during the recent polar vortex, natural gas demand exceeded delivery capacity demonstrating a current need. C ommenter s opined that permitting and construction of additional infrastructure would take more than two or three years to complete. Accordin g to the
commenter s , NERC states in its November 2014 initial 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 2020.480 Commenter s asserted that, without significant changes to the proposal, state plans that comply with it would be all too likely to put reliability at risk by stranding essential as sets, increase power prices dramatically, and cause a stampede of new base

- load natural

- gas fired generation. C ommenter s opined that this wave of new base

- load gas generation would lock

- in levels of new fossil fuel emissions in the US power sector that wou ld make getting on the IPCC pathways to a world with no more than two degree centigrade warming much more difficult, if not impossible.

Commenter s argued that the proposed interim goal eliminates 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 compliance. Commenter s opined that states will have no choice but to make dramatic changes in generation resource dispatch to achie ve near or full compliance with the interim goals by 2020. Moreover, according to commenter s , the constricted timeline will prevent states from cushioning economic impacts from retirements.

According to commenter s , the EPA has overestimated the ability of states to achieve re

- dispatch, and the EPA has proposed interim emissions goals that are so stringent that many states will be required to achieve most of their CO2 emissions reductions by 2020. According to commenter s , given the EPA's proposed timetable f or the approval of state plans, this would leave states at most with approximately 2 years to implement the necessary CO2 reduction measures; a task that they asserted will be extremely difficult or impossible to achieve without severe economic disruption. Commenter s explained that, to determine the interim goal for each state, the EPA assumed that all emission rate reductions from Building Block 1 and Building Block 2 could be achieved at the start of the ten year interim goal compliance period. As a conse quence of this assumption, commenter s 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.

Commenter s further reported that, states with emission 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. According to commenter s , t his is evident from the calculations presented in the EPA's technical support documents, which project that many states will make dramatic changes in generation resource dispatch to achieve near or full compliance with the interim goals in 2020. Commenter s reported that resulting emission rate reduction trajectory resembles a cliff, whereby emissions decrease sharply early in the compliance period and then remain largely unchanged through 2030.

Commenter s argued that states are left with little or no flexi bility to determine a different compliance path to avoid the compliance cliff under EPA's proposed schedule for implementing the Proposed Rule. Commenter s stated that the EPA intends to finalize the proposed rule in 2015, which means that the earliest stat e implementation plans would be approved by EPA is 2017. At most, commenter s asserted, this schedule leaves 2 years for electric generating companies to achieve aggressive emission reductions and for states to make sweeping changes to their existing electr ic generation, transmission, and distribution systems. Given the stringency of the interim goals, commenter s reported that the proposed implementation schedule will force states to adhere to the EPA's anticipated re

- dispatch and coal and oil/gas

- unit closu res to achieve compliance with the goals.481 Commenter s asserted that the interim goals are largely unachievable in their current state for many jurisdictions. C ommenter s stated that, this is in no small part because it requires most of the emissions reduct ions to occur in 2020 via the natural gas re

- dispatch in Building Block 2.

Commenter s asserted that, whether the electric system as a whole can operate with most states' NGCC fleets averaging 70 percent by the early part of the compliance period (as implie d by the goal computation) is uncertain. According to the commenter s , while many states would be able to rapidly increase the utilization of existing NGCC facilities, others may require additional time because of infrastructure constraints, characteristics of existing in

- state generation facilities, or because of their load centers' locations in the electric or gas transmission system. C ommenter s stated that procuring adequate natural gas supplies to sustain a high level of utilization year round could mean , in the case of some states, building new pipelines or increasing the capacity of existing ones. For others, the commenter s stated that getting the electricity to consumers currently served by steam units without expanding transmission may be a challenge. Thus, although the commenter s agreed with EPA's conclusion that, over time, existing fleets will have the technical capability of reaching a 70 percent capacity factor, and agreed with EPA's finding that states could comply with the emission guidelines wi thout 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 as part of the goal

- setting process.

Commenter s opined that the timeline between final state 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 early emission

- reducing measures that would counteract th e EPA's stringent interim goal requirements. Commenter s reported that full re

dispatch by 2020 would be unachievable and bad public policy. Commenter s stated that the EPA claims that its intent in proposing to require compliance with an interim goal is to "provide states with a reasonable glide path to compliance with their final goals by 2030." However, according
to commenter s , EPA fails to explain why interim goals are necessary to achieve the Proposed Guidelines' ultimate goal. Commenter s stated that, al though they do not believe EPA's suggested approaches will significantly alleviate the negative consequences of EPA's proposed interim goals, they urged that, if EPA does not abandon interim goals, the EPA adopt both of these changes in the final guideline s.

Commenter s stated that, as proposed, significant carbon reductions

- 80% of final compliance requirement

-- will be needed by 2020 in order to meet the 2020/2029 interim goals. C ommenter s argued that front loading of reductions by 2020 is particularly problematic because of the short time frame between approval of state plans (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 co mpliance strategies that ensure reliability. In particular the
commenter s expressed concerned that the drastic action required to meet the 2020 interim targets will lead to a major upheaval in the industry and the potential for blackouts.

Commenter s stated that, while the idea of a "glide path" to the final requirements of the year 2030 appears appealing, it would not work. 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 pe riod, the
commenter s believe d that the glide path proposed by the EPA would prematurely and unnecessarily cause an increase in costs borne by their (Minnkota's) member

- owners by shifting482 generation away from coal

- fired plants to more expensive lower emitti ng carbon dioxide sources prematurely.

Commenter s asserted that "overnight." large scale re

- dispatch raises a number of daunting problems in the real world, which they believed were inadequately addressed in EPA's analyses. C ommenter s opined that, in state s with a large number of existing combined cycle units and existing coal plants, such a sudden major re

- dispatch has the potential to create resource adequacy challenges by stranding assets needed for reliability, increasing consumer costs, and, in all lik elihood, leading to unnecessarily large amounts of new natural gas power plant investment and the long term lock

- in of their CO2 emissions. C ommenter s argued that the sudden retirement of most or all coal plants in a state where they make 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 ade quacy crisis in states with much smaller reserve margins. According to the commenter s , such a crisis would almost certainly be met by deployment of new natural gas plants

- whose dispatchable capacity counts toward reserve requirements and whose CO2 emissi ons simply don't count under the proposed rule.

Commenter s 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 implications for the interconnected power system. C ommenter s also asserted that it also reflects the fact that the proposed guidelines do not acknowledge or consider how the interconnected power system works. For example, commente r s stated that the Director of the Arizona DEQ has noted that, "the proposed goals for Arizona were set based upon an EPA assumption that all of our existing coal

- fired power generation could be immediately transferred to existing natural gas

- fired power p lants by 2020." Commenter s reported that Arizona is required to achieve at least 75 percent of its final 2030 goal by 2020. According to commenter s , the DEQ reported that Arizona's only option to achieve this level of reductions by 2020 is through switchin g from coal to natural gas. Commenter s 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 few short years.

Commenter s expressed concern that states will h ave limited flexibility to tailor their implementation plans in ways that (A) make practical and economic sense for each state's circumstances and (B) ensure on

- going system reliability. MLIG understands that implementation of the Clean Power Plan could ha ve significant impacts on Minnesota utility resource planning processes. C ommenter s stated that energy

- intensive trade

- exposed industries that their members operate in are not only vulnerable to electricity price increases, but also price volatility. C omme nter s opined that allowing states more flexibility to establish their own glide paths would allow for more efficient planning and provide the ability to take advantage of more
cost

- effective options that may arise in the 2020

- 2029 timeframe. C ommenter s fur ther expressed serious concerns about reliability issues that could be caused by the proposed 2020

- 2029 interim emission performance period. C ommenter s reported that, on November 25, 2014, they had submitted a comment letter to EPA arguing that application of the interim compliance period "will negatively impact reliability and resource adequacy in the MISO region starting in 2020." States need flexibility to resolve such potential tensions between meeting Clean Power Plan targets and complying with reliabi lity safeguards. C ommenter s opined that the Clean Power Plan483 has a greater chance of success if it can be implemented in a way that accounts for other critical energy consumer needs such as affordability and reliability.

Commenter s stated that the EPA assu mes that the re

- dispatching from existing coal

- fired EGUs to NGCC EGUs under Block 2 can happen by 2020. However, according to commenter s , the EPA does not consider that legislative changes, and in particular, ERCOT market changes that would be necessary t o effect such a re

- dispatching change. According to commenter s , 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 entire United States NGCC fleet. In f act, according to commenter s , the net increase in generation 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, commenter s reported that the EPA ass umes that Texas can effect such a change in less than four years. Commenter s reported 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 it s permitting authority to restrict operation of units. However, commenter s asserted that the EPA's arbitrary assumption is flawed. Commenter s stated that neither the TCEQ nor the EPA has the legal authority to call the permits for the affected units to imp lement such a change through permitting actions. In citing RGGI as an example of how states might cause such a change, commenter s asserted that the EPA fails to acknowledge the significant amount of time required to implement RGGI. According to the RGGI pr ogram design history webpage, commenter s reported that discussions to create the program began in 2003. RGGI was reported by commenter s to be first established in 2005 and includes two control periods, spanning from 2009 to 2014. According to commenter s , from the initial concept to the final phase, the RGGI program encompasses more than ten years.

Furthermore, commenter s asserted that, while the EPA might argue that they are not requiring the re

- dispatching to be implemented by 2020, the EPA has incorporated this assumption into the calculation of the interim goals. Commenter s asserted that the effect of the EPA's assumpt ion is that the interim goal for Texas is substantially reduced which forces the state to make significant reductions prior to the start of the 2020

- 2029 interim period. Commenter s 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 required to be made by 2020. Commenter s stated that, given the legislative, regulatory, and implementation factors, it is not possible for Texas to implement such a drastic sh ift in energy policy in the time period assumed by the EPA.

Commenter s 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 afte r Arizona receives clarity on the state target and even less time from when Arizona's state plan actually gains approval. According to the commenter s , since Arizona has no natural gas storage and only two major natural gas pipelines, this radically compres sed timeline leaves Arizona virtually no time for proper economic, safety, and reliability based preparation.

Commenter s noted that, in Arizona, the application of Building Block 2 makes a disproportionate contribution to the overall required CO2 reduction s. According to the
commenter s , this result would essentially require Arizona to choose re

- dispatch over other

measures.484 Commenter s opined that the time frame the proposed regulation would provide from its predicted finalization in June 2015 to implementat ion 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 and negotiation of any potential multi

state or regional plan;

3. Meeting any requisites for proposing leg islation that may exist under state law;

4. Adoption of enabling state legislation;

5. Adoption of state regulations implementing state legislation;

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 multi

- state plan.

8. Approval of fifty or more state section 111(d) plans by EPA, which is already well behind in approving state SIPs under CAA section 110;

9. Commitment of capital by the electric generation industry and others that would be regulated by the proposed rule to fund the work that will be necessary to achieve its mandates;

10. Commitment of capital for new electric transmission lines and gas pipelines;

11. Acquisition of prope rty rights for construction or other work that may be necessary;

12. Regulatory approvals and permits from FERC, utility commissions, environmental regulators and others, including any required reviews under the National Environmental Policy Act, the Endanger ed Species Act, 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, systems or device s to assure performance as intended.
According to commenter s , the fact that each of these 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 otherwise be the case.

Commenter s stated that the original proposed rule contains a requirement for a phased reduction (glide path) from 2020 to 2029 that is problematic for a number of reasons. According to
commenter s , while recognizing that there are significant 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 eliminated any flexibility that EPA claimed was in485 the proposed rule. More recently, commenter s stated that, in the NODA, the EPA has noted the problems with the strict phase

- in targets and has expressed an interest in additional ideas regarding the "glide path" to ensure that the overall framework of its rules include s sufficient flexibility. Commenter s agreed that the originally proposed "glide

- path" is a substantial, intractable problem. Commenter s 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.

Commenter s opined that, instead of providing a smooth "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, disruptive, sharp reductions, 47 percent of West Virginia's final goal, before the 2020 to 2029 "glide path" even begins. Commenter s opined that the interim goals effectively remove all flexibili ty and limit the opportunity section 111(d) provides to take advantage of the remaining asset value of coal

- fired generation. According to
commenter s , this problem is not limited to states for which Building Block 2 results in large amounts of CO2 reductio n. Commenter s reported that their state's (West Virginia) coal

- fired EGUs with remaining useful life have already installed controls and undertaken work practices to meet the ARP, CAIR, CSAPR, and MATS. Commenter s reported that compliance has come at a hig h capital cost, which can only be recovered if the units are allowed to operate at reasonable levels. According to commenter s , in order for West Virginia to achieve the interim goal as EPA has outlined in the proposal, existing coal

- fired EGUs would be hav e to achieve a six percent reduction in CO2 emissions due to heat rate improvements; 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 annual savings) in avoided generation due to EE measures over 2012 levels by 2020 which they reported is not possible.

Commenter s asserted that the EPA's presumption that Building Block 2 can be implemented by 2020 is unrealistic. C ommenter s stated that, if EPA chooses to retain the interim goals and allows states to phase in Building Block 2, the time 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 gas generation needed to comply with the rule, according to the commenter s , will require at least five to seven years. The commenter s stated that it is impossible for this capacity to be operational by 2020, given that it is v ery unlikely the state will have an approvable plan prior to 2019. Finally, the commenter s reported that EGU outages for equipment installations have to be coordinated by the independent system operators (ISOs). C ommenter s argued that this planning and app roval process, along with any necessary permitting, cannot occur by 2020.

Commenter s reported that, between 2012 and 2016, Georgia is retiring over 3000 MW of coal

fired capacity. In January 2016, commenter s reported that there will be 9400 MW of capacity remaining in its coal

- fired fleet. According to commenter s , selective catalytic reduction (SCR) controls and flue gas desulfurization (FGD) controls will be installed on 95% of the remaining coal

- fired generation capacity. C ommenter s reported that installa tion dates of these controls will range from 2001 to 2014. Assuming a 40

- year book life for this equipment, commenter s reported that the book life retirement dates will range from 2041 to 2054. Commenter s asserted that these control systems should be viabl e assets for at least 21 years past 2020, the year that the EPA has assumed re

- dispatch to NGCC to be completed.486 Commenter s asserted that the EPA's proposed target schedule for Georgia is asking too much, too soon. Commenter s reported that the Georgia's re

- dispatch from coal unit to NGCC makes u 30 % of the overall reduction in their emission rate reduction from 2012

- 2030 and is targeted by EPA for implementation by 2020. Commenter s opined that re

- dispatch away from coal

- fired generation will result in a si gnificant quantity of stranded viable assets. For example, accordig to EPA's modeling, commenter s stated that Plant Scherer Units 1 and 2 will be retired by 2020 after recently installing nearly $500 million in air pollution control equipment. Commenter s r eported that these units are partially owned (30%) by Georgia municipal utilities and (60%) Georgia's EMCs. The premature retirement of these units, according to commenter s , will leave small municipal utilities, and the Georgia citizens served by these uti lities, with financial obligations for the installation of the air pollution control equipment extending for the next forty years without any benefit of electricity generation.

Commenter s stated that, although EPA has determined that, on an average basis, many states have significant excess capacity at existing natural gas plants, this may not necessarily mean all of this capacity is available to displace coal

- fired electricity on a year

- round basis. C ommenter s expressed that some states may have strong sea sonal variations in demand for natural gas electricity, for example to accommodate high air conditioning demand during the summer in the Southwest. C ommenter s 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. C ommenter s 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.

Commenter s stated that the existing transmission network in Arizona is designed for coal

- fired EGUs located in t he eastern and southern periphery of the State, while the NGCC EGUs are located in and around Phoenix and in the western periphery of the State. C ommenter s complained that significant modifications and additions to the transmission network would be require d to account for shutdown of the coal

- fired EGUs and still provide reliable electricity.

