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TABLE OF CONTENTS

3.2 CO2 Reduction Potential from Generation Shifts Among Affected EGUs (Building Block 2) .....2

3.2.1 Ability of shifting generation among existing EGUs to reduce CO2 emissions............................2

3.2.2 Magnitude of generation shifts among existing EGUs................................................................100

3.2.3 Natural Gas Supply........................................................................................................................224

3.2.4 Technical Considerations..............................................................................................................236

3.2.5 Analysis of Cost-Effectiveness.......................................................................................................366

3.2.6 Natural Gas Price Impacts............................................................................................................403

3.2.7 Co-firing..........................................................................................................................................435

3.2.8 New NGCC .....................................................................................................................................438

3.2.9 Regional approach .........................................................................................................................445

3.2.10 Setting a floor ...............................................................................................................................465

3.2.11 Glide Path .....................................................................................................................................478

3.2.12 Other .............................................................................................................................................525
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3.2 CO2 REDUCTION POTENTIAL FROM GENERATION SHIFTS AMONG 

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 subsections are discussed 

below along with summaries the specific public comments.

At proposal, we referred to building block 2 as “Re-Dispatch of Existing Units,” and 

consequently this is the terminology used by the commenters on building block 2. We have 

retained 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 related to this subsection which are organized by 

topics (comments) below. Responses are provided for these topics.

Comment 1: Commenters stated that trying to squeeze coal out of the energy equation is not 

only unrealistic, but it's also dangerous and irresponsible.

Response 1: The EPA disagrees with the interpretation of the Rule. 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. 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 overconstruction of new generation. See sections V.D, VIII.A, VIII.C and VIII.G of the final rule 

preamble of the CPP and Chapter 3 of the GHG Mitigation Measures TSD for the CPP Final 

Rule supporting the final CPP.
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The following are summaries of the specific public comments under this comment:

Commenters referenced a study and stated the study finds that short-term natural gas may be 

worse than burning coal. Commenters stated these 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 costeffective.

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 final 

CPP for EPA’s detailed approach to the issues.

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

Commenters said that the potential to reduce carbon pollution at the point of combustion by 

using natural gas in lieu of coal is fully demonstrated. Commenters 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. Commenters 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

Commenters stated this shift 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. Commenters 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. Commenters 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. Commenters cited EIA data that indicate from 2003 to 2012, coal generation fell from 

about 2 million GWh to 1.5 million GWh.478, and 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; commenters stated that natural gas consumption for electricity generation 

increased 20 percent from 2011 to 2012. Commenters said that today natural gas plants are 

commonly operating as baseload plants, providing 27 percent of U.S. net power generation in 

2013, compared to only 10 percent in 1994. Likewise, commenters added, the use of natural gas 

to co-fire alongside coal in steam generating plants and the conversion of coal-fired power plants 

to operate on natural gas is well established. Commenters said that 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. 

Commenters 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 the 
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states in the Clean Power Plan Implementation Group. Commenters stated that NGCC units that 

were operating in their states in 2005 increased their generation 21 percent by 2012.51

Commenters added that this significant increase in utilization at existing NGCCs is a significant 

component of the system our states have collectively used to achieve emission reductions and 

improve emissions intensity. 

Comment 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:

Commenters said that the use of natural gas for power generation has proven to be an effective 

method of lowering carbon dioxide emissions. According to the Energy Information 

Administration, commenters said, US energy-related carbon dioxide emissions have declined in 

four of the last seven years since 2007 and are down a total of 10 percent from 2005 levels due in 

part to increased natural gas-fired generation. Commenters 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, commenters said, natural gas provided the US with 27 

percent of its total energy supply, and 28 percent of US electricity in 2013, up from 22 percent in 

2012. In the proposed rule's base case year of 2012, commenters added, power generation from 

combined cycle units and other natural gas generators reached an all-time high of 30 percent and 

contributed to carbon dioxide emissions falling to a 20 year low. Commenters said that these 

reductions demonstrate the ability of the natural gas industry and competitive markets to reliably 

deliver emission reductions without additional regulations. Commenters concluded that natural 

gas generation has a proven track record of lowering emissions, and its inclusion in the proposed 

rule recognizes its environmental benefits. 

Commenters stated that a recent "bottom-up" analysis of the potential carbon mitigation from redispatching the fleet of coal generating units to NGCCs by researchers at the National 

Renewable Energy Laboratory (NREL) found that this strategy holds the technical potential to 

mitigate over 500 million metric tons of CO2, or about 25 percent of the power sector's total 

emissions in 2012. Commenters stated the study found that over 300 million metric tons of CO2 

could be avoided at EPA's proposed 70 percent NGCC utilization "ceiling" 

Commenters stated that dispatch switches from coal to gas can be taken exclusively by regulated 

sources (EGUs) and provide a key, near-term source of emission reductions. Commenters

supported the EPA's approach regarding the 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. Commenters stated that various studies show 
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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. Commenters referenced the following 

studies: (1) the Massachusetts Institute 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 emissions; 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.

Commenters 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 their annual capacity 

factors by more than 10 percent (from 63.7 to 56.7 percent), according to EIA's Electric Power 

Monthly. Commenters pointed out that as a result, electric sector CO2 emissions were at their 

lowest level since 1996. Commenters added, however, that this shift in utilization was not 

consistent across all states, and there are operational considerations that the commenters believe 

should be reflected in the standard setting calculations. 

Commenters 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. Commenters stated these reductions are within reach in the 

near term and states should be encouraged to seize such opportunities. Commenters stated that, 

while concerns have been raised regarding infrastructure and other limitations, those discussions 

fail to reflect the extent to which many NGCC plants do have sufficient existing infrastructure 

and stand ready and able to operate at and above the target capacity factors. 

Commenters stated NGCC units can produce as much as 46 percent more electricity from a 

given quantity of natural gas than steam EGUs, making re-dispatch from coal and oil-fired EGUs 

a significantly less expensive way to reduce CO2 emissions than through natural gas conversions 

or co-firing. Commenters 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.

Comment 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 

rules, 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 flexibility as to how they structure those plans to achieve the 

111(d) requirements. The flexibility includes, for example, the choice of approaches, trading, 
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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. 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 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.

Commenters stated the EPA has not adequately considered the feasibility or costs related to redispatch and premature unit retirements, or considered the effect on system reliability, and there 

is no analysis of whether the existing transmission system can accommodate the dramatic 

changes that EPA's proposal may necessitate. Commenters requested the EPA to ensure that rules 

do not mistakenly accelerate the removal of electric generation capacity when corresponding 

alternatives are not available endangering the availability of reliable, base-load energy, there by 

endangering our regional, state and national economies. Commenters noted that Arkansas's coal 

plants were designed and built to provide baseload power, while the non-merchant NGCC units 

were designed to provide electricity during periods of higher demand and stated that changing 

the purpose and design of these units so drastically will have a substantial adverse impact on 

utility rates and the reliability of service. 

Commenters stated that for many existing NGCC units there is simply insufficient pipeline, gas 

availability, or transmission infrastructure to permit operating year-round at a 70 percent 

capacity factor. Commenters stated that these infrastructure limitations are exacerbated by the 

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 target level, which commenters regard 

as impossible. Commenters stated that the infrastructure to transport natural gas to increase the 

dispatch of NGCC units to 70% capacity factor is inadequate.

Commenters stated this building block dramatically oversimplifies the ability of one generation 

source to substitute for another. Commenters stated that relying on natural gas for high-capacity 

factor, baseload operations creates significant dispatch, reliability, and transmission concerns for 

operators. Commenters stated that, while natural 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 supply and price issues. Commenters stated that both the Federal Energy Regulatory 
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Commission (FERC) and the North American Electric Reliability Corporation (NERC) have 

expressed concern about the reliability implications of increased natural gas use. 

Commenters 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 redesign. Commenters agreed 

with NERC concerns that continued assessment of the reliability implications of the proposed 

Clean Power Plan need to occur, because the over dependence on one fuel type can expose 

customers to the potential of detrimental price volatility. 