Commenter s reported that, at the earliest the Kentucky SIP would be approved by EPA in June of 2017. According to the commenter s , for an interim reduction compliance date of January 1, 2020, OMU would need to take immediate action to find an acceptable site for construction of natural gas generation. C ommenter s stated, at a minimum, that process would take 6

- 12 months. C ommenter s further stated that permitting a new na tural 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 Agreements (LGIA) and associated required studies pursuant the LGE/KU Open Access Transmission Tariff would take a minimum of 12 months after the definitive site is identified and engineering was completed. C ommenter s reported that the LGIA process is further complicated because to the extent LGE/KU has additional LGIA requests in queue , OMU and any other applicant must wait until their project reaches the number one queue position before the OATT prescribed time clock begins. C ommenter s also reported that construction of required interconnection infrastructure will take at least 24 mont hs with complications likely due to right

- of

- way acquisition for transmission facilities and natural gas pipelines. According to the commenter s , with a minimum construction period of 24 months depending upon start date, the retirement of an ESGS unit in 20 20 would expose OMU ratepayers to market prices for a minimum of two years before a replacement487 natural gas fired generating facility comes online. C ommenter s suggested that EPA should at a minimum permit a compliance timeline based upon the assessment mad e by the Kentucky Division of Air Quality working with the affected EGUs that recognizes both the reality of the time required to complete the steps necessary to replace existing generation with lower emitting natural gas generation and to reflect the usef ul life of existing EGUs.

Commenter s stated that the EPA glide path for Building Block 2 inherently assumes that re

dispatch can be achieved seamlessly by 2020; it entirely fails to account for the fact that NGCC is used as reactive power to back up the intermittent renewables, such as wind. According to the
commenter s , if those current units are re

- dispatched as base load, new natural gas

- fired units would have to be constructed for the purpose of providing reliability for the renewable energy already on the ground. The commenter s asserted t hat the inability to re

- dispatch means that Building Block 2 " where EPA assumes over 30% of reductions can be made " is not available to MRES, nor is it even remotely possible in many states. Instead, the commenter s suggested that the EPA acknowledge that t he states alone are in the best position to determine when and how reductions can be made under this building block during the interim glide path period.

Finally, the commenter s stated that, in the upper Midwest, where the MRES load is centered, there are already constraints in natural gas capacity. C ommenter s reported that the Northern Natural Gas, one of the leading suppliers of natural gas in the upper Midwest, faced constraints and limited capacity during the "polar vortex" of 2014 and that it may require new natural gas infrastructure just to provide addit ional 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. C ommenter s further reported that new natural gas lines would also face the need of a mple time frames to be permitted and constructed. C ommenter s stated that public notice, permitting, and construction will take years, not months. C ommenter s further stated that there will also be added delays if the lines are opposed, if there are environm ental impact issues, or if there are eminent domain complications. C ommenter s asserted that, before the publication of this proposed rule, the MISO region already had 3.7 GW of announced coal retirements and 5.0 GW of new gas plants announced in the region . According to the commenter s , in order to interconnect the MISO

- forecasted NGCCs and simple cycle turbines, the lateral natural gas pipeline construction will cost between $870 million to $1.08 billion. C ommenter s stated that this is for the construction of lateral lines only and not including any mainline costs. C ommenter s 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 and the time for planning, permitting and constructing sufficient natural gas construction in the upper Midwest alone. C ommenter s stated that, as the MISO natural gas infrastructure analysis concluded, there must be consideration for the lead

- time required for pipeline construction to meet the ne ed of power generators by 2015/2016 and the potential for construction delays due to the anticipated increase in power generation interconnection request. Lastly, the commenter s asserted that the decision

- makers must recognize the competing needs for pipel ine construction as industrials and other reshoring industries ramp

- up. C ommenter s opined that this will affect the availability of skilled labor and materials and will most likely increase costs for those that postpone decision

- making. C ommenter s asserted that the electric power industry must determine its own level of redundancy and reliability requirements and the means to recover costs associated with the value of reliability under its economic models. Simply put, according to the commenter s , the488 antici pated substantial increase in natural gas reliance and additional natural gas capacity needed makes the glide path milestones difficult, at best, to reach in the allotted time.

In summary, commenter s argued that the glide path would 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/MWh), a huge feat in such a short time. Likewise, Iowa would need to achieve 61 percent of its total ma ndated reductions by 2020, North Dakota 67 percent, South Dakota 67 percent and Wyoming 53 percent. This, according to the commenter s , would require substantial changes in the entire electric industry in the matter of less than four years, which the commen ter s stated is not achievable given the limitations of natural gas capacity, renewable energy intermittency, the need for more transmission, and the lack of planning and permitting time for new renewables, new pipelines or transmission, for natural gas ram p

- ups at existing plants (if feasible), or for new natural gas plants.

States Can Comply With Interim and Final Standards

A few commenters believed that the interim and final standards compliance timeline can be met.

Commenter s stated that Missouri can achieve all its needed reductions through already

announced coal plant closures and through compliance with state policies already in place.

Commenter s asserted that states have many alternatives to comply with the interim and final standards if re

- dispatc h would result in temporary reliability issues. Commenter s noted that it should be emphasized that the building blocks are used to calculate what a state could do to cut emissions, not what it must do. Therefore, according to the commenter s , if local relia bility genuinely prevents re

- dispatch of coal to gas, as some claim, there are other options. C ommenter s stated that other options are being deployed by Western states and utilities, and are already leading to significant emission reductions. According to the commenter s , states could:

• 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 technologies to expand capacity and maintain reliabil ity; and

• implement demand

- side management at the regional level.

According to the commenter s , if a state is unable to meet the state's annual targets in the early years due to operational constraints, it could still meet the interim and final standards by exceeding annual state targets in the latter years of the performance period. Finally, the
commenter s stated that it is important to keep in mind that EPA did not set its standards based on the maximum achievable reduction from each block. The commenter s e xpressed that this provides states with flexibility to use the blocks in amounts different than EPA assumed in setting the state targets.489 Comment 2: Some commenters supported a phase

- in period for re

- dispatch while others said that the proposed NODA approach would not work or would result in excess GHG emissions.

Response 2: The EPA thanks the commenters. The 111(d) final rule requires that states develop plans that establish emission standards for affected EGUs. The rule provides states with substant ial 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 (po stponed 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 regulatory req uirements 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 Final Rule 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

- dispatch under Building Block 2 rather than requiring re

- dispatch be fully implemented by 2020. Several of these comments are pro vided in the following paragraphs.

Commenter s 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 intensity goals would allow a more reasonable schedule for infrastructure expansion, thereby avoiding significant cost increases to rate payers.

Commenter s requested that EPA mitigate negative effects by setting more reasonable goals for each state that are based on the emission reductions that are truly achievable for each state. In addition, the commenter s stated that a gradual phase

- 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 measures.

Commenter s opined that a more measured phase

- in sched ule would provide time for infrastructure improvements that would be required to ensure grid reliability. C ommenter s requested that any improvements to Building Block 2 and the interim period take into account the remaining useful life of affected electric generating units.

Commenter s stated that a more gradual phase

- in of Building 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 power sector as a whole at a lower cost.

Commenter s urged EPA to phase

- in the re

- dispatch component of Building Block 2. Commenter s stated that a substantially longer runw ay for states to make this coal

- to

- natural gas transition and include a phased approach to re

- dispatch is needed. C ommenter s stated that it is490 needed because the interim average target is so close to the end 2030 target and it leaves little room for flexib ility let alone enough time to site needed upgrades.

Commenter s recommended that the EPA adjust the Building Block approach to exclude remaining useful life units from the re

- dispatch calculation (discussed in another comment summary in this section) 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. C ommenter s stated that additional 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 gas for compliance.

Commenter s recommended that the EPA phase in the target for re

- dispatch to NGCC over a longer duration to allow for continued, cost

- effective operation of existing fossil

- fired generation

sources.

Commenter s stated that, if the EPA does not phase

- in re

- dispatch, there would be the required shutdown of many coal

- fired units that "have recently been constructed" or "have received significant capi tal investment (e.g., in the form of pollution control retrofits)."

Commenter s expressed concern with the assumption that the full re

- dispatch of NGCC units according to Building Block 2 is feasible on "day one" and agrees with phasing in of these targets over time.

Commenter s believe d that, while existing NGCC plants are capable of operating at higher capacity factors, they acknowledged the need for a reasonable phase

- in to accommodate infrastructure and economic realities. C ommenter s also recognized the need to balance this re

dispatch with the concern for an economic transition that includes capital recovery for the existing fleet of coal generation, especially in light of the significant recent investments coal plants have made to c omply with other recent EPA rulemakings. Therefore, although the
commenter s believe d that the existing fleet is technically capable of achieving this capacity factor today, they also believed that an extended phase

- in period for Building Block 2 requiremen ts would better allow for necessary infrastructure improvements and economic considerations.

Commenter s argued that, if the interim goals remain in the EPA's final guidelines, they supported the phase

- in of emissions under Building Block 2.

Commenter s requ ested the "front loaded" problem be addressed by building in phase

- in periods for the implementation of the NGCC re

- dispatch called for under Building Block 2, while providing a mechanism for utilities to get credit for early action, such as purchase of Ri o Nogales in 2012.

Commenter s preferred that the EPA phase

- in Building Block 2 to allow for a more gradual glide path instead of the current cliff facing their state (Arkansas). C ommenter s asserted that the electric grid is a complex machine and the implementation of Building Block 2 represents a major change in operations and that such a change will not be quick or easy.491 Similarly, commenter s stated that, if EPA chooses to retain the inter im goals and allow states to phase

- in Building Block 2 over the 10

- year compliance period, a phase

- in schedule should consider additional necessary infrastructure improvements, due to existing natural gas supply constraints and ensuring a reliable fuel sup ply. According to the commenter s , the EPA should also consider the time required to integrate any transmission enhancements needed to address impacts to reliability from the proposed rule, as indicated by Midcontinent Independent Systems Operator (MISO) an d North American Electric Reliability Corporation. C ommenter s indicated that new transmission may be necessary to support new resources in order to comply with the rule and that the transmission planning process and construction could take between 6 and 10
years.

Commenter s agreed that many NGCC facilities have the technical capability to operate at an annual average capacity factor up to 70%. However, according to the commenter s , other factors limit the ability of NGCCs to increase their current annual ave rage capacity factor. To ensure existing NGCCs can provide up to 70% capacity factors, the commenter s reported that many states/regions would need to address natural gas delivery and/or transmission constraints. C ommenter s recognized that strict implementa tion of the goals is not required for compliance; however, other options (plant retirements and/or new construction) will not be available early in the interim period for the very same reasons. Therefore, the commenter s recommended that EPA provide a glide path that allows for these reduction opportunities to occur evenly throughout the interim compliance period. C ommenter s reported that projects to address natural gas delivery and transmission constraints take time to implement, and stated that two prime e xamples have occurred in New Jersey:

1. BL England Closure/Repowering

According to commenter s , 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 repower the facility to natural gas (NGCC). C ommenter s stated that the order was amended in 2012 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

fired EGU), according to the commenter s , was originally scheduled to shutdown in 2015 and the owner planned to complete construction of a new NGCC unit in 2016. However, the commenter s stated that Units 2 and 3 (oil

- fired EGU) remain in opera tion. C ommenter s 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 commenter s reported that the pl ant owner submitted a generation deactivation request to PJM for Units 2 and 3; however, the request was withdrawn because PJM identified reliability issues. The PJM Reliability study, according to the commenter s , stated that the closure of Units 2 and 3 w ould require significant transmission upgrades that may take several years to complete. PJM indicated that brownouts and/or blackouts may occur during periods of peak demand. Hence, the commenter s reported that the NJDEP extended the retirement requirement for Unit 2 to mid

- 2017. C ommenter s stated that the amended consent order allows for an extension beyond 2017 if the New Jersey Board of Public Utilities ("NJBPU") or PJM determine that additional time is necessary to avoid reliability issues. The commente r s further reported that492 the potential closure/repowering of this facility has 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")

Commenter s s tated that, in 2007, PJM approved the Project 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. C ommenter s reported that the Project consists of a new 500 kV transmission line that will run from Susquehanna, PA to Roseland, NJ. PSE&G is responsible for constructing the New Jersey portion of the Project. C ommenter s further reported that the Project required app rovals for the following: Board of Public Utilities, Freshwater Wetlands Permits/Flood Hazard Area Permits, National Park Service (NPS), Picatinny Arsenal, and required land use agreements. The original in

- service date was scheduled for 2012; however, acco rding to the commenter s , commencement of construction was delayed by three years due to the NPS Environmental Impact Study. In total, the commenter s reported that the Project will have taken eight years from PJM approval to complete.

C ommenter s opined that these two examples show that ample time is needed to address all potential obstacles relating to re

- dispatch and that the 2020 cliff that the proposed rule would impose may not be practical. NERC also expressed its concern regarding the need for more time to address transmission and delivery enhancements that are required to achieve the necessary reductions in the CPP. C ommenter s concluded that, given the significant delays states may face in planning for increased use of NGCC units, EPA must allow for a g radual phase in of Building Block 2.

Commenter s asserted that, as a preliminary matter, phasing in reductions under Building Block 2, similar to the phase

- in of reductions under Building Blocks 3 and 4, could address some of the

near

- term compliance chall enges discussed in these comments for some states. In general,
commenter s stated that phasing in these reductions is more reasonable than assuming that all changes in dispatch between coal

- and gas

- based generation occurs before 2020. As EPA recognizes in establishing the Building Block 3 and 4 goals, commenter s believe d that it is appropriate to give states and electric utilities sufficient time to make system changes or create new programs. Commenter s opined that a phase

- in of Building Block 2 reductions could allow for the necessary expansion of natural gas infrastructure to support increased utilization of existing NGCC units and could provide competitive markets time to review and adjust market rules, if needed.

Commenter s stated that the EPA should rev ise the Proposed Rule so that the phase

- in period for Building Block 2 roughly mirrors the EPA's more gradual approach to implementing Building Blocks 3 and 4. C ommenter s asserted that a gradual approach would provide more flexibility for states and utilit ies to invest in the infrastructure that will be necessary to increase NGCC utilization to the levels assumed in calculating state goals.

Commenter s shared the concerns of stakeholders who have requested EPA replace the current interim compliance period go als with a more reasonable glide path. Commenter s supported alternative phase

- in glide paths between 2020 and 2029 based on State specific considerations and suggests EPA should expressly allow a State to present alternative glide path compliance493 scenarios so long as the State can demonstrate the same or better cumulative emissions are achieved.

Although commenter s favored a mile milestone approach 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. C ommenter s stated that a phase

- in schedule would provide time for infrastructure improvements that would support increased existing natural gas

fired generation as well as modifications that would minimize stranded investments.

Commenter s opined that easing the emissions "glide path" in the first few years of the interim compliance period gives states time to focus on long

- term infrastructure needs. C ommenter s opined that phasing in compliance would enable states to make investments in deeper cuts that may not be achievable as quickly as a shift from coal to gas. Specifically, the commenter s opined tha t states would be able to develop increased renewable generation capacity, including new transmission lines where necessary, to reduce fossil fuel consumption. C ommenter s stated that such development requires a significant amount of planning, permitting, and construction time. If states are forced to move too quickly to comply with a strict interim target, they are likely to prioritize solutions that are faster than large

- scale renewable generation deployment, such as the construction of new natural gas power plant capacity. C ommenter s asserted that, while new natural gas capacity would be preferable to coal, forcing this type of investment too quickly in order to meet the interim target may deter consideration of investment in zero

- emitting capacity in later years, and thereby reduce the lasting impact of the Proposal. C ommenter s stated that, while they appreciate EPA's willingness to explore softening the emissions glide p ath for states, they are not suggesting that any change to this effect should loosen the 2030 targets or the cumulative effect of the Proposal over the course of the next decade, because loosening the targets would likewise reduce the incentive to invest i n zero

- emitting capacity.

Commenter s agreed with the proposal to phase

- in Building Block 2 over time to accommodate technical challenges states may face in expanding natural gas infrastructure. Similar to the way that building blocks 3 and 4 are implemente d in the proposal, the commenter s suggested that EPA could define an amount of utilization shift that is feasible by 2020, and then define how quickly that amount could grow until the full amount of utilization (70 percent in 2030) is achieved. This way, a ccording to the commenter s , states 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 deployment of the other building blocks. C omment er s stated that they do not believe it is necessary to evaluate the rate at which existing coal

- fired power plants can be retired as the compliance period averaging should be able to accommodate any such delays.

Commenter s stated that the development of an interim 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.

Commenter s asserted that, to maintain affordability and re liability, the switch from coal to more natural gas fired generation needs to be phased in at an achievable rate through 2030, rather than by 2020.494 Commenter s expressed that, aside from the legal, technical, and practical concerns with Building Block 2, a phased

- in approach would offer additional flexibility for states to attempt to address early unit retirement and related potential reliability issues in developing a state plan within, what they believe to be an aggressive implementation schedule proposed by EPA.

Commenter s expressed that the EPA does not provide any specific information on how it would determine an appropriate phase

- in schedule for Building Block 2. C ommenter s opined that it is not realistic to assume that the EPA will be able to establis h a phase

- in for Building Block 2 to accommodate all of the concerns surrounding the permitting, technical, engineering, and infrastructure limitations associated with Building Block 2.

Did Not Take Position on Phase

- In of Re

- Dispatch

Commenter s stated th at they did not take a position on whether EPA should phase

- in Building Block 2, and they reported that their states may have different positions on this issue. However,
commenter s requested that, if the EPA does choose to develop a phase

- in schedule for B uilding Block 2, the EPA base any rate of transition from existing coal to existing under

- utilized NGCC capacity on technical considerations relevant to such a transition. Commenter s recommended that the EPA carefully consider historic changes in the relat ive 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 pace of shifts in utilization between coal

- and
gas

- fired power plants.

S

pecifically Supported Phase

- In of Building Block 2 Alternatives Raised in the NODA

Commenter s supported a phase

- in of Building Block 2 under both alternatives raised in the NODA. Commenter s stated that utilities could be in a situation to need the flexibil ity afforded by each alternative. Commenter s reported that, where there is an existing NGCC that will need additional infrastructure improvements to increase to a 70% capacity factor, utilities and states will need additional time. Commenter s are also in favor of EPA considering the return on capital investment in existing coal

- based assets in order to avoid stranded investments. Based on
commenter s’ analys e s of EPA's modeling results, there are numerous stranded assets as a result of this proposa l. Commenter s reported that, some of the units that would be retired are currently installing air pollution controls at a cost of several hundred million dollars to comply with the Mercury and Air Toxics Standards (MATS) rule.

Commenter s 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.

Commenter s expressed that, if the EPA does not defer to the states, they supported the adoption of a more gradual glide path that takes into account both natural gas infrastructure needs (e.g

., pipelines, booster compressors, and storage) and stranded investment concerns. C ommenter s opined that su ch an approach is consistent with the statute, which provides for consideration of energy system impacts and the remaining useful life of the affected source. C ommenter s further opined that a more gradual glide path would also likely facilitate deeper long

- term reductions. According to the commenter s , there is likely an inverse relationship between forcing states to495 reduce greenhouse gas emissions almost immediately (i.e., by 2020) and a state's ability to shift generation to renewable sources of energy, si nce early reductions will depend predominantly on natural gas dispatch. C ommenter s asserted that, where material additional state investments are required, near

- term natural gas commitments may "lock in" a state's or region's investment strategy thus defer ring alternative investment in renewables, energy

- efficiency and energy storage. C ommenter s requested that states be able to retain the authority to select the approach best suited to their needs and to time the reductions accordingly.

Commenter s supported the allowance for compliance of measures which occur between the baselines year(s), and the first interim compliance deadline in 2020. C ommenter s opined that this would encourage states to act early in building renewable generation and energy efficiency i ncentive programs to create a smooth transition into the compliance period, and will also provide some credit to states already making these investments. C ommenter s further stated that, while it would not be appropriate to make these early reductions legal ly 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 reduction. C ommenter s agreed with commenters who suggest that the re

- dispatch of NGCC units co ntemplated under Building Block 2 cannot reasonably be expected to occur on "day one" and supported the recommendation put forth in the October 28th NODA that Building Block 2 should be phased in similar to Building Blocks 3 and 4. C ommenter s expressed tha t states should be given flexibility to determine the appropriate phasing of this Building Block based on electric and gas transmission needs in their states and regions.

Commenter s urged the EPA to adopt a phase

- in schedule for Building Block 2 based on the fact that some states will require additional infrastructure improvements in order to support more use of existing natural gas

- fired generation, as discussed in the NODA. Comment er s stated that they would support the NODA

- suggested approach of modifying Building Block 2, and thus the interim goal, to reflect such factors as infrastructure limitations and the potential for stranded investments considering state specific factors. C o mmenter s suggested that the most straightforward method of adopting this approach would be to allow each state to propose its interim goal in its section 111(d) plan.

Commenter s believe d that both options described in the NODA, credit for early reductions (addressed under another comment in this section) and phasing in of Building Block 2, are options that a state should be able to use in establishing its glide

- path. Phasing

- in would be m ore consistent with Buildings Blocks 3 and 4 where increased utilization is phased

- in between 2020 and 2029. Commenter s further stated that they supported the second phase

- in option included in the EPA 's NODA; that Building Block 2 be modified to respond t o stakeholder concerns about the pace with which generation in some states may need to be shifted from higher

- emitting to lower

- emitting

- units.

Commenter s expressed that it is not clear from the NODA how EPA would structure a phase

- in schedule for Building Block 2. Commenter s stated that, under the first option, the EPA would account for the needed expansion in natural gas pipeline infrastructure, but the Agency has not provided any details as to how the Agency would determine which states need new capacity and how quickly it could be built. Commenter s stated that, at minimum, the EPA should recognize that it takes three to five years to plan, permit, contract for capacity, finance and build additional496 pipeline capacity. However, commenter s believe d that, in general, it is difficult to see how the Agency could determine a phase

- in rate for new pipeline capacity that would make sense for each state or accurately reflect state

- specific infrastructure circumstances.

Commenter s urged the EPA to examine early act ion (addressed under another comment in this section) and phasing in to reasonably adjust the interim goals, while maintaining the environmental integrity of the final targets. C ommenter s urged the EPA to work with states, regulatory authorities such as th e NERC, and regional 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 costs and the reliability of the grid. Specifically,
t he commenter s requested that EPA develop a more reasonable, phased

- in timetable for re

dispatch that would not threaten the reliability of the regional grid nor impose undue stranded costs on states' electric ratepayers. C ommenter s opined that such a devel opment 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 measured way to gauge progress toward the 2030 goals. C ommenter s stated that a more r easonable, phased

- in timetable is important for states like California that have both significant NGCC capacity and few high emitting resources.

Commenter s recommended that, in addition to allowing 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 implementation of efforts to achieve the final goals.

Complicated and Difficult to Implement NODA Approaches

Commenter s agreed with stakeholde r concerns that there may be technical challenges associated with achieving all of the reductions that states would be required to make as early as 2020, when the interim period commences, such as additional infrastructure improvements (e.g., natural gas
p ipeline expansion or transmission improvements) needed to support more use of existing natural
gas

- fired generation. However, commenter s did not support either of the alternative approaches that EPA has requested comment on in the NODA to address stakehold er concerns with the "front

- loading" of Building Block 2 because they believe they are complicated, cumbersome, subjective and difficult, if not impossible, to be implemented on a uniform basis across the states. C ommenter s recommended another glide path a pproach that they believed might offer states the flexibility they need to address stakeholder concerns with the "front

- loading" of Building Block 2 while still ensuring that they can achieve the final goals.

Implementation of NODA Options Would Not Be Su fficient to Address Compliance Concerns

Commenter s stated that, although they agree that both of the options provided in the NODA can help temper the near

- term compliance challenges, even if implemented together they are not sufficient to fully address concerns.

Commenter s asserted that, in the NODA, the EPA did not provide any additional data to support either of their proposed approaches. Moreover, according to commenter s , because the EPA did not change the December 1 comment deadline, there was insufficient time for them to fully analyze EPA's proposals . However, based on the commenters' limited review, they asserted that neither of the alternate glide path proposals provides reasonable alternatives to Rule 111(d) as497 proposed. First, commenter s stated Building Block 2 is an "outside the fence" activity o ver which the EPA has no authority. Commenter s stated that the EPA is neither authorized nor qualified to dictate to states how their natural gas units should be operated or dispatched. Second,
commenter s stated that Rule 111(d) does not provide flexibilit y for their state (Texas), but instead would require their state to implement approximately 77% of its emission reductions by 2020, which they opined is both unreasonable and unachievable. In conclusion, commenter s stated that the alternate glide path prop osals in the NODA do not appear to provide any meaningful flexibility for their state to meet EPA's interim emissions goals.

Commenter s stated that, while they understand the critical importance of maintaining system reliability both before and during the plan performance period, they are concerned that the options set out in the NODA may not result in a reduction of total CO2 emissions at a level that the EPA's proposal would. C ommenter s asserted that climate change is a threat of epic proportions, and ade quately addressing that threat must not be compromised.

Commenter s stated that, while the EPA seems to recognize 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 phasi ng in of NGCC units) is inadequate. Commenter s stated the NODA still fails to recognize the infrastructure, permitting and construction limitations. Commenter s stated that, while the proposal contemplates adjustment of individual state targets for this bui lding 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 the timing requirements for filing of state plans. Commenter s added that construction t imelines are difficult to accurately predict and thus create unnecessary compliance uncertainty and risk.

Commenter s opined that, while the idea of a "glide path" to the final requirements of the year 2030 appears appealing, it will not work. C ommenter s st ated 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: C ommenter s asserted that the glide path proposed by the EPA would pre maturely and unnecessarily cause 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.

Commenter s stated that the EPA has begun to reco gnize that a sudden shift to natural gas generation by 2020 may be unreasonable and unachievable and has requested comment on a phase

- in approach aimed at avoiding the likely consequences of a hasty reduction in coal

generation. However, according to the c ommenter s , the suggestion of a glide path is not the answer, and they believed they had insufficient time to address issues pointed out in the NODA.

Commenter s 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 phase

in would alleviate concerns over workability and reliability. Id. at 64,548

- 549. The commenter s asserted that, while the acknowledgement of stakeholder concerns is laudable, it does not resolve the basic flaws of Building Block 2. First, according to the commenter s , states have no authority to mandate dispatch of NGCC within their state; the dispatch of power is governed by the RTOs. C ommenter s stated that NGCC units in existence wer e planned, permitted, constructed and interconnected with transmission based on the needs of the operating/owning utility, and are498 limited by physical pipeline and transmission constraints, permit limits and gas availability, none of which can be simply ra mped up to meet the 70% assumed capacity factor by 2020. C ommenter s stated that the glide path 's assumption that all NGCC can be ramped up to 70% in 2020 ignores basic operational issues. C ommenter s asserted that the timing of the glide path does not reflect the transmission or interconnection studies, revised agreements or RTO modeling that would have to be accomplished in a very short period of time to increase the capacity factor, while still meet ing reliability requirements of the North American Electric Reliability Corporation (NERC). And of course, according to the commenter s , that is predicated on the assumption that transmission capacity is available for the increase in NGCC operation. In fact

, according to the commenter s , if the existing units are in a transmission constrained area, new transmission must be added to accommodate the load. C ommenter s stated that transmission studies on average take about two years to complete and that new transm ission cannot be guaranteed to materialize in the time frame suggested by the proposed rules. C ommenter s reported, for example, the Minnesota CapX 2020 project took roughly 10 years from initial planning stages, to permitting, to the placement of the new l ines into service. C ommenter s further reported that the CapX project has taken additional time as there have been contested court challenges to eminent domain and the Minnesota "Buy the Farm" statute which requires affected agricultural land to be purchase d in whole, and not just the impacted portion. See Minn. Stat. 216E.12, subd. 4. The commenter s asserted that, as the EPA is well aware, contested case proceedings would significantly lengthen the timeframe of building needed transmission, will be a signif icant 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 Delay Carbon Pollution Reductions

Commenter s stated that EPA 's proposals to dev elop state carbon pollution reduction targets based on a gradual phase

- in of Building Block 2 could weaken or delay carbon

- pollution reductions in the short term unless the EPA strengthens the guidelines of the other building blocks.

Commenter s requested t hat EPA not adopt a phase

- in for either building block 1 or 2 as it will undermine efforts to meet the national all

- sector goal of 17% by 2020 and 28% by 2025. C ommenter s asserted that, while there has been a reduction of emissions from power plants 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.

Commenter s expressed that they do not support the NODA proposed changes to the glide path. C ommenter s asserted that the draft proposal already allows significant flexibility to states in the timing for reaching their goals of the CPP and further delays in achieving emissions reductions are contrary to the overall goals of the CPP to make a significant contribution to re duce U.S. global warming emissions in a timely way. C ommenter s requested that, if EPA decides to make changes to the glide path, it should only be done in conjunction with strengthening the state emissions reduction goals required by CPP. C ommenter s also a sserted that delaying emissions reductions could also result in more stranded assets with utilities making investments to near

term targets that may be unsuitable for meeting the long term targets.

Phase

- In Not Needed499 Commenter s opined that, with respect t o the proposal for a phase

- in for Building Block 2, EPA should refrain from adopting such methodology. According to the commenter s , a phase

- in methodology is not needed for Building Blocks 1 and 2, as it is for 3 and 4. C ommenter s believe d the EPA was correct in its proposed rule in determining that the BSER for Building Blocks 1 and 2 were feasible in the proposed timeframe.

Comment 3: Commenters said that s tate s s hould h ave a uthority to d efine t heir o wn g lide p ath and t imeline to a ddress c ompliance c oncerns

. Response 3: The EPA disagrees with commenters. The interim standards are an important part of this final rule and are essential for successful performance. The EPA has provide d many pathways that states can choose to comply. The 111(d) final rule requires that states develop plans that establish emission standards for affected EGUs. The rule provides states with substantial flexibility as to how they structure those plans to achieve the 111(d) requirements. The flexibility includ es, 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 regulatory requirements and the “useful life” of assets. See sections V.D, VIII.A, VIII.C and VIII.G of the final rule pream ble 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:

Commenter s argued that, eliminating states' compliance flexibil ity 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).

Commenter s urged EPA to recognize state authority to determine the interim path and timetable to achieve 2030 carbon intensity targets.

Commenter s opined that states should be given flexibility to determine the appropriate phasing of this Building Block based on ele ctric and gas transmission needs in their states and regions.

Commenter s suggested that EPA allowing states to establish EGU

- specific re

- dispatch or re

firing dates by permit or rule is reasonable.

Commenter s asserted that, because states are in the best p osition 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 adjusted interim targets for 2020

- 2029 that account for a more gradual ramp

- up of NGCC capacity factors. C ommenter s expressed that states' final 2030 targets could remain the same.

Commenter s requested that the EPA allow states to determine what level of re

- dispatch is feasible and the reasonable schedule for implementing NGCC re

- dispa tch.500 Commenter s asserted that, while a phase

- in of the re

- 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 state. Commen ter s 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, commenter s asserted that the EPA is not qualified to determine the feasibility of such a fundamental shift in a state's energy policy. Commenter s opined that only the state public utility commissions are in a position to evaluate the feasibility of shifting generati on from one fuel source to another on the scale that the EPA is assuming under Block 2. Furthermore, commenter s asserted that, what may be feasible in one state is not necessarily feasible in another state.

Commenter s believe d that each state should be al lowed 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 early reductions and phasing in of Building Bloc k 2 are all optio ns that a state should be able to use when establishing its glide

- path.

Commenter s suggested that the EPA allow the states to determine how quickly Building Block 2 may be phased in. Commenter s reported that the EPA suggests that an appropriate phase

- in

sc hedule could be based on "whether, and to what extent, any additional infrastructure improvements (e.g., natural gas pipeline expansion or transmission improvements) are needed to support more use of existing natural gas

- fired generation," or on avoiding s tranded investments considering the "book life" of generating assets. Id. at 64,548

- 49. Commenter s asserted that states are in a much better position than EPA to assess these factors and determine an appropriate phase

- in schedule. Commenter s also stated th at the EPA gives no indication as to how it would go about assessing these factors and developing a phase

- 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 verbally that this approach is not provided for in section 111(d), the commenters also noted that the interim goal is not provided for in section 111(d).