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 (Nov. 2014).]

First, NGCC units have traditionally been used for load following purposes, and while some are 

capable of operating at a high capacity factor, they are generally less well-suited to serve as 

baseload resources than coal generation. Second, the Proposed 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 "polar 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 

manage 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. There 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. 

Commenters 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. Commenters referenced 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 units 

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 needed 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-congestion regions, increasing the risk for potential blackouts. 

Commenters stated the EPA over-estimated the amount of NGCC capacity available for redispatch by failing to consider limitations like operational constraints, reliability, infrastructure, 

and statutory and regulatory barriers that may impede re-dispatch. Commenters stated the EPA's 
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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 capability which can 

lead to interruptions in service. 

Commenters 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. Commenters stated that 

supplying NGCCs with adequate gas year round will cause some NGCCs to run on liquid fuels 

or shut down, reducing capacity factors. Commenters stated coal has always been the reliable 

fuel, as coal can be safely and conveniently stored on the plant side removing risks of failures in 

the delivery systems such have been experienced by natural gas. Commenters noted that unlike 

coal and fuel oil, natural gas typically cannot be stored on site at an EGU and as a result, natural 

gas is limited to real-time delivery through a network of pipelines and bulk gas storage. 

Commenters 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.

Commenters stated that demand for natural gas will grow and the ability to supply the gas may 

cause interruptions in service. Commenters added that demand for natural gas is expected to 

grow in other sectors (e.g., transportation, exports, and manufacturing), further affecting its 

availability for EGUs. Commenters 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. Commenters stated that a continuous supply is critical to 

support electric 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 transportation service in 

the power sector. 

Commenters raised concerns about increased dependence on natural gas for generation, 

especially during extreme winter events. 

Commenters 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. Commenters

noted that according to PJM, "Among the challenges for PJM and its members in maintaining 

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

Commenters noted that in Chapter 3 of its Polar Vortex Review, September 2014, NERC states: 

"Increased reliance on natural gas during the polar vortex exposed the industry to various 

challenges with fuel supply and delivery. This increased reliance, compounded by generation 

outages during the extreme conditions, increased the risks to the reliable operation of the 

BPS." Commenters noted last winter's polar vortex weather event in the PJM interchange when 

over 9,000 MW during a peak demand day of natural gas fired units went into a forced outage 

due to natural gas fuel curtailment. Commenters stated there was simply not enough natural gas 
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transportation capacity available to satisfy the home heating and power generation needs of the 

area. Commenters stated that on January 7, 2014, when temperatures fell to below zero, near a 

quarter of the PJM operators faltered due to low temperatures, with natural gas generators being 

47% off line at one time. Commenters stated that almost 90% of the planned 7,100 MW of AEP 

coal unit retirements were called to operate during that time. Commenters stated that as observed 

during the 2014 polar vortex, the relationship between gas-fired generation availability and low 

temperatures challenges the industry's ability to manage extreme weather conditions -

particularly when conditions affect a wide area and less support is available from the 

interconnection. Commenters stated that extreme weather conditions have the potential to strain 

BPS reliability and expose risks related to natural-gas-fired generation availability. Commenters

asserted that with greater reliance on natural-gas-fired generation, the resiliency and fuel 

diversification that is currently built into the system may be degraded, which NERC has 

highlighted in recent gas-electric interdependency assessments. 

Commenters stated 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. Commenters gave the example that during the extreme cold 

temperatures 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, commenters noted that 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 effectively forced out. 

Commenters expressed concern regarding the reliability of gas supplies to EGUs and households 

for home heating purposes. Commenters stated that implementation of the CPP could raise 

reliability issues associated with availability and distribution. Commenters 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. Commenters stated Indiana is currently evaluating the 

infrastructure to determine the effect this rule will have on grid reliability. Commenters stated 

that a shortage of fuel capacity during cold Indiana winters could pose serious consequences for 

residential 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.