Comment 4: Some commenters s upport ed e liminating or a djusting i nterim g oals , while other

commenters opposed the idea of eliminating the interim 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 many ways to comply with this final rule. The 111(d) final rule requires that states develop plans that establish emission standards for affected EGUs. The rule pr ovides 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 int erim 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, inc luding other regulatory requirements and the501 “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 Final Rule supporting the final CPP.

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

Support Eliminating Interim Goals

C ommenters suggested that the EPA not finalize an interim goal for implementing the NGCC dispatch. Most of the commenters believe d that eliminating interim emissions goal so that states can determine the most appropriate phase

- in schedule for Building Block 2 reductions would better address state

- specific concerns. Rather than mandating enforceable interim goals,
commenter s recommend ed that the EPA give states discretion to develop individualized plans for the 2020

- 2029 time period that establish programs and measures that lead to compliance with the 2030 emission goals. In particular, commenter s stated that the EPA must allow each st ate 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 of the 2030 goals. Commenter s stated that, although both of the approaches set out in the NODA address some o f their glide path concerns, neither approach provides states the same ability to design cost

- effective compliance plans that are consistent with the technical realities of shifting generation between existing coal

- and gas

based units that would be provid ed by eliminating the interim goals. Commenter s suggested that the EPA can consider the phase

- in as part of its review of the state plan, but should not establish a set of unattainably harsh interim goals governing it. Commenter s asserted that, if EPA is to set BSER standards, the interim standards should be eliminated and EPA must allow states, in concert with ISOs and RTOs, to develop their own moderated glide paths in order to avoid grid reliability and economic problems. Commenter s suggested that inter im 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 plans to demonstrate a reasonable glide path to the 2030 targets.

Commenter s asse rted that the flexibility that the EPA advertises with this proposed rule would be more credible if the interim goals were eliminated. C ommenter s stated that, in its current form, the interim goal glide path is very specifically tailored to an exact combin ation of building blocks implemented by a precise schedule set by the EPA. According to the commenter s , if a state were to vary from this combination of building blocks or schedule in even the slightest way, there is a high likelihood that the interim goal s or final goals would not be able to be met. C ommenter s asserted that the elimination of the interim goals would promote the flexibility to implement building blocks, at a state or regional level, on a schedule that is appropriate given the individual fac tors contributing to that state or region 's ability to reduce carbon emissions. C ommenter s also asserted that states or regions should be able to determine this schedule in their implementation plans and not be mandated to meet interim goals as long as the timeline proposed in the SIP (and approved by the EPA) includes appropriate measures taken to ensure compliance with the 2030 goals.

Commenter s requested that the EPA consider a glide path approach by 1) removing the interim goals from the final rule and/ or 2) delaying the compliance deadline by five years from 2030 to 2035.502 Commenter s stated that, if the EPA were to eliminate interim goal and instead only require states to achieve their final emission rate goals in 2030, states would then be allowed to t ailor the contour of its glide path to attaining its 2030 goal based on the unique circumstances and limitations for implementing the four building blocks. C ommenter s stated that the state would be required to establish a plan, subject to EPA approval, wit h 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 as practicable. C ommenter s asserted that such an approach is consisten t with section 111(d) and that EPA has discretion to allow states to achieve their state

- specific emission goals based on various factors enumerated in section 111, including costs, energy requirements, and the remaining useful life of existing source.

Com menter s 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.

Commenter s 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. C ommenter s believe d that both of these steps would help to alleviate many of the negative impacts this aspect of the Proposed Rule.

Commenter s supported all options that provide the state with flexibility to achieve the state goal based on state procedures, legislation and with coordination with all appropriate stakeholders. C ommenter s believe d that states should continue to be allowed to choose rate

- based or mass

based goals and single

- state and/or multi

- state plans to achieve state goals according to the glide path developed by the state. C ommenter s specifically supported states being able to design a "rate of progress" plan and should not prec lude the use of any means the state chooses to reach the end goal (including whether to adopt the "alternate" 2025 state goal or adopt what are termed in the current proposal the interim and final goals. C ommenter s suggest ed that if a state develops a "rat e of progress" plan that satisfies the final goal, then the interim goal should be eliminated. C ommenter s believe d that the interim goal creates unnecessary reliability risks, increases consumer cost, and improperly restricts the state's ability to exercis e its statutory prerogatives under the CAA to develop appropriate compliance plans and alternatives, including consideration of remaining useful life of existing resources

.

Commenter s stated the EPA should not finalize any interim goal and should allow st ates to determine and set reasonable schedules for implementing NGCC re

- dispatch. Commenter s noted there are obstacles to increased NGCC operation by 2020 that will make meeting the Proposal's goal unlikely, if not impossible. Commenter s stated increased N GCC 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 operation of the electrical grid. Commenter s

were concerned that neither EPA n or regulated entities 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 th e timeline to properly comply. Commenter s suggested that an industry group and/or NERC are the appropriate entities to conduct such a study, and EPA's role should be to set a timeline that will accommodate it. In the event that EPA includes a mandatory int erim goal, commenter s suggested the EPA should assume a ramp

- up period for re

- dispatch implementation, similar to EPA's treatment of renewables and energy efficiency.503 Commenter s stated that the EPA should at a minimum permit a compliance timeline based upo n the assessment made by the Kentucky Division of Air Quality working with the affected EGUs that recognizes both the reality of the time required to complete the steps necessary to replace existing generation with lower emitting natural gas generation and to reflect the useful life of existing EGUs. Commenter s described the following procedure 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 Janu ary 1, 2020, OMU would need to take immediate action to find an acceptable site for construction of natural gas generation, which would take 6

- 12 months at a minimum. Permitting a new natural gas EGU would take a minimum of 18 months after engineering is c ompleted to the level necessary to support the air permit application. Large Generator Interconnect Agreements (LGIA) and associated required studies pursuant the LGE/KU Open Access Transmission Tariff will take a minimum of 12 months after the definitive site 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 other applicant must wait until their project reaches the number one queue position be fore the OATT prescribed time clock begins. Construction of required interconnection infrastructure will take at least 24 months with complications likely due to right

- of

- way acquisition for transmission facilities and natural gas pipelines. 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 minimum of two years before a replacement natural gas fired generating facility comes online.

Commenter s recommended the EPA to eliminate the interim goal and allow states to determine a schedule for implementation based on feasibility and cost. Commenter s stated that, if EPA chooses to retain the interim goals and allow states to phase in Building Block 2 ov er the entire compliance period, a phase

- in schedule should consider any additional necessary infrastructure improvements needed to eliminate existing natural gas supply constraints and ensure a reliable fuel supply. Commenter s stated the EPA also should c onsider the time required to integrate any transmission enhancements needed to address impacts to reliability, as indicated by MISO and NAERC.

Commenter s stated that, based on the current and future demand on the existing and under

construction natural gas infrastructure and NGCCs and the economics and hurdles for the construction of new natural gas infrastructure and NGCCs, EPD believes the 70 percent cap acity factor is not achievable by 2020. Commenter s suggested 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. Commenter s stated that Georgia's NGCC fleet capacity is not adequate to support a reliable power grid and 70% dispatch rate for NGCC. Commenter s stated that, while Georgia currently maintains a reliable power grid with NGCCs operated at a dispatch rate of over 51%, with the increased burden of NGCCs operated as baseline, future system reliability will be decreased.

Recommended Adjusting Interim Goals504 Commenter s suggested that, as an alternative to eliminating the interim goals, EPA should adjust the stringency of the states ' interim goals to account for the barriers and delays that states may face when implementing Building Blocks 1 and 2. Under this approach, the commenter s asserted that the state would still achieve the 2030 final goal established by the EPA based on the f our building blocks, but the stringency of the interim goals would be adjusted to reflect the state

specific schedule for the expeditious implementation of the control measures within the state. According to the commenter s , 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

- specific factors. C ommenter s further stated that the state plan would include f ederally

- enforceable milestones, for implementation of the emission reductions necessary to meet the final goal.

Commenter s requested that, in cases where EPA may be unable to adjust state interim goals prior to the issuance of the final rule due to insuff icient data, EPA establish a procedure for the adjustment of the state goals. C ommenter s stated that, under this procedure, a state would have the option to seek an adjustment of its interim goals based on a detailed technical demonstration that it was not feasible or practicable to implement all of the CO2 reductions under Building Blocks 1 and 2 by the start of the program in 2020. C ommenter s suggested that such state requests could be submitted to the EPA within 6 months from the promulgation of the fina l emission guidelines. C ommenter s further suggested that EPA could review and approve of such requests based on specified criteria, such as the amount of generation that would need to be re

dispatched as well as the barriers or limitations for achieving th e re

- dispatch.

Commenter s recommended that the EPA reconsider several 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 Complian ce Period

Commenter s expressed opposition to the idea of eliminating the interim compliance period or allowing states to devise their own interim compliance period requirements as some stakeholders have suggested, because they think it is important that th at states achieve emission reductions in a consistent manner across the compliance period and not delay emission reduction programs to the latter half of the decade.

Comment 5: C ommenters requested that the "glide path" be limited to those states that can demonstrate that they are unable to cost

- effectively 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 warranted but has modified the final rule compliance path and provided additional flexibilities. The 111(d) final rule requires that states develop plans that establish emission standards for affected EGUs. The rule provides 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 from505 2020 until 2 022), 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 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 Measures TSD for the CPP Final Rule supporting the final CPP.

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

Commenter s requested that, in the final rule, EPA clarify that amendments to the "glide path" are limited to those states with a demonstrated inability to cost

- effectively comply with the interim goal as proposed. Minnesota's C lean Energy Organizations appreciate EPA's attempt to make state compliance with the Clean Power Plan as flexible as possible. C ommenter s also requested that EPA set an interim goal based on average emissions during the 2020

- 2029 timeframe. C ommenter s stat ed that, as with EPA's expectation regarding 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 g oal in a cost

effective manner before EPA makes any changes to the "glide path," such as those identified in the NODA. According to the commenter s , for states like Minnesota

- states that have renewable energy generation in 2013 beyond the 2030 goal, robus t RESs and energy efficiency standards, and coal

- fired EGUs with existing natural gas infrastructure

- it is possible that the current interim goal structure will be entirely feasible using cost

- effective measures. C ommenter s stated that, in other words, e arly action credit is likely unnecessary for states that have already taken significant early actions because those states, like Minnesota, are well positioned to comply with the Clean Power Plan in a cost

- effective manner.

Commenter s consider ed the NODA p hase

- in schedule approach 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.

Comment 6: Some commenters s upport ed or c onditionally s upport ed an a llowance for e arly

a ction c redit , while other commenters felt that this 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 plans.

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

Specifically Support Early Action Credit

C ommenters believe d that early crediting should be allowed.

Commenter s supported providing full credit for early actions that result in reduced CO2 emissions before the compliance period begins in 2020.

Commenters reported that, allowing states to recognize early action that reduces emissions between 2012 and the start of the interim compliance period is an important tool that could be506 useful to some states when designing compliance plans. Commenter s agreed with the EPA's assertion that it is important to recognize early reductions so as not to create disincentives for
pre

- 2020 reductions and that the final guidelines should permit early recognition of reductions as states develop their individual glide paths to the 2030 goal.

According to commenter s , 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. Commenter s asserted that, while 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 utilization of existing NGCC units to meet the interim goals. Commenter s further asserted that credit for early RE and EE reductions also does not address infrastructure concerns or other tec hnical challenges associated with increasing the utilization of existing NGCC units.

In addition, commenter s argued that, given the timing challenges states face in submitting timely compliance plans for EPA approval, it is unlikely that states would be ab le to begin compliance plans early in order to take advantage of pre

- 2020 reductions. Commenter s asserted that, if states would like to do so, the final guidelines should make it clear that this is an option. Nonetheless,
commenter s reported that early rec ognition, is not sufficient to alleviate these concerns and does not obviate the need to eliminate the interim compliance goals.

Commenter s stated that, while the EPA identifies early action crediting as a potential response to stakeholder concerns regard ing Building Blocks 1 and 2, they believe that such an approach is justified for reasons beyond smoothing out a "glide path." C ommenter s asserted that early crediting for new actions will also spur states to act earlier, accelerating the expansion of the

a dvanced energy markets, driving earlier emission reductions, and providing states a longer period for compliance activity. Commenter s stated that early action crediting can achieve all of this without weakening the stringency of the emission targets. Conve rsely, commenter s asserted that providing no credit for early action threatens to counter

- productively stall continued expansion of advanced energy markets, and their associated emission reductions, until after 2020 when "full credit" would be available.

C ommenter s opined that early credit for emissions reductions would help ease issues related to interim goals. In addition, the commenter s believe d that early credit would send a signal to states encouraging early action on emerging problems.

Commenter s stro ngly supported EPA allowing early reductions credit to ease the 2020

- 2029 glide However, the commenter s asserted that the EPA should only consider such approach with respect to energy efficiency measures. According to the commenter s , this is because energy efficiency is a unique resource. Unlike other investments, the commenter s stated that energy efficiency continues to replace demand long after the actual measures themselves are installed. C ommenter s stated that the EPA's proposed rule would limit credit for energy efficiency savings installed prior to 2020, but would allow EGUs to claim credit for pre

- 2020 measures with respect to the savings those measures achieve after 2020 and beyond. C ommenter s expressed belief that the EPA should consider allowing cr edit for savings experienced as early as the baseline year of 2012, so long as EGUs can demonstrate a precise amount of savings using the Evaluation, Measurement and Verification (EM&V) methodology approved or developed by EPA.507 Furthermore, the commenter s stated that allowing EGUs to claim credit for past and/or current efficiency investments will avoid the threat of EGUs delaying large efficiency investments until later years so as to claim maximum credit when it counts.

A couple of commenters specifically supported the allowance for compliance of measures which occur between the baselines year(s), and the first interim compliance deadline in 2020. C ommenters opined that this would encourage states to act early in buildin g renewable generation and energy efficiency incentive programs to create a smooth transition into the compliance period, and would also provide some credit to states already making these investments. C ommenter s stated that, while it would not be appropria te 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. Commenter s supported incentives for early action to encourage investments in renewables and energy efficiency and a shift away from fossil

- fired 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.

Commenter s supported incentives for early action to encourage investments in renewables and energy efficiency and a shift away from fossil

- fired 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 have Already Taken Significant Early Action

Commenter s stated that early action credit is li kely unnecessary for states that have already taken significant early actions because those states, like Minnesota, are well positioned to comply with the Clean Power Plan in a cost

- effective manner.

Concerned Early Crediting Will Not Result in Similar Emi ssion Reductions to What Was Proposed/Provides Conditions for EPA to Consider If Early Action Credit Mechanisms Allowed

Commenter s expressed concern that allowing for early action credit may not result in the same level of emission reductions to the propos al. C ommenter s urged that, if the EPA believes that reliability claims must be addressed through some sort 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 atte mpt to "cherry pick" early actions only from low

- emission EGUs or emission reduction systems. C ommenter s opined that early action must consider all statewide EGU emissions in an early action period

- it makes no sense to provide a state with early action f or renewable energy deployment at the same time the state was increasing emissions from fossil

fueled generators.

Comment 7: Commenters said that the EPA s hould a ccount for r etirements o ccurring in the n ear t erm in Building Block 2 c alculations 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. The508 EPA does recognize retirements of high emitting units 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 t he specific public comments under this comment:

Commenter s requested that the EPA account for retirements occurring in the near term in Building Block 2 calculations. C ommenter s 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 few years are relevant for purposes of setting a baseline. However, the commenter s reported that the rule 's proposed compliance period will not begin until 2020. According to the commenter s , by including business

- as

- usual retirements in the target

- setting exercise, EPA fails to identify the best system of emission reductions, since states with re cent or imminent coal plant retirements may face relatively more lenient standards than other states. C ommenter s urged the agency not to allow states to ignore near

- term changes in the generation mix, including the large number of retirements expected to o ccur between 2012 and 2017 or 2018, when final state plans are due.