Commenters 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 originally 

designed for such duty. Commenters stated that NGCC units are better suited to follow load and 

that cycling coal-fired EGUs reduces heat rate efficiencies, causing their CO2 emission rates 

(lbs/MWh) to deteriorate, and offsetting the Building Block 1 assumptions. Commenters 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 - for 
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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. Commenters stated that operational and reliability issues arise as lost dynamic 

response capabilities to match intermittent load exist when CCNG fast ramp optionality is 

eliminated. Commenters 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 

requiring the addition of more intermediate or peaking capacity. Commenters 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, makes the power system more 

susceptible to fluctuations in price and availability of that one fuel source.

Commenters stated that coal-fired unit generation must remain an integral part of Indiana's 

baseload power generation to maintain current system reliability. Commenters stated that, under 

the Proposed Rule, coal-fired units historically used for baseload power generation would 

effectively need to transition into load-following units. Commenters noted that, at NIPSCO, 

current average coal-fired unit ramp rates are much slower than the NGCC ramp rate. 

Commenters stated that relying on coal-fired units to supply load-following generation could 

decrease electric system reliability because these units are not designed to respond to rapid 

changes in demand. Commenters stated that coal-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. Commenters stated that more frequent forced outages pose 

increased reliability risk.

Commenters stated that the forced re-dispatching of natural gas generation and the addition of 

large amounts of renewable energy resources will impact the stability and reliability of 

transmission grids in varying degrees. Commenters 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. Commenters indicated that to shift generation from that plant to a natural gas-fired plant 

located elsewhere increases the risk of service disruptions. Commenters stated that the EPA 

recognized such risks in its enforcement memorandum addressing when it would provide utilities 

additional time to comply with the MATS rule. 

Commenters noted that many of the units retiring by 2020 are smaller coal units which follow 

load well and also noted that increasing renewable capacity under Building Block 3 calls for 

more load following due to the inherent intermittency of renewable energy technologies. 

Commenters stated that increasing the capacity factors of NGCCs and operating them 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. 

Commenters 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 NGCC 
11

fleet's average availability, but such an analysis says nothing of the reliability of units operating 

at a 70 percent or greater capacity factor for prolonged periods. Commenters 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. Commenters stated that a 70 percent capacity 

factor would change the purpose and design of the nation's NGCC fleet at-large, and the EPA 

must consider whether fleets by state or NERC reliability zones can operate reliably at such a 

capacity factor. Commenters referred to several reports concerning reliability. Commenters

asserted that the EPA should defer to the expertise and jurisdiction of System Operators, NERC, 

and balancing authorities in ensuring resource adequacy and grid stability.

Commenters stated the EPA has not adequately considered reliability in the development of state 

goals under Building Block 2. As an example, commenters 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 improper assumption will be very significant and serious. Commenters

contended that the EPA ignores several factors that would limit the ability of existing NGCC 

units to increase utilization to an average annual capacity factor of 70% and that would prevent 

that increased NGCC generation from replacing displaced coal and O/G generation. Commenters

stated that the EPA does not even acknowledge, let alone adequately address, the constraints 

preventing existing EGUs from operating at a 70 percent or higher capacity factor. Commenters

added that the EPA completely ignores potential technical or permit limits on NGCC unit 

operation and dismisses infrastructure concerns. Commenters 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, commenters characterized 

the Agency's reliance on "averaging flexibility" as "mere speculation or conjecture".

Commenters stated the EPA's analysis of the existing NGCC capacity "available" for re-dispatch 

fails to consider reserve margin requirements. Commenters stated reserve margin is the amount 

of generation capacity an entity must maintain in excess of its peak load-serving obligation. 