C ommenter s argued that, under EPA 's approach, generation from fossil fuel

- fired steam EGUs is expected to be reduced in equal measure to the excess NGCC capacity that is available for re

dispatch. For example, according to the commenter s , in Virginia, re

- dispatch to underutilized NGCC units would generate approximately 6 million MWh, so the state is expected to reduce its coal

- fired generation by that same amount. C ommenter s reported that Virginia 's coal

- fired generation amounted to 13.6 million MWh in 2012, but only 10.3 million of those MWhs were generated by units that are expected to continue operating past 2015. C ommenter s stated that, after a 6 million MWh reduction, the units that co ntinue to operate can either generate 7 or 4 million MWh depending on whether or not EPA accounts for near

- term coal retirements in its final guidelines. C ommenter s opined that this is a much more substantial difference in stringency than the range of opti ons under consideration for Building Block 1: a one

- percent difference in heat rate improvements at these Virginia units is comparable to 40

- 70,000 MWh of generation reduction.

Commenter s asserted that Tennessee 's situation also illustrates this point. As of this writing, the
commenter s reported that three coal

- fired units in Tennessee that were included in EPA 's goal

setting calculation have either retired or have announced plans to retire prior to the 2020 compliance period: Allen Steam Plant, Johnsonvill e Fossil Plant, and John Sevier Fossil Plant. According to the commenter s , these three facilities generated approximately 7.5 million MWh in 2012, and Tennessee 's 2030 target emission rate under the Clean Power Plan is 1,163 lbs CO2/MWh. Under Building Blo ck 2, EPA calculates that Tennessee can re

- dispatch approximately 3.3 million MWh annually from existing coal plants to existing gas plants if it scales up its gas

- fired generation to a 70 percent capacity factor. But, the commenter s 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 can simply bypass the reductions needed satisfy Building Block 2. C ommenter s reported that, even if Tennessee were to replace t he 7.5 million MWh produced by these retiring units with generation from new combined

- cycle gas plants (which the commenter s urged EPA not to permit for use as a compliance mechanism), it could avoid re

- dispatching any existing gas units entirely and still achieve a final emission rate of509 1,111 lbs CO2/MWh if it adopted the measures specified under Building Blocks 1, 3 and 4. In fact, according to the commenter s , these three retirements would give the state enough of a compliance margin that it could reduce its heat rate improvements at existing coal plants to just two percent and still meet its final target, assuming full compliance with Blocks 3 and 4. On the other hand, the commenter s stated that, if these three 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 reductions under Building Block 2, which would be determined by the then

- available excess NGCC capacity.

Commenter s requested that the EPA improve the fairness and effectiveness of the proposal by excluding near

- term "business

- as

- usual" plant retirements from the determination of BSER and the state emission targets. C ommenter s asserted that the most accurate process wo uld be for EPA or each state to calculate the state 's Building Block 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
commenter s , if Tennessee were to submit its p lan 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 commenter s stated that the EPA would use 2016 dat a. C ommenter s stated that this would ensure that plants that existed as of 2012 but have retired since that time are not included in either the target

- setting or compliance

determining process. It would also ensure, according to the commenter s , the use of the most accurate information concerning available underutilized NGCC capacity for purposes of calculating the enforceable state emission targets. Moreover, the commenter s requested that the EPA delete from its target calculations and compliance determinat ions any still

- existing plants with legally enforceable retirement obligations in place at the time the compliance period begins. C ommenter s asserted that this would ensure that Building Block 2 is fully effective in states like Tennessee.

Commenter s argu ed that their recommended approach for plant retirements would have the added benefit of resolving uncertainties regarding combined cycle plants that are currently under construction. C ommenter s stated that these plants are defined as NGCC units that were in existence as of the effective date of the section 111(b) proposal January 8, 2014 but that were not operating as of 2012. According to the commenter s , under EPA 's current approach, 15 percent of the generating capacity of an under

- construction NGCC is i ncluded in Building Block 2 's re

dispatch 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. However, the commenter s argued that, by using 2015 or 2016 data as a baseline, any facilities under construction as of January 2014 will likely be in operation and can simply be considered existing NGCC units. As such, the commenter s reported that any unde rutilized capacity can be included in the re

- dispatch scenario described in Building Block 2.

Comment 8: Commenters said that EPA d oes n ot h ave a uthority to e stablish e ither of the EPA's Building Block 2 p hase

- i n a pproaches

.510 Response 8: The EPA disagrees and has explained its authority in Preamble Section III: Rule Requirements and Legal Basis.

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

Commenter s asserted that both of EPA's Building Block 2 phase

- in approaches require EPA to have authority that it does not possess. According to commenter s , 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. Commenter s stated that the EPA does not have the authority to prescribe energy policy for a state. Under the second option identified, commenter s reported that the EPA has indicated that it "believes that the proposal provides states the flexibility to specify appropriate requirements for individual EGUs, including coal

- fired EGUs, t aking into account the potential for stranded investments and other unit

- specific factors." However, commenter s reported that, the EPA provides that if the tools available to the states are "inadequate to address 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 the book life of any major upgrades to the asset, such as major pollution control retrofits." Fed.Reg. at 64548

- 49. Commenter s argued that the EPA does not possess this authority; in their state (West Virginia), this auth ority resides with the WVPSC.

Comment 9: Some commenters said that the final rule should a ccount for r emaining u seful l ife of the a ffected EGU and suggested t aking into a ccount the b ook l ife of the f acility when d etermining the t imeline for a ttaining i nterim g oals , while other commenters opposed using the concept of book life.

Response 9: The EPA thanks the commenters but has determined that 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 V II.G

. The following are summaries of the specific public comm ents 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 that any improvements to Building Block 2 and the interim perio d must also take into account the remaining useful life of affected EGUs.

Commenter s 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 commenter s , the EPA relies upon the purported flexibility afforded states under its Proposed Carbon Rule, as somehow excusing its failure to consider the remaining useful life concept. However, the
commenter s , not all states have the same degree of flexibility unde r the Proposed Carbon Rule (cites Arizona as such a state). According to the commenter s , Arizona has a younger coal fleet511 and Arizona utilities have made large investments in their coal plants in recent years to comply with EPA regulations. C ommenter s repo rted that two coal plants were placed in service less than ten years ago. C ommenter s asserted that failure to consider the age of coal generating units will result in stranded investment from premature closure of coal plants, which will have significant retail rate implications and reliability implications.

Commenter s asserted that Arizon a is home to some of the newest coal fired units in the country with the most recent units commencing operation as recently as 2009. C ommenter s expressed that investments assume a long and useful life of 40 years or more. According to the
commenter s , the a pplication of Building Block 2 would 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. C ommenter s stated that retiring these units far earlier than a reasonable planned useful life would result in excessive stranded costs and ratepayers essentially paying twice for this generation capacity.

Commenter s recommended that the EPA adjust the Building Block approach to exclude remaining useful life units fr om the re

- dispatch calculation 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 commenter s , the additional timing will enable more cost effect ive decision making and reduce the cost and reliability impacts associated with stranded coal investments and simply defaulting to natural gas for compliance.

C ommenter s stated that EPA's proposal requested that comments be submitted to EPA, so that EPA c an 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 commenter s , the CAA does not direct EPA to consider remaining useful life, rather it commands that the EPA "shall permit the State in applying a standard of performance to any particular source under a plan submitted under this paragraph to take into consideration, among other factors, the remaining useful life of the existing source to wh ich such standard applies." C ommenter s further stated that the EPA has established emissions targets that states are not allowed to alter and, through the NODA and Rule Proposal, withholds the statutorily guaranteed power to states to assess useful life (a nd other factors); rather than giving that authority back to the states, EPA assumes this role itself. According to the commenter s , this is in direct and illegal conflict with the CAA. C ommenter s asserted that the EPA must provide 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 Remaining Useful Life) of a Facility

Several comme nters expressed that "book life" of the 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.

Commenter s believe d that the final EPA rule mu st allow states to consider and use book life and remaining useful life (assuming 40 years) of the original generation asset, as well as consider the impact on book life and remaining useful life of any major upgrades for pollution control equipment to the asset, even if that results in those units operating beyond 2030. According to512 the commenter s , book life and remaining useful life can be used to extend the glide

- path or to raise the overall goal. C ommenter s stated that, for Arizona, five coal

- fired gene rating units have remaining book lives that would result in their economic operation into the period between 2020 and 2030: Cholla (through 2024), Springerville (through 2025), and Springerville (through 2030). According to the commenter s , there are also f ive coal units that have remaining book lives that would result in operation beyond 2030: Apache ST, Coronado, and Springerville

. C ommenter s reported that, absent consideration of book life and remaining useful life, the stranded investment in Arizona coul d be up to $3 billion.

Commenter s stated that the EPA could either take book life into consideration itself or allow states to do so in calculating state

- specific goals.

Commenter s caution, however, that book life is not, by itself, an indication of "useful life." According to the commenter s , many assets, including EGUs, will have useful lives that far exceed the nominal "book life" due to care in operation and maintenance practices , investment in emissions controls, state prudency requirements, reliability needs, and overall economic value. Thus, the commenter s asserted that the fact that an EGU may be beyond its nominal "book life" is not an indication that the EGU is no longer use d and useful, is inadequately controlled, or is the subject of inappropriate life extension. Any such conclusion would require evaluation of many factors that are beyond the scope of this rulemaking.

Commenter s explained that, book life does, however, pre sent a potentially useful way of better integrating cost considerations related to "remaining 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 reductio n in EGU usage) prior to the end of the book life, according to the
commenter s , has cost implications

- unrecovered costs from running an EGU at a reduced capacity factor or not running an EGU that was expected 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. C ommenter s stated that, if the EGU does not run, those costs that would have been recovered during the longer run life must still be absorbe d 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). C ommenter s asserted that the earlier re

- dispatch (reduced utili zation) occurs within the life of an EGU, the higher the cost of that re

- dispatch.

In summary, commenter s are proposing that EPA modify the methodology used in Building Block 2 to re

- dispatch coal

- fired EGUs to NGCC EGUs such that re

- dispatch does not occ ur until the latter of 2020, the end of initial book life, the end of 20

- year pollution control project book life, or, for EGUs subject to a shutdown or natural gas conversion requirement prior to December 31, 2029, the date of such shutdown or conversion. C ommenter s expressed belief that it is important to emphasize that their proposal 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 shou ld be retired or cease burning coal.

Commenter s 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 their state when setting Building Block 2 targets513 Several commenters specifically opposed/conditionally supported the EPA basing the glide path on the book life of a facility.

Commenter s objected to EPA's suggestion that book life is an appropriate means of implementing this statutory mandate. According to commenter s , book life is an accounting and
rate

- making concept that concerns depreciation. Commenter s stated that it does not describe the end of useful life of an asset, which should b e determined on a case

- by

- case basis. Moreover,
commenter s opined that the statutory mandate to consider the remaining useful life by implication includes the discretion to exempt such sources from regulation.

Commenter s asserted that basing the glide pat h on book life does not account for circumstances where continued operation of the facility beyond the end of its book life is needed for system reliability. Commenter s stated that a facility may have an additional 20 years of remaining useful life beyond the end of its book life. Commenter s also stated that building book life into the glide path will not necessarily protect facility owners from stranded investments. Commenter s reported that facilities selling power into organized markets recover their capi tal investments according to market conditions, without a recovery guarantee and that operating units beyond the end of their book lives is therefore often necessary to recover investment capital. According to
commenter s , future market conditions cannot be predicted and states will not be able to predetermine a glide path for these units that ensures cost recovery. Commenter s asserted that, even facilities that sell into unorganized markets, and thus may have some form of guaranteed return through a FERC ta riff or state rate, may not be able to recover the costs of pollution control retrofits if these are not included in their respective tariff or rate.

Commenter s asserted that "book" life is not the criteria section 111(d) authorizes states to consider. Ins tead, commenter s 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.

Commenter s suggested that, if EPA determ ines to recognize 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 c oncerned that the EPA's p roposed g lide p ath w ill i ncentivize

s ignificant n atural g as i nfrastructure i n the e arly y ears of the c ompliance p eriod 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 renewable 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:514 Co mmenter s were concerned with the "glide path" proposed by the EPA and the incentive it might create to build significant natural gas infrastructure in the early years of the compliance period. Commenter s recognize d the need for some compliance flexibility early on. Therefore,
commenter s proposed limited banking and urged EPA to carefully consider whether the proposed "glide path" will create an early incentive 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 measures in the long term. Commenter s reported that natural gas has a history of price fluctuations, and a low cost in the U.S. in 2014 doesn't guarantee it will remain inexpens ive in 2020 or 2030, particularly given the very high price for natural gas elsewhere in the world and increasing demand for the product. Commenter s recommended that a portfolio of energy resources can act as a hedge against price increases in natural gas; particularly as the price of renewable energy continues to decrease. Commenter s stated that their plants, for example, use conventional steam turbines, and when combined with thermal energy storage have the same operational characteristics of fossil fuele d power plants, without their emissions. Commenter s also urged the EPA to recognize the speed of solar deployment, along with the modularity of solar, which makes it a great choice for meeting incremental generation needs and can assist states in quickly a chieving compliance with EPA regulations under section 111(d). Commenter s highlighted that the development and construction timeline for a large, centralized conventional fossil fuel power plant is typically a multi

- year process (and longer for nuclear ene rgy) and that the 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 and enforceable agreements between states and operators of coal

- fired power plants to cease coal combustion at a date certain during the interim compliance period.

Response 11: The EPA thanks the commenters. The EPA has modified the start of compliance and the application of the interim goals and believes that this revised path does not need the extra provisions recommended by the commenters. See Preamble Section V.

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

Commenter s stated that they would support EPA's glide 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 agreements between states and ope rators of coal

fired power plants to cease coal combustion at a date certain during the interim compliance period. Commenter s asserted that these agreements effectively shorten the book life of those plants. Commenter s reported that a limited book life app roach 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 energy during the interim compliance period.515 Comment 12: Commenters suggested that s tates could rely on other existing market mechanisms to define emission reduction glide paths ( e.g., competitive wholesale markets administered by RTOs).

Response 1 2 : The EPA thanks the commenter s

. The EPA believes that 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 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 examp le, 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 regulatory requirements and appropriate mechanisms. 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:

Commenter s asserted that states could rely on other existing market mechanisms to define emission reduction glide paths. For example, according to commenter s , the competitive wholesale markets administered by RTOs could be used to define a reduction trajectory for

s tates. Under such an approach, commenter s explained 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. Commenter s stated that this would alter the dispatch of u nits to better reflect their CO 2 emissions and provide a mechanism for continued emission reductions from existing units in a way that both respected system requirements and ensured reliable operation of the portions of the grid administered by the RTOs.

C ommenter s suggested that the EPA could provide that while the carbon adder is used to affect dispatch, states would not be required to file annual compliance reports or otherwise demonstrate compliance with the proposed guidelines in recognition of the fac t that the maximum amount of

re

- dispatch that could be supported by the system operated by the RTO would be accomplished. Commenter s stated that this "safe harbor" would give states and electric utilities time to undertake actions and measures that result in emission reductions later, in recognition of, as discussed above, the infrastructure challenges related to implementing Building Blocks 1 and 2 and the timing issues related to implementing legislation necessary to implement Building Blocks 3 and 4. Com menter s further stated that it would 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 the emission rate formula proposal.

Commenter s stressed that, importantly, because the carbon adder relies on existing market structures, it could be implemented soon after state compliance plans are approved (and before 2020) to start reducing emissions. Commenter s added that, as noted, th e EPA should strive to create state flexibility that promotes early achievement of emission reductions. Further,516 commenter s suggested that, to address concerns about costs for electricity customers, the carbon adder could be collected by the market operato rs and then used to offset increased costs to customers, ensuring that electricity remains affordable for end

- users.

Commenter s suggested that, to support the potential use of this option to define state glide paths, the final guidelines should recognize t he value of using existing market dispatch structures to achieve emission reductions and specifically note that states could pursue this option as part of an approvable plan. Further, commenter s suggested that the final guidelines could include a carbon ad der value for states to require affected units to use when bidding into competitive markets.

Comment 13: Glide p ath f lexibility s hould also be a pplied to o ther m ethods of c ompliance (i.e.,

s hould be a vailable for e lectric i nfrastructure d evelopment, s hould not be l imited to c oal to g as

r e

- d ispatch).

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 the flexibilities in the path in the final rule. The EPA believes that states have the flexibility to adjust their plans to accommodate their own infrastructure timeline needs within this overall compliance glide path. The flexibility in the CPP includes, for example, the choice of approaches, trading, tim e 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 ma y consider local circumstances as they develop their plans, including other regulatory requirements, gas infrastructure, and electric infrastucture. 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:

Some commenters, though supportive of the additional "glide path" flexibility proposed by EPA for gas in frastructure development in the NODA for Building Block two, expressed that such "glide path" flexibility should also be applied to electric infrastructure needs.

Commenter s requested that the EPA apply the "glide path" flexibility proposed in the NODA to address gas pipeline and transmission infrastructure ("gas infrastructure") to also address electric system infrastructure ("electric infrastructure") development where: (1) the 2030 compliance deadline is achievable and (2) flexibility is needed due to th e timing of necessary electric infrastructure development.

Specifically, commenter s opined that, while EPA's proposal provides incremental reliability value relative to the proposed rule, such "glide path" flexibility should also be applied to electric infrastructure needs that could impact the overall State Plan's achievability over the compliance period. Commenter s opined that such flexibility would better position states, EPA, and entities responsible for reliability to most effectively mitigate and/or respond to potential reliability challenges resulting from electric infrastructure n eeds that require flexibility in the overall517 compliance strategy set forth in the State Plan, without jeopardizing the 2030 compliance deadline.

Commenter s explained that, while entities affected by the final rule have greater ability to develop electric i nfrastructure than gas infrastructure, electric infrastructure development is still subject to many of the same complexities and uncertainties as gas infrastructure development, e.g., state and federal permitting processes, construction and equipment const raints and/or delays, right of way processes, and other technical and/or legal issues. In particular, commenter s reported that, while the responsibility for assessing electric infrastructure needs and identifying related projects lies with certain reliabil ity entities, the technical, engineering, legal, regulatory, and financial aspects of such projects lies with the "owning" entity, which must coordinate all such projects with both state and federal regulatory entities (depending on the regulatory scheme f

or applicable regulations). Further, according to commenter s , where projects involve regional electric systems, such coordination can involve multiple state agencies. Commenter s reported that, in this way, electric infrastructure development 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 t he scope of the additional flexibility contemplated in the NODA. More simply put, commenter s stated where such issues justify flexibility for gas infrastructure development, they should also justify flexibility for electric infrastructure development invol ving each of the building blocks and their interaction under a State Plan. Further, commenter s explained that whether and when generation resources are built (and whether existing electric infrastructure is adequate to serve such new generation resources) is a variable beyond the control of relevant reliability entities in many regions of the country where generation is a deregulated, competitive commercial function. Commenter s asserted that this further supports the inclusion of electric infrastructure dev elopment with gas infrastructure development in the scope of the additional flexibility contemplated in the NODA.

Commenter s requested that the final rule provide that, where a demonstrated reliability issue would result without construction of necessary e lectric infrastructure, a state or region may depart from the "averaging requirements" for emissions reductions during the 2020

- 2029 compliance period and, instead, propose a more flexible (or region

- specific) "glide path" so long as the 2030 compliance go al is met and affirmative steps are being taken during the compliance period. Commenter s respectfully submitted that either of these approaches, or a combination of the two, authorized in the Final Rule would provide flexibility that may be necessary due t o the complexities and uncertainties of electric infrastructure development up front, resulting in certainty as the industry undertakes the significant actions needed to bring itself into compliance with the final rule's requirements by 2030.

Although comm enter s supported the application of "glide 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 substantial benefits to reliability, such flexibility would not be available where attainment of the 2030 compliance deadline is in jeopardy. Furthermore, according to commenter s , the NODA flexibility, even if expanded to electric infrastructure, may not address every situation that could ar ise during implementation of State Plans that may negatively impact grid reliability.518 Commenter s expressed that additional electric infrastructure needs will not be known until State Plans are developed and evaluated; however, it is anticipated, in both th e Proposed Rule and the NODA, that there will be substantial modifications to the overall generation resource mix during the compliance period. According to commenter s , this is significant because the current electric infrastructure has been built and main tained to serve existing load from existing generation resources. As the generation portfolio changes, in terms of Megawatt output or geographical and electrical locations, commenter s assert ed that it is likely that the electric infrastructure necessary
to support such shift will need evaluation and upgrading or additions. Hence, commenter s believe d that, as State Plans contemplate meeting CO2 reduction goals through means that impact the generation portfolio

- e.g., shifts to significantly higher utilizati ons of natural gas and renewable resources, the Final Rule should accommodate the complexities associated with the upgrading and/or addition of electric infrastructure. To address such potential circumstances,
commenter s reiterated their recommendation tha t the "glide path" flexibility designed to accommodate gas infrastructure for purposes of Building Block 2 also be applied to the overall compliance requirements during the interim period, rather than limiting this flexibility to those portions of the glid e path associated with re

- dispatching existing resources to less CO2 intensive resources under Building Block two. Commenter s stated that this flexibility should also apply where: (1) electric infrastructure needs are identified; (2) additional flexibility is needed between 2020 and 2029 regarding achievement of interim performance goals and/or expectations in the State Plan for the other aspects of a state plan (including achievements of building blocks one, three, and four and the interaction of all build ing blocks in a state plan); and (3) the State Plan still contemplates meeting the 2030 compliance deadline.

Commenter s asserted that, as delays in the siting and construction of electric transmission infrastructure could impact achievement of compliance t hrough the use of renewable energy 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 needs could affect units that otherwise might wish to retire placing increas ed pressure on achieving 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

- dispatch as the NODA outlines. Rather, commenter s

as serted that, so long as specific reliability issues affecting plan achievement can be supported by the applicable reliability authority, the ability of a state or region to tailor its "glide

- path" trajectory should be available as an overall tool to ensure reliability without being artificially constrained solely to achievement of one particular method of compliance.

Commenter s reported that detailing of this RSV

- style flexibility (and the evidentiary requirements surrounding same) would provide welcome ce rtainty as the industry undertakes the significant action needed to bring itself into compliance with the final rule's requirements by 2030.

Comment 14: Commenters recommended a lternative g lide p ath o ptions and r ecommended

c hanges (e.g., d efined e xceptions, a llowance for s tates to d epart from s trict a veraging of

e missions, Building Block 2 c alculation c hanges) to the g lide p ath

.519 Response 14: The EPA thanks the commenter s , and has made modifications 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 states with substantial flexibility 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 before the start of the interim performance period (postponed from 2020 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 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 th e 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, commenter s stated 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 with the 10

- year glide path provided for Building Block 3 and Building Bloc k 4. C ommenter s include d an appendix to their comment letter that provides examples of what a linear glide path, combined with other proposals they include in their comments, might look like.

Case by Case Relief/Defined Triggering Events

Commenter s asserte d that, on a regional approach, the "glide path" may be achievable. However, according to commenter s , there is little flexibility in the rule for specific conditions arising either at the outset or during the 2020

- 2029 compliance period. Commenter s opined that this could make the strict averaging of emissions reductions over the 2020

- 2029 compliance period unachievable, in spite of the inter

- temporal flexibility the "glide

- path" offers to effectively bank and borrow emissions rate reductions over the initia l 10

- year "glide

- path." Commenter s suggested that the EPA address up

- front any identified reliability challenges in one of two ways:

(1) Case by Case Relief

- Indicating in the final rule 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 appropriate state or regional "glide

- path" so long as: (a) the 2030 compliance target is met and; (b) affirmative steps are being ta ken during the interim compliance period to timely and cost

- effectively address the identified reliability issues; or

(2) Relief Based on Defined Triggering Events

- Amending the proposed rule to allow for defined exceptions to meeting the state specific average interim target, if specific infrastructure additions are not being added on a timely basis to meet the emissions averaging requirement520 during the interim compliance period such as additions of new electricity transmission or natural gas pipeline i nfrastructure.

According to commenter s , the first approach outlined above would allow for case

- by

- case determinations to be made initially at the state level and ultimately approved by EPA based on specific fact circumstances presented at the time. Commen ter s reported that the second approach would be more structural in nature by identifying those "triggering events" up front in the Proposed Rule and enumerating the process a state would use to justify its departure from the averaging requirement presently found in the proposed rule. Commenter s opined that either of these approaches, or a combination of the two, authorized in the final rule would signal needed flexibility in the final rule (and the evidentiary showing required by a state or reliability enti ty to meet the standard) up front rather than simply leaving the issues to later litigation and enforcement actions during the compliance period itself.

Changes to Building Block 2 Calculation

Commenter s stated that, as much as the shift EPA has proposed a s 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 commenter s recommended the following two adjustm ents to EPA's Building Block 2 calculation:

(1) C ommenter s 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 necessary to support this level of utilization is in place or to increase the use of other compliance strategies.

(2) C ommenter s recommended that 2012 generation from oil/gas steam units be excluded from the goal computation.

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 factor in 2012 (recommendation number 1). (In 2012, the commenter s reported that the natural gas prices were relatively low, so NGCC utilization rates were relatively high.) According to the commenter s , the EPA could take a range of approaches to introducing NGCC to the goal setting equ ation. C ommenter s suggested that, to be consistent with the proposed approaches to renewable energy and energy efficiency, EPA could start increasing NGCC from 2012 levels in 2017 to the 70 percent target in 2029. Alternatively, the commenter s suggested th at EPA could consider reaching the 70 percent level in 2025. C ommenter s 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 often used as a backup to coal and natural gas base load generating facilities. In 2012, the commenter s reported that NGCC capacity factors increased si gnificantly and coal steam utilization rates declined. However, the commenter s reported, the average utilization of natural gas and oil steam units was virtually unchanged between 2011 and 2012, demonstrating that utilization rates of oil/gas steam units d o not521 correlate with NGCC capacity factors. According to the commenter s , 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 commenter s stated that the EPA would treat 2012 oil/gas steam MWhs like it does "Other Generation" in there

- dispatch analysis, meaning not subject to NGCC

re

- dispatch. According to the commenter s , this would avoid situations where the re

- dispatch of NGCC capacity would eff ectively eliminate 100% of oil/gas steam MWhs in the state goal computation and would preserve an element of fuel diversity that we believe is important to capture in the goal computation.

Commenter s recommended a few targeted changes to the Building Block 2 calculation that, according to the commenter s : (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 attun ed to the statutorily

- mandated " remaining useful life " concept. The commenter s ’ recommended changes include the following:

• Re

- dispatch from coal

- fired EGUs to NGCC EGUs should occur upon the later of any of the following, if re

- dispatch would occur prior t o January 1, 2030:

• January 1, 2020;

• January 1 of the year following 40 years after initial commencement of operation;

or

• January 1 of the year following 20 years after commencement of operation of significant air pollution controls at any EGU if insta llation occurred prior to issuance of the final 111(d) rule, or after commencement of operation of selective

non

- catalytic reduction (SNCR) or electrostatic precipitators (ESPs) at an EGU owned by a small utility, as defined by the Federal Energy Regulator y Commission (FERC), if installation occurred prior to 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 implemen tation plan or enforceable Title V permit, provided that such commitment is entered prior to the effective date of the final rule and the date of shutdown or natural gas conversion is prior to January 1, 2030.

• Coal

- fired EGUs that do not re

- dispatch pri or to January 1, 2030 remain coal

fired EGUs for purposes of calculating the interim and final goals.

The commenter s believe d that their proposal is consistent with concepts introduced in the NODA, and would provide significant and much

- needed relief to s tates 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 commenter s , not only would their proposal accommodate proper consideration of remaining useful life in setting522 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.

Commenter s provided a figure to illustrate that t he impact of the changes they proposed would be minimal nationwide and that only a handful of states would be significantly and disproportionately impacted by Building Block 2 would be affected by their proposed changes.

Commenter s supported the Clean Ene rgy Group's alternative proposal that promotes a "glide path" approach for increasing the rate of utilization of NGCC plants to ensure reliability is maintained and the goals of the regulation are achieved. The commenter s noted that the following three rec ommendations are made as a package, and are not meant to be taken separately.

• First, the commenter s recommended that, in developing the proposed state targets, 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 necessary to support this level of utilizati on is in place or to increase the use of other compliance strategies.

• Second, the commenter s recommended that 2012 generation from affected oil/gas steam units be excluded from the goal computation since oil/gas steam units serve a different segment of th e dispatch curve and are often used as a backup to coal and natural gas base

- load generating facilities, as opposed to a replacement for those facilities.

• Third, the commenter s

-- recommended that EPA retain 10% to 12% of coal steam MWhs in the state goal computation.

The commenter s further stated that other stakeholders have suggested a higher capacity factor and suggested that EPA evaluate the viability of a higher capacity f actor for states with an increased penetration of natural gas and zero

- emission resources as a lower target may, in fact, be appropriate.

Milestone Approach

Commenter s favored a milestone approach for measuring progress during the years preceding the 2030 goal. C ommenter s stated that a milestone approach would allow for stepped reductions in a manner that comports with the Nevada Public Utilities Commission's integrated resource planning (IRP). C ommenter s further stated that it would give states greater fle xibility in meeting their final goals and would create meaningful targets that take into account planned retirements of coal

- fired EGUs. According to the commenter s , 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. C ommenter s opined that such a process is more likely to result in targets that address stakeholder concerns, such as infrastructure im provements, stranded investments, continued safety and reliability of the grid, and overarching federal laws such as the National Environmental Policy Act.523 Shorten the compliance trajectory; create a least

- emissions dispatch hierarchy

Commenter s stated tha t the EPA should strengthen rather than weaken the compliance trajectory or "glide path" of emission reductions. Commenter s believe d that, assuming that a life

- cycle analysis shows that natural gas plants do outperform coal

- fired plants, Block 2 should cre ate a dispatch hierarchy that favors the least

- emitting sources (rather than NGCCs only) whenever possible. Commenter s stated that under a least emissions dispatch hierarchy, increasing utilization of NGCC units to 70% of capacity or encouraging 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

- decreasing use of fossil fuels, should be the policy driver informing the target. Commenter s asserted that the targets for RE and EE should be steeply increased while their phase

- in time is shortened, decreas ing the frequency of dispatch to NGCCs. Commenter s added that these measures should make the EPA's concerns about any potential infeasibility of higher NGCC utilization rates unnecessary.

Commenter s also noted that the EPA's concerns about the effects of t he Proposed Rule on states that currently lack sufficient NGCC capacity to meet the Block 2 target is focused solely on whether those states can or should build additional NGCCs. According to the commenter s , a least

- emissions dispatch approach diminishes o r avoids that concern as it will incentivize the construction of new renewable generation over new fossil

- fuel generation. Commenter s pointed out that the EPA has already set extremely low targets for those states that have both few renewable energy resour ces and few natural gas

- fired plants, and suggested these states also can use emission

- reducing measures outside of the Proposed Rule and/or join regional plans.

Commenter s concluded that stakeholder fears that some coal

- fired plants may have to stop
opera ting by 2020 even though they have made significant capital investments are not legitimate
reasons to re

- design the Proposed Rule. According to the commenter s , section 111 is concerned with exorbitant costs to the industry, not to a few individual faciliti es, and in this case the vast number of flexibilities in the Proposed Rule assures that states can comply with their targets in any event.

Comment 15: Commenters do n ot s upport the c oncept of a g lide p ath

. Response 15: The EPA thanks the commenter s . In response to additional analysis and many comments, we have modified the proposal and RIA

. The EPA would agree with the commenter s that further introduction of a glide path is not necessary if the commenter s means that extending a nuclear plant life would permit emissions reduction consistent with the requirements for the interim goal. The 111(d) final rule requires that states develop plans that establish emission standards for affected EGUs. We are providin g 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 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, includin g other regulatory requirements and the “useful life” of assets. See sections V.D, VIII.A, VIII.C and VIII.G of the524 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 follow ing are summaries of the specific public comments under this comment:

Commenter s expressed that, for states like North Carolina that have already achieved high heat rate improvements (HRI), there exists little to no room for further HRI in the next few years. C ommenter s reported that the North Carolina Department of Environment and Na tural 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 goal through infrastructure changes such as extending the life of a nuclear plant or conversion from coal to g as late in the 2020

- 2029 performance period (were those mechanisms found to be legally authorized).