Commenters 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. Commenters 

said economic dispatch is based on the principle of providing the least cost option from available 

fleet resources to deliver the required power to the grid. Commenters added that the diverse 

energy portfolio that Georgia utilities have cultivated lessens 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 Issues
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Commenters expressed concern that the EPA may not have adequately addressed regional issues 

that could affect grid reliability. Commenters 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, integration 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. Commenters gave the 

example that while New England has concerns related to the lack of pipeline infrastructure and 

the ability of generators to contract firm natural gas delivery services, the desert Southwest has 

firm pipeline contracts but lacks natural gas storage and has concerns related to the flexibility 

needed on the gas side to address challenges associated with the increased deployment of 

variable resources. Commenters 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 gaselectric dependency studies and analyses, and include ISO/RTOs, electricity market participants, 

industrial consumers, national and regional regulatory bodies, and other government officials. 

Commenters added that the extent of these concerns varies from region to region; however, 

concerns are most acute in areas where power generators rely on interruptible pipeline 

transportation as the natural gas use for generation rapidly grows. 

Commenters stated 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 to support 

generation during the winter heating season, due to geography, fuel mix, and market structure. 

This is already an issue in New England, and may be an emerging issue in other regions as more 

gas is utilized for generation;" similarly, Commissioner Moeller has voiced his concern about 

"whether there will be sufficient pipeline capacity to support this increase in natural gas 

generation." Commenters noted that during a September 18, 2014 public meeting convened by 

Commissioner Moeller, electric generation 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."

Commenters 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 reliability 

issues associated with the increased use of natural gas for electric generation in their respective 

regions. Commenters 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. Commenters stated that in addition to FERC, the RTO/ISOs also are discussing these 

issues through their stakeholder processes and are conducting regional studies to determine what 

must be done to maintain reliability going forward, and that NERC has similarly noted that 

"higher dependence on natural gas can expose additional reliability risks, including pipeline 

transportation constraints that could result as more gas-fired generation is built" (Initial 

Reliability Review at 10). Commenters asserted that if the organizations charged with 

maintaining reliability and ensuring the functioning of electricity systems and markets are 
13

concerned about natural gas infrastructure and gas-electric coordination, EPA cannot ignore 

these issues in its BSER analysis. Commenters stated that chief among these issues are the 

sufficiency of the current natural gas pipeline infrastructure, 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 the closure of coal plants. 

Commenters expressed concern that, in projecting a non-economic dispatch of natural gas EGUs 

to become baseload generation, EPA's models have 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. Commenters stated that coal plants will 

close not only because they are not dispatched but also because their economics were based on 

baseload, high capacity factor operation; 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. Commenters stated Building Block 2 is impractical because it 

ignores the need to keep coal resources online for reliability support. Commenters stated 

PowerSouth must keep a set amount of spinning reserves available at all times under NERC 

requirements, and to do this it typically keeps at least one of the Lowman units online at all 

times. Commenters stated that, in order to prevent rolling blackouts or brownouts, PowerSouth 

must be able to dispatch the Lowman coal-fired power plant in order to maintain stability and

reliability under extreme, but foreseeable, loading conditions. Commenters stated that this extra 

capacity supplied by the Lowman unit (and required by NERC) may prevent the NGCCs from 

operating at a 70 percent capacity factor. Commenters noted the power demands during the 

severe winter season earlier this year and stated that system failure was avoided only through the 

sustained peak generation of several coal-fired power plants. Commenters suggested that, instead 

of substituting a method of power generation that is unproven at capacities needed to fulfill grid 

demands, the EPA should recognize the already-proven reliability of coal-fired EGUs as the 

preferred method of power generation. 

Commenters stated that given the system requirements that must be met in order to maintain 

reliability, even the seemingly simple decision to close a single fossil base load unit and replace 

it with a renewable generator requires 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 infrastructure 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 requires 

consideration of similar issues. Commenters 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 interconnection study and 

analysis process, whether the change is to the capacity of an existing generator or a new 

generator is proposed. Commenters described the required studies as follows: "The purpose of 

these studies is to assess the impact of a new generating 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 in 
14

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 points on the transmission system. The 

results of this study determine whether transmission upgrades or expansions are needed to 

accommodate the increased generation." Commenters noted that MISO's Generator 

Interconnection Procedures describe these required studies in more detail. 

Commenters stated the EPA did not consider market challenges associated with additional 

integration of the natural gas and electric markets. Commenters stated that, as reliance on natural 

gas to generate electricity has increased, the NERC has undertaken a series of studies to examine 

potential impacts of this increased reliance. Commenters 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. Commenters stated NERC noted that increased reliance on natural gas for electricity 

generation merits increased coordination to address some of the issues associated with this 

"planning gap." Commenters stated that when the EPA assumed that natural gas fired power 

plants could dispatch at 70 percent capacity 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. 

Commenters stated the Proposed Rule does not allow sufficient time to replace generation 

capacity that is expected to be retired. Commenters anticipated that the Proposed Rule would 

require the retirement of approximately 11 gigawatts of generation capacity in or around 2020. 

Commenters stated that, to avoid reliability and resource adequacy issues, this generation would 

need to be replaced in a timely manner. Commenters asserted that it is essential that the Agency 

assess whether the natural gas industry can support the level of increased NGCC utilization 

contemplated by the proposed guidelines both prior to and during the interim compliance period. 

Commenters indicated that the increased demand for gas pipelines can be addressed with 

sufficient lead time (i.e., more than three years), which is needed to plan, collect contracts, 

permit, procure, and build new pipeline. 

Commenters stated that the EPA failed to take into account other infrastructure issues in 

developing Building Block 2, noting that the SPP's analysis of the Proposed Guidelines indicated 

that unless the required generation and 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. Commenters stated under the Proposed 

Guidelines SPP's anticipated reserve margin would be 4.7 percent, representing a reserve-margin 

deficit of almost 4,600 MW in 2020 and an additional deficiency of 10,000 MW by 2024

Commenters indicated that given the 8 to 10 year time frame needed to design, permit and 
15

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. Commenters stated that a Bloomberg 

Government report illustrated the severe transmission bottlenecks facing New York. 

Commenters 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. Commenters indicated that 

the EPA's Building Block 2 methodology assumes, not only in New York but in other parts of 

the country, that ramped-up utilization of NGCC 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. Commenters asserted that the EPA did not consider these possible 

transmission constraints. 

Commenters stated Southwest Power Pool (SPP) studies have shown that the EPA's schedule of 

proposed unit retirements will have severe impacts on system reliability. Commenters stated that, 

in a November 2014 "Analysis of EPA's Proposal to 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 reductions 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 resource adequacy) in a 

two-year window will be difficult if not impossible. MISO's experience is that new gas plant 

construction typically requires three to six years. If new transmission and gas pipeline additions 

are needed to accommodate the capacity expansion, 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 finalized until the 2018-19 timeframe, there will be little time for decisions and 

implementation for infrastructure changes before 2020. 

Commenters 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. Commenters stated 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. Commenters 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. Commenters stated the CPP's 

interim goals do not allow the time required to permit and construct the necessary infrastructure 

for this shift. Commenters 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 existing 

natural gas pipelines. Commenters 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 comes 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 implement the CPP.

Commenters stated the changes in the utilization of the various generating plants driven by this 

proposal could have a significant impact on transmission reliability due to potential large 

changes in power flows across the system and retirement of generation that contributes to 

transmission system voltage and frequency performance. Commenters stated that the change in 

generation will almost certainly require development of new transmission to ensure operational 

reliability, but scheduling outages 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. Commenters asserted that to understand the full reliability, economic, 

and financial impacts of the proposed rule, detailed transmission reliability evaluations should be 

conducted. Commenters 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 financial implications of stranded transmission investments that become 

underutilized. Commenters encouraged the EPA to conduct detailed transmission reliability 

evaluations to understand the full reliability, economic, and financial impacts of the proposed 

rule.

Commenters 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. Commenters 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.