Comment 16: Commenters requested that the EPA d elay the c ompliance d eadline

. Response 16: The EPA disagrees with this comment on moving the deadline . In response to additional analysis and many comments, we have modified 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 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 incl udes, 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, although the final compliance year is 2030), 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 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 Measures TSD for the CPP Final Rule supporting the final CPP.

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

C ommenters specif ically requested that EPA consider delaying the compliance deadline for the rule.

Commenter s 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. C ommenter s stated that u nder the proposed rule, significant carbon reductions (80 % of the final compliance requirements) would be needed by 2020 in order to meet the 2020/2029 interim goals. C ommenter s state d that a delay of five years would not materially impact the re

- dispatch obligation, but would allow time to make the necessary transmission and gas infrastructure improvements to accommodate the proposed plant retirements and the construction/operation of new gas

- fired power plants. As for the impact on the ETCs, the commente r s reported that a five year delay shifts approximately $1.1 B of $2.9 billion impacts to later years. Also, according to the commenter s , operating Nelson 6 and ISES

- 2 for an additional five years would bring these plants right up to the point when525 signifi cant expenditures (

- $400 million per unit) would be required for flue gas desulfurization systems (FGD, or scrubbers) for S02 National Ambient Air Quality Standards (NAAQS) compliance and Selective Catalytic Reduction (SCR) for Ozone/NOx NAAQS compliance.

Commenter s stated that, in order to prepare adequately 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 prior to 2020. C ommenter s asserted that additional time for compliance with the proposed rule would give utilities more flexibility in the

near

- term to meet the initial targets, and additional time in this instance would lower cost and other impacts on electric utility co nsumers.

3.2.12 Other

This section discusses issues related to building block 2 that do not fit in the other subsections of section 3.2.

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

Comment 1: Commenter s stated the EPA should amend the final rule to prioritize and drive permanent retirements from high

- intensity sources.

Response 1: The EPA thanks the commenter s . In response to additional analysis and many comments, we have modified the proposal and RIA

. The final rule is designed to drive permanent reductions, but to provide flexibility about how these are achieved, rather than driving 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 fl exibility 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 perfo rmance periods. The Building Blocks are not prescriptive, and states may consider local circumstances as they develop their plans, including infrastructure, and the “useful life” of assets. With attention to reliability, t he emission performance rate s refl ect not maximum stringency, but reasona ble stringency . 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:

To ensure that the CPP achieves the maximum intended emission reductions, commenter s suggested the EPA finalize the CPP to prioritize and encourage permanent retirement of the oldest and highest

- intensity sources of carbon pollution. Commenter s stated that there is no dispute that there are multiple different approaches to compliance with EPA's CPP, and to some extent, Sierra Club supports the rule's flexibility. Commenter s provided modeling anal ysis to526 show, however, that the EPA can (and should amend) the final rule to remove any artificial and arbitrary constraints on the deployment of renewable energy generation and energy efficiency savings. Commenter s stated that, only by doing so, can the E PA drive the kind of carbon emission reductions necessary to meaningfully impact the spiraling costs of climate change.

Commenter s stated they used a modeling tool developed by Synapse Economics and ran multiple scenarios assuming that certain coal

- burnin g EGU that will turn 50 years old during the compliance period actually retires on that date. Commenter s provided a table on pages 22

- 23 which lists units, first year operated, the 2011 CO2 emissions, the announced retirement (MWs) and the Total MWs. Comme nter s stated that, using EIA'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. Commenter s stated 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 growth, and (3) the Union of Concerned Scientists' observed annual growth of 1.1% of generation for the 2009

- 2013 time frame. For each scenario, Sierra Club used assumed EPA's baseline energy efficiency growth rate and low

- bound energy efficiency cost, which for the reasons stated above, Sierra Club believes are also unduly conservative and unrealistically low. Comme nter s stated 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, incorpor ated building block 1 and 1, but only included retirements that are planned or required.

Commenter s stated that these modeling runs demonstrate that, given the expected addition of natural gas units in Texas, the state will likely be able to comply with E PA's carbon emission targets relatively easily. Commenter s stated that, as a result, the CPP does little to encourage or compel any permanent retirement of coal

- burning electric generation units, despite the fact that these units are at the end of their us eful life. Commenter s stated the most direct and straight

forward means of meeting EPA's overall carbon reduction 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 en ergy, energy efficiency, or already

- planned natural gas generation. Commenter s 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 more than 29% from 2012 levels.

Comment 2: Commenter s urged the EPA, when considering stakeholder concerns about the stringency of building block 2 and its technical feasibility, to maintain the guiding principle of requiring states to first demonstrate technical infeasibility of final targets before adjusti ng targets based on specific building blocks, or to demonstrate the costs of implementation are significantly higher than EPA projections (79 FR 34893).

Response 2: The EPA thanks the commenter s

. The EPA requires states to develop plans that achieve the g oals of the 111(d) final rule

. The following are summaries of the specific public comments under this comment:527 Commenter s urged the EPA to use these expectations to reject attempts by states to demonstrate infeasibility on a piecemeal basis without demonstrating an inability to meet the final target

- as well as to provide sufficiently valid estimations for significantly hig her costs projections.

Comment 3: San Miguel refers the EPA to the expansive comments 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 commenter s . 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 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 (postpo ned 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 regulatory require ments 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 Final Rule supporting the final C P P

.

Comment 4: Commenter s asked for clarification regarding EPA's selection of capacity factors and raised issues regarding the adequacy of pipeline infrastructure.

Response 4: The EPA thanks the commenter s . 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 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 2020 until 2022), and the ability to shift emission rate achievement betwe en performance periods. The Building Blocks are not prescriptive. The building blocks are not requirements, but were used to calculate CO2 emission performance rates, and states may consider local circumstances as they develop their plans, including other regulatory requirements, 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 Chapter 3 of the GHG Mitigation Measures TSD for the CPP F inal 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) fleet capacity factor was 44

- 46%. How did the EPA determine that 70% utilization was BSER?528 2. Wha t was the technical basis for this determination? What literature did the EPA rely on and what additional analysis was performed? Why did the EPA not rely on peer

reviewed data? Why is 70% a "reasonable ceiling"? See GHG TSD p.3

- 11. What is the physical maximum technically feasible utilization rate 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 the EPA not look at coal generations numbers after all other BBs were applied?

5. Why d id the EPA not make any attempt to exclude NGCC units with low capacity factors, which would be exempt from 111(d) state plans under the proposed applicability language.

6. If the EPA is expanding the applicability criteria for the 111(d) rule, why did the E PA not explain how this impacts the applicability of the 111(b) NSPS for new and modified/reconstructed sources?

7. Why does Table 3

- 4 of the GHG TSD not demonstrate the ability for capacity factor growth to facilitate generation growth, but rather name plate capacity growth to facilitate generation growth.

8. In many states, as coal

- fired units are ramped down, the communities they formerly served will need new transmission connections to NGCC units elsewhere. Why didn't the EPA consider the additional electric transmission infrastructure required?

9. What technical analysis did the EPA undertake to justify 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 expansion will occur by 2020? What did EPA estimate the cost of necessary pipeline expansions would be? What was the technical basis for this calculation? What pipeline expertise or authorities did EPA rely on for making these determinations? What was the methodology for determining what authorities to rely on? Were all authorities peer

- reviewed?

11. Why didn't the EPA account for the fact that capacity from NGCC units in one state may already be committed to other states through firm contracts (and consequen tly unavailable for re

- dispatch within a state)?

Commenter s stated that (1) the EPA proposal entails significant fuel switching from coal to natural gas, (2) most retiring coal plants cannot simply be replaced by natural gas plants, (3) before this switch can occur, gas infrastructure, including storage facilities, must be built, (4) the necessary pipelines require permits, and in many cases, federal approval, (5) studies indicated the need for more than $300 billion in gas infrastructure investment between now and 2035 and (6)529 the EPA projects that its proposal will result in nearly 50 gigawatts of retirements of base

- load coal generation between 2016 and 2020, creating an even greater demand for infrastructure investment. Commenter s asked the following que stions :
a. What steps will your Administration take to ensure the necessary construction of interstate natural gas infrastructure, including pipelines? Will you consider expediting the environmental impact study (EIS) process so that gas transmission can b e built to serve constrained regions?

b. What is the estimated cost of the gas infrastructure required to meet compliance targets under your proposal, and who does the federal government foresee paying for it?

Comment 5 : Commenters noted that West Virginia's energy producing infrastructure depends on both natural gas and coal, which will affect compliance with the state’s CCP goal

. Response 5 : The EPA thanks the commenters. Coal, as well as natural gas, will continue to be an important part of the fuel mix under the rule (See 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 substantial flexib ility as to how they structure those plans to achieve the 111(d) requirements. States may consider local circumstances as they develop their plans, including other regulatory requirements, fuel diversity and the infrastructure. See sections V.D, VIII.A, VI II.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:

Commenter s 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. Commenter s stated that the construction of new NGCC plants,

co

- firing existing coal plants with natural gas, and 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.

Commenter s stated that despite the benefits of integrating natural gas into state's electric power

s ector, combined with the increasingly high cost of coal

- fired generation, West Virginia's rate

regulated utilities have increased their dependence on coal

- fired generation by acquiring three coal

- fired generating facilities from affiliated companies during the past year. As a result of these investments, commenter s believes that West Virginia ratepayers will likely bear higher compliance costs under the proposed Clean Power Plan, given the inability to avoid the costs of owning these plants while at the sam e time bearing the increased costs of pursuing opportunities under the third and fourth building blocks of the Clean Power Plan (i.e., renewable energy and energy efficiency). Commenter s stated that although these recent acquisitions by West Virginia utili ties may represent a step backward for reducing the state's carbon dioxide emission intensity,530 natural gas fired generation can play an important role going forward. According to the
commenter s , the Moundsville station NGCC plant is anticipated to go into service in West Virginia as early as 2018 and would provide 525 MW of high

- efficiency natural gas generation capacity. Commenter s noted that this additional capacity would stimulate additional demand for West Virginia natural gas, provide much needed resou rce diversity, and reduce the emission intensity of the state's power sector.

Comment 6: Commenter s expressed the view that a carbon emission regulation that targets coal

based power plants without encouraging a clear reinvestment strategy in the sector is impractical and unnecessarily burdensome.

Response 6: The EPA disagrees. The rule establishes emission performance rates. It does not set specific rates for specific power plants, and it provides inherent flexibility in operations. In response to additional analysis and many comments, we have modified the proposal and RIA

. 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 ex ample, 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 Buildi ng Blocks are not prescriptive, and states may consider local circumstances as they develop their 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 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:

Commenter s noted that coal plays an invaluable role as a fuel for baseload power generation in most markets because it is an inexpensive and readily accessible fuel supply shipped on an extensive rail distribution system. Commenter s stated the EPA's proposed rule cr eates powerful incentives for coal plants to retrofit with natural gas turbines

- a far less universally available fuel (at present) with far greater price volatility. Commenter s expressed appreciation that the emissions targets under the rule allow for ma ny paths to compliance, but expressed the opinion that there is an effectively unequal treatment of coal. Commenter s asserted that owners in this sector must be allowed greater options for rescuing assets through reinvestment, longer compliance timeframes, and emission offset strategies.

Comment 7: Commenters stated that as states convert power plants to natural gas, it is important that the resulting emissions be included in the states' goals.

Response 7: The EPA thanks the commenter s and agrees that the resulting emissions of existing fossil steam plants converted to NGCC should be counted, as this final rule does

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

Commenter s stated that the transition to cleaner energy has been underway for decades. Commenter s asserted that as Arizona converts its power plants to natural gas, it is vital that the resulting carbon emissions, even though they are lower than those from burning c oal burning, be measured, reported and included in the state goal. Citing the EPA's estimates of the health benefits of the proposed rule, commenter s expressed support for the proposed EPA emission reduction guidelines in order to accelerate the pace of im provement and put targets in place that will promote continuous and measurable caps on carbon pollution.

Comment 8: C ommenter s contended that the Clean Power Plan upsets the balance the policymakers in the state of Minnesota have strived to achieve by weighing strong environmental protections with the cost impacts and reliability requirements in their integrated resource planning process.
Response 8: The EPA thanks the commenter s

. However, the rule does 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 achiev e their goals . We are providing states with substantial flexibility as to how they structure those plans to achieve the 111(d) requirements, so that plans can be consistent with other state approaches. The flexibility includes, for example, the choice of a pproaches, 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 pres criptive, and states may consider local circumstances as they develop their 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 of the CPP and Chapter 3 of the GHG Mitigati on Measures TSD for the CPP Final Rule supporting the final CPP.

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

C ommenter s added that EPA's block two biases natural 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 electric generation needed to s erve their customers. C ommenter s 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 u se of the term "redispatch."

Response 9 : EPA agrees with those commenters that recognize that the CPP is consistent with current economic dispatch practice , and disagrees with those commenters who maintain that the CPP is inconsistent or otherwise problematic for current planning and dispatch of power.532 “Redispatch” as used in the proposal was, in practice, just the overall annual shifting of generation among resource types. The final rule uses the terminology of generatio n shifting, not redispatch. However, the proposed rule was intended and designed to work with current environmental regulations that are consistent with the current security constrained economic dispatch (SCED) protocols and to continue that history of c ompatibility 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 the BSER process and can be implemented consistently with the building bloc ks on which it is based. See Preamble Section V.
The following are summaries of the specific public comments under this comment:

Commenters stated that it is important to understand the EPA's use of the term "redispatch." The Commenters stated that normal ly, the term "dispatch" is used to define the order in which particular generating plants are lined up to feed electricity into the grid. The c ommenters stated that a number of factors, such as reliability, responsiveness 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 c ommenters stated that the dispatch line

- up works differently in competitive markets, where generation has been deregulat ed and therefore owners of generating plants are not guaranteed profits, and those where generation remains regulated with a guaranteed rate of return (subject to prudent management). The c ommenters stated that for instance, in markets where generation has been deregulated, generation that has the lowest marginal costs is dispatched first

- this usually means dispatch of utility scale wind and solar generation first, unless there are tec hnical reasons not to do so.