Commenters expressed concerned that 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. Commenters 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 NGCC facilities 

would displace all or most of the baseload coal-fired facilities. Consequently, commenters

believed 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. Commenters stated that the EPA's 

NODA appears to acknowledge these are significant and material issues, but no changes to the 

Proposed Rule were presented. Commenters indicated that while the EPA has assumed future 

wholesale level transactions between reliability regions, it has not provided the commenters 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, commenters stated they do not believe that 

electric reliability will be maintained if the Proposed Rule is implemented.
17

Comment 5: Commenters 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 

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 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 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 valuable fuel diversity to 

the state as a whole. Commenters 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 generation facility serving this highly constrained area. Sufficient generation 

must be immediately available within New York City to ensure continued electric service to 

customers located there. The first local reliability rule - Minimum Oil Burn - supported 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 

supply 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 facility 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 rules 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 local reliability rules described above and would undermine reliability in New 
18

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 gas 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 scarcity 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 generators. 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 ensure 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 expressed 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 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, 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

Commenters 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 significant GHG emitter, and 

given the uncertain future of natural gas availability and price volatility. Commenters stated there 

is not enough existing NGCC in this country, and in Indiana particularly, to make up for the 

forced reductions in coal generation. Commenters urged the EPA to reconsider the proposed 

rules which removes an abundant, and widely utilized nature resource from the nation's energy 
19

mix in such a dramatic and expeditious fashion, thereby hindering the reemergence of 

manufacturing in the nation's heartland and moving carbon emissions to global competitors with 

less pollution controls.

Fuel Diversity

Commenters stated that a balanced approach to fuel diversity is necessary to maintain reliability 

and affordability. Commenters stated that their 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. Commenters

noted that, once the operation 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.

Commenters expressed concern that the proposed rule would remove coal EGU's from the 

electrical generation portfolio in Nevada and relies totally on NGCC for base load power. 

Commenters stated this is contrary to PUC goals, which seek portfolio diversity in order to 

maintain relative price stability in electrical markets and mitigate the potential for fuel supply 

disruptions. Commenters noted that coal units have the ability to stockpile fuel on site, whereas 

natural gas units receive their fuel through pipelines and are therefore vulnerable to pipeline 

disruptions. Commenters 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 natural 

gas and because suppliers cut off interruptible load to serve other load under much higher spot 

prices. Commenters stated 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.

Commenters stated that NERC has determined that the CPP will cause a generation shortage. 

Commenters stated that natural gas units are best suited to follow load, rather than serve as base 

load units. Commenters stated that employing diverse fuel sources (coal-fired in addition to 

NGCC and renewables, when available) ensures a secure and reliable energy supply. 

Commenters 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. Commenters noted 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 procedure gas; and (4) fuel oil gelling. Commenters 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 times; and (5) frozen instrumentation.

Reliability

Commenters 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 generation 
20

serve different functions, with coal units required to ensure grid stability. Commenters 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.

Commenters referred to the EPA's IPM run results and stated the Proposed Rule would 

effectively eliminate coal-fired generation from PowerSouth's generation portfolio. Commenters

stated this has long-term implications, including impacts to PowerSouth's ability to provide 

reliable and affordable service to its members. Commenters stated the EPA cannot systematically 

phase out coal-fired EGUs. Commenters explained that, if external factors affect natural gas 

delivery, PowerSouth can rely on the coal resources in its fleet to meet demand. Commenters

stated the ability to choose from a suite of fuel options during resource planning retains fleet 

flexibility and reliability, and also ensures that economic and efficient electricity is provided to 

our members. Commenters stated the additional 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. Commenters stated the EPA should 

be promoting, not destroying, projects that create an abundance of reliable and affordable electric 

generating capacity for our nation's seniors. 

Commenters stated the shift to NGCC will eliminate stability in the energy market because gasfired technology is not as mature and reliable as coal-fired generation. Commenters noted that, 

should a coal-fired unit experience a forced outage, generally speaking, it will be a 3 to 5 day 

outage repaired by a local veteran work force. Commenters stated that, if a natural gas-fired 

combustion turbine unit experiences a forced outage, it is likely a 3 to 5 month outage with many 

unexpected expenses and without the availability of a local veteran workforce. Commenters

stated that, if the utility industry is expected to rely upon gas-fired combustion turbine 

technology, the industry will have to install twice as many units as anticipated by EPA and spare 

units will be necessary to ensure that sufficient energy can be generated at all times, particularly 

during prolonged maintenance outages. 