The c ommenters stated that the EPA's use of "redispatch" is not in the sense of a lineup of particular generating stations for dispatch of electricity into the grid at specific times; rather it is an estimate for each state of how much additional generation can be had from existing NGCC plants to displace coal over a one

- year period. The c ommenters stated that of course, an increase in renewable energy, nuclear energy, hydropower, solar energy, and other generation can also replace fossil energy. The c ommenters stated that however the EPA chose no t to apply the "redispatch" concept to any additional generation from these other generation technologies. Yet, the EPA itself noted in the CPP that "....renewable generation replaces predominantly fossil fuel

fired generation and thereby avoids the CO2 em issions from that replaced generation." The commenters stated t he use of the term "redispatch" is not the most felicitous in the sense that a lower CO2 energy generation technology can be used to displace a more CO2 intensive generation method. The commen ters stated will use the 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 t he term "shifting generat ion 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 part of the 13

- state PJM indepe ndent 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 manda ted by state implementation plans, this normal price phasing would reverse. Commenters said these changes would quickly affect electricity as a commodity; prices would rise; economies would shift. Commenters said that533 businesses' long

- term investment decis ions would increasingly exclude the Cincinnati region. Commenters said the CPP needs to clarify whether and how carbon can be a controlling factor for ISO operations. Commenters said that within the states, steps to control carbon emissions will require de liberate and coordinated planning among utilities, 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, bid

based economic dispatch; co mmenters stated these regimes 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 services" as transmission or generation

- related services "that are necessary to support the transmission of capacity and energy from resources to loads while maintaining reliable operation of the Transmission Provider's Transmi ssion System in accordance with Good Utility Practice." [Preventing Undue Discrimination and Preference in Transmission Service, Order No. 890, 72 Fed. Reg. 12,266 (Mar. 15, 2007), FERC Stats. & Regs. paragraph 31,241 (2007), order on reh'g, Order 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, several ancillary services may be procured from suppliers that offer to sell them at prices determined by ISO and RTO dispatch algorithms. Commenters stated that no ISO or RTO has r ules or dispatch 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 operating costs are called first to generate electricity

- with various reliability requirements and other factors as part of the decision, depending on the structure of various markets ." [see FERC Perspectives: Questions Concerning EPA's Proposed Clean Power Plan and other Grid Reliability Challenges: Hearing Before the Subcomm. on Energy and Power of the H. Comm. on En ergy & Commerce, 113th Cong. 3 (July 29, 2014) (written testimony of Philip D. Moeller, Comm'r, FERC), available at http://energycommerce.house.gov/hearing/ferc

- perspectives

- questions

- concerning

- epa%27s

proposed

- clean

- power

- plan

- and

- other

- grid ("Moeller Te stimony”).] 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 inform ed Congress that FERC

- jurisdictional RTO markets "would need to be fundamentally altered and redesigned to implement EPA's proposal to accommodate environmental dispatch." [see FERC Perspectives: Questions Concerning EPA's Proposed Clean Power Plan and oth er Grid Reliability Challenges: Hearing Before the Subcomm. on Energy and Power of the H. Comm. on Energy & Commerce, 113th Cong. 3 (July 29, 2014) (Answers to Preliminary Questions for the FERC, Philip D. Moeller, Comm'r, FERC), available at http://energy commerce.house.gov/hearing/ferc

- perspectives

- questions

- concerning

epa%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' exis ting economic dispatch rules have accommodated existing environmental rules on a plant

- specific basis, e.g., by permitting sellers to incorporate environmental costs into534 their offers. Commenters stated that this is no defense; EPA has proposed a radical
t ransformation of electric dispatch rules that is nothing like current RTO rules, and, regardless, EPA has no authority to take such action. Commenters stated that revising dispatch rules to focus on NGCC utilization rates instead of economic dispatch would in fact be a radical transformation. According to the commenters, FERC Commissioner Clark has explained that: "The Commission has allowed RTOs to acknowledge the operating limits of certain plants. Also the Commission allows generators to recognize variou s governmentally imposed costs like taxes and cap

- and

- trade schemes, but this is simply a matter of allowing generators to bid

- in costs that they have legally incurred. To go beyond that by changing the fundamental market dispatch algorithms in the ways so me have suggested would be a major change, to say the least." [see FERC Perspectives: Questions Concerning EPA's Proposed Clean Power Plan and other Grid Reliability Challenges: Hearing Before the Subcommittee 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

- perspectives

- questions

- concerning

- epa%27s

proposed

- clean

- power

- plan

- and

- other

- grid ("Clark Responses")].

Commenters raised questions regarding increased natural gas prices that prevent profitab le operation, and equipment breakdown. Commenters indicated that EPA's suggestion to increase

re

- dispatch of NGCC by limiting the operation of coal

- fired EGUs through Title V permits conflicts with federal mandates of large utility plants to operate for re liability purposes.

Commenters stated that the proposed rule relies on a flawed understanding of regulated wholesale electricity markets and the bulk power system. Commenters referenced and quoted Motor Vehicle Mfrs. Association v. State Farm Mut. Auto. In s. Co., 463 U.S. 29, 43 (1983) (agency action will be upheld only if it "articulates a satisfactory explanation for its action including a rational connection between the facts found and the choice made") (quoting Burlington Truck Lines, Inc. v. United Sta tes, 371 U.S. 156, 168 (1962)).

Commenters stated that all ISOs and RTOs use a form of regional, security

- constrained, bid

based economic dispatch; commenters stated these regimes 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 services" as transmission or generation

- related services "that are necessary to support the transmission of capacity and energy from resources to loads while maintaining reliable operation of the Transmission Provider's Transmission System in accordance with Good Utility Practice." [Preventing Undue Discrimination and Preference i n Transmission Service, Order No. 890, 72 Fed. Reg. 12,266 (Mar. 15, 2007), FERC Stats. & Regs. paragraph 31,241 (2007), order on reh'g, Order No. 890

- A, FERC Stats. & Regs. paragraph 31,261 (2007), order on reh'g, Order No. 890

- B, 123 FERC paragraph 61,29 9 (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, several ancillary services may be procured from suppliers that offer to sell them at prices determined by ISO and RTO dispatch algorithms. Commenters stated that no ISO or RTO has rules or dispatch 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 an535 inter

- regional or even a national level. According to the commenters, FERC Commissioner Moeller has testified, " simply put, the power plants with the lowest operating costs are called first to generate electricity

- with various reliability requirements and other factors as part of the decision, depending on the structure of various markets ." [see FERC Perspectives: Questions Concerning EPA's Proposed Clean Power Plan and other Grid Reliability Challenges: Hearing Before the Subcomm. on Energy and Power of the H. Comm. on Energy & Commerce, 113th Cong. 3 (July 29, 2014) (written testimony of Philip D. Moeller, Comm'r, FERC).] C ommenters 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 t hat FERC

- jurisdictional RTO markets "would need to be fundamentally altered and redesigned to implement EPA's proposal to accommodate environmental dispatch." [see FERC Perspectives: Questions Concerning EPA's Proposed Clean Power Plan and other Grid Relia bility Challenges: Hearing Before the Subcomm. on Energy and Power of the H. Comm. on Energy & 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 have accommodated existing environmental rules on a plant

- specific basis, e.g., by permitting sellers to incorporate environmental costs into their offers. Commenters stated that this is no defense; EPA has proposed a radical transformation of electric dispatch rules that is nothing like current RTO rules, and, regardless, EPA has no authority to take such action. Commenters stated that revising dispa tch rules to focus on NGCC utilization rates instead of economic dispatch would in fact be a radical transformation. According to the commenters, FERC Commissioner Clark has explained that: "The Commission has allowed RTOs to acknowledge the operating limi ts of certain plants. Also the Commission allows generators to recognize various governmentally imposed costs like taxes and cap

- and

- trade schemes, but this is simply a matter of allowing generators to bid

- in costs that they have legally incurred. To go be yond that by changing 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 Proposed Clean Power Plan and other Grid Reliability Challenges: Hearing Before the Subcommittee 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' stateme nts that the EPA's proposal would involve a fundamental shift from an economic dispatch system to an environmental dispatch system that would engender considerable conflict, controversy, and uncertainty for resolution by FERC within its statutory directive to 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 regulations. Commenters stated that FERC has

e nsured that variable renewable generation

- largely wind

- can participate effectively in the wholesale markets without undue discrimination. Commenters stated that it has not, however, ever required a generation dispatch preference for resources based on th eir emissions characteristics, or given a preference to certain types of generation resources for purposes of setting wholesale power sales rates or regulating transmission service.536 Commenters stated that FERC Commissioner Philip Moeller has stated that F ERC

- jurisdictional RTO markets " would need to be fundamentally altered and redesigned to implement EPA's proposal to accommodate environmental dispatch " [see Commissioner Philip Moeller's Answers to Preliminary Questions for the Federal Energy Regulatory C ommission, 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 appears 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 Regulation 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 reductions on a "sub

- regional" basis) ("Initi al MISO Study Results")]. Commenters stated that the Proposed Guidelines would mandate new regional coordination, e.g., by effectively compelling the creation of multi

- state dispatching arrangements in non

- RTO regions, expanding the scope of existing RTO d ispatch, or requiring RTOs to coordinate conflicting state plans

Commenters stated that both regulated and competitive electricity markets operate on a lowest cost dispatch model; commenters provided that power systems operate through running the lowest co st generation first, with higher and higher variable cost units then progressively operated until demand is met. Commenters stated that the proposed CPP instead assumes an arbitrary dispatch that is completely incompatible with Texas's policy goals of prov iding the most economically efficient dispatch of power plants.

Commenters argued that for the members of their regional reliability and transmission organization (RTO/RE), both the economic and reliability dispatch of EGUs is not determined by the indivi dual plant or the utility at all; those decisions 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 extre mely difficult and raises many significant issues that will need to 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 resolved b y 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 utility 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 RTO/ISO or non

- RTO/ISO within the state has which proportion of the compliance obligation?

Commenters asked what if one RTO/ISO uses one compliance method while the other uses an incompatible method?

Commenters asked what if one RTO/ISO is in a cap and trade system and the other isn't? How does the state determine proper dispatch of its generating plants in these circumstances?537 Commenters said since the states don't typically have regulatory control over independent power producers, the commenters questioned whether the state can order independent generators to alter their emissions. Commenters said there are substantial 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 withdrawing from RTOs so that dispatch within the state can be regulated by the state in a manner that allows the state to meet the EPA emission requirements in the most efficient way possible for the state, without concerns for regional impacts. Commente rs 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 state ensures that it can meet its obligations at the lowest possible cost. That leads to the question of whether and how RTO s could conduct state by state environmental dispatch to meet individual state emissions targets.

Commenters stated the key to RTO/ISO markets is that they are based on bids

- no seller has to divulge its cost to the dispatcher, and the generator itself is the one with responsibility to meet any applicable environmental laws or regulations applicable 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, the RTO generally has must

- run contracts with the generator which specifies when they can be called upon and how much they get paid. Commenters said while each RTO has different rules and operates in different environments, they all ha ve these common characteristics. Commenters posed this question in order to comply 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 under 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 in each state according to the state's plan for meeting emissions targets. Commenters continued this means the RTOs would conduct state

- by

state environmental dispatch, and questioned if they can do that? Commenters said first of all, RTOs have no regulatory authority to dispatch (or order a plant to operate). Commenters said it would have to negotia te terms and conditions with every 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 state d that emissions guidelines mandating 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 the competitive energy market an d could place EGUs at risk of early retirement, resulting in potential grid reliability issues; and that the dispatch of EGUs is beyond the scope of the EPA's authority, and the regulation of carbon dioxide emissions is beyond the authority of Regional Tra nsmission Organizations (RTOs) and Independent System Operators (ISOs). Commenters noted that the operation of a competitive energy market is the role of RTOs and ISOs while the 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 enfo rcement

.538 Commenters stated that EPA maintains the NSPS for existing sources does not need to be a national standard that is achievable at plants throughout 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 rather than regulating emissions reductions. Commenters stated that EPA maintains that electricity is fungible, and lower emitting fuels can be substituted for higher emitting fuels, and thi s policy would enable EPA in the future to claim a nuclear or wind plant obviates the need to build new natural gas plants. Commenters believed this regulatory approach enables EPA to de

- emphasize the importance of fuel diversity in the IRP process and pla ce an ever increasing reliance on emphasizing CO2 emissions reductions over economic costs, the value of fuel diversity and electric reliability.

Commenters stated that the re

- dispatch measures in building block 2 are not "limited to affected sources" bec ause owners or operators of affected EGUs do not dispatch electricity, citing that in the United States and Canada, Independent System Operators (ISOs) and Regional Transmission Organization (RTOs) coordinate, control, and monitor the electrical grid, incl uding re

- dispatch. Commenters added that in Louisiana, RTOs include the Southwest Power Pool (SPP) and Midcontinent Independent System Operator (MISO), and these entities are not affected sources per the proposed rule.

Commenters raised issues about how di spatch under CPP would be managed in RTOs/ISOs

• Can the RTO force a generator to agree to be dispatchable?

• Can EPA, FERC, DOE, the states (or anyone) force such a result? For FERC

jurisdictional utilities? For utility

- owned generation? For independent power facilities? For utilities (such as municipal utilities and cooperatives) that are not subject to FERC or state jurisdiction? For Power Marketing Administrations? For PURPA facilities?

• While the federal government can impose limitations on power plant sour ce emissions, can it impose and enforce dispatch requirements if states or RTOs can't?

• What new local market power problems or issues arise as a result of any re

dispatch regime? What does that mean to end

- use customers?

Commenters brought up the following group of questions:

• 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?539 • And there are security and reliability considerations 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 the grid and might be a candidate for shutting down o r not running to reduce emissions, that plant may "have other outputs voltage support or "inertia" qualities that may contribute significantly to grid stability."?

Commenters brought up the following group of questions:

• How does the RTO ensure that enough generation gets enough revenues to ensure that it doesn't retire and remains operational to maintain reliability, amid what is likely to be a constantly changing base of generation due to retirements of plants.

• Which plant retirement breaks the back of t he system?

• Commenters said all plants, regardless of their emissions, are going to want to run in the hours with the highest prices. Commenters said plants that would be economic to continue running if they run in high price hours might be uneconomic if t hey are shut out of those hours. Commenters said if they don't get to run in those high

- price hours, it may not be economic to keep the plants operational and more retirements will result. Will RTOs need to make some extra payments to keep those plants fro m retiring?

• Who will cover the costs of those payments?

• How is it determined what plants get such reliability payments?

Commenters stated changes in dispatch will change flows within the transmission system. Commenter s said the existing transmission grid is built and maintained based on fairly predictable patterns of load and the location of generation. 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 m ay be needed. Commenters said transmission 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 out the grid to reliably operate the system with changes in power flows that will result from changes in dispatch.

Commenters stated as Professor Bill Hogan at Harvard has observed, mandating priority for low carbon technologies in energy dispatch presents more complications than might first appear because of the nature of the transmission system interaction with electricity market design. Commenters said the complex interactions in the grid mean that changing how demand is met at one point in the grid changes flows in the grid, affecting mul ti

- plant dispatch that may increase emissions elsewhere in the grid and increase overall emissions. Commenters said the system impacts of emissions reductions at any particular plant location are not always easily predictable. Commenters said under environ mental dispatch, according to Hogan, "market structures540 currently based on bids and locational market pricing (LMP) in a framework of security constrained economic dispatch would confront a substantial disconnect between the economic prices applied in the settlements system and the opportunity 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 operations, arbitrage opportunities and tempt ations are created that could undermine the dispatch and the market." (See Hogan, William W., "Electricity Wholesale Market Design in a Low Carbon 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 cases, these FTRs are owned or acquired by load

- serving entities so a s to be able to hedge against their congestion costs consistent with their planned energy deliveries. Commenters said some RTOs auction FTRs and in some cases they are allocated to load

- serving entities, but they are a tradable commodity. Commenters said F TRs are important in that changes in an RTO's dispatch methods affect FTR values significantly, and, thus, changes due to environmental restrictions that do not have an economic dispatch basis will be extremely controversial as there will be winners and lo sers created in the FTR markets. Commenters said changes in the value of FTRs resulting from environmental dispatch will have numerous unintended consequences.

Commenters stated assuming that RTOs are to run environmental dispatch based on state direction, within states there will be options as to 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 independent generators beyond the reach of both RTOs and state regulators. Commenters questioned the following:

• How will fairness be ensured among generators within a state?

• Can states even dictate to RTOs how plants in the state should be dispatched?

• Can states, RTOs or FERC require NGC C 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 responsib ility for ensuring gas supply so that the NGCC plants can increase their capacity factors?541 • Does the RTO simply not dispatch the coal plants in that state and assume that regional demand will still be met by increased generation in other states that have
t heir own targets to meet?

• What if a state or states in the region fail to meet 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 any price sign al to prevent such leaning if generators are bidding their marginal costs as expected.

Commenters stated state

- by

- state environmental dispatch by RTOs is likely to be extremely inefficient, and RTOs will not be able to take advantage of lower cost emissio n savings in other parts of their footprint. Commenters said it will be important to understand the implications of an RTO dealing with a patchwork dispatch regime that treats generators differently depending on the state where they are located. Commenters said power flows within the RTO would certainly be affected, and actions taken in one state could have detrimental effects on the emissions rate and costs of electricity generation in other states, as it would be inefficient. Commenters said it would no l onger be clear what the extra expense of administering an RTO for a region is bringing to the table. Commenters said individual utilities can environmentally dispatch their own generation just as effectively as an RTO can dispatch their generation, and whi le the back office systems of RTOs may still have value for billing and settlements, it seems all the existing dispatch algorithms and software would become sunk costs.

Comment 10: Commenters believed that EPA should augment building block 2 of the Propos ed Rule based on inside the fence natural gas measures so that, if outside the fence measures (such 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 severability provision whereby those building blocks that withstand judicial sc rutiny should remain, 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 building block could allow the measures to remain in plac e as a basis for BSER should other measures not withstand judicial scrutiny.]
Response 10: We appreciate the spirit of the commenters’ recommendations. 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 purpose, and legislative history. Accordingly, we are confident that our interpretation will withstand judicial re view.