Commenters 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. Commenters 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. Commenters 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 raise red flags, those 

warnings should be carefully considered.

Commenters cited a NERC report and stated that extreme weather events highlight the need for 

adequate reserve margin and fuel diversity. Commenters stated that many regions relied on coalfired 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 Concerns
21

Commenters expressed concern that 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 

close as the economic viability of the operation would erode to unsustainable levels. 

Commenters stated that the complete eradication of coal-fired units from New York's fleet 

presents concerns related to fuel diversity and reliability. Commenters 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.

Commenters noted that in 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. Commenters 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 only 

announced the retirement of some of their existing coal capacity and have plans to keep their 

remaining coal fleet operating into the future. Commenters 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. Commenters 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 Option 

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

generation to its NGCC units without 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. Commenters stated that even 

more coal capacity would be needed if EPA had properly applied summer capacity (as opposed 

to nameplate capacity) for NGCC. 

Commenters 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 fired generating 

facility, Plant Morrow, will be forced into early retirement. Commenters 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, Arkansas. Commenters referred to Attachment A to 

their comments which express some of these concerns.

Stranded Investments
22

Commenters 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. Commenters stated that the 

draft rule summarily discards billions of dollars in investment Georgians have made in state-ofthe-art emissions controls 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 response to 

this rule, thereby stranding the investment in those generating units, including billions of dollars' 

worth of environmental controls. 

Commenters stated that implementation of the proposed re-dispatching would require premature 

closure of Mississippi's remaining coal fleet, even though many of these units have taken recent 

steps to comply with the MATS rule by spending millions of dollars in control retrofits. 

Commenters stated that full implementation of Building Block 2 is not an option for these units 

because it would cause these upgrades to become stranded assets to the rate payers of 

Mississippi. Commenters stated that, under the proposed application of Building Block 2, 

Mississippi would completely lose its fuel diversity with a projected zero coal and oil/gas steam 

power generation by 2020, which is an unacceptable result. Commenters stated that removing 

fuel diversity jeopardizes power reliability and removes the ability to control power costs for 

consumers. Commenters requested that the impact of Building Block 2 on Mississippi's proposed 

goal align with the stated intent of the proposed rule, which is to reduce carbon emissions "while 

maintaining an affordable, reliable, and diverse energy mix". Commenters suggested the EPA 

consider evaluating the state's fuel usage profile for an acceptable level of natural gas usage prior 

to determining whether re-dispatching is even necessary. Commenters 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. Commenters stated that re-dispatching to NGCC capacity for the 

Mississippi fleet does not consider the intended utilization of the units. Commenters stated that 

many of Mississippi's units were not designed or included in the power system to provide 

extended power generation. Commenters 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. 

Commenters 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. 

Commenters stated these measures contravene Section 111(d) by forcing displacement of coalfired EGUs with significant remaining useful lives. Commenters stated section 111(d) requires 

EPA to take into account the remaining useful lives of the sources it regulates. Commenters

stated that, despite this provision, EPA did not assess the remaining useful lives of OG&E's and 

others' coal-fired EGUs that are poised for closure under the Proposed Rule. Commenters stated 

shutting down OG&E's coal-fired EGUs will cause untold damage to local communities, 

including job losses at OG&E facilities and elsewhere in the supply chain, stranded investments, 

and reductions in revenue. Commenters stated the abruptness of the transition risks destabilizing 

energy production and threatens reliability. Commenters stated this scenario can and should be 

avoided, particularly since OG&E realizes the value of a diverse portfolio of electricity 
23

generation methods and has taken a leadership role across Oklahoma by pioneering utilization of 

NGCCs. Commenters 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.

Commenters stated the EPA has not considered that re-dispatching may leave some generating 

entities with stranded investments because, as EPA's own modeling shows, many coal units will 

shut down due to re-dispatch. Commenters stated 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 capacity during peak load periods. 

Commenters supported the modifications proposed by the Arizona Utilities Group (AUG). 

Commenters stated the AUG proposal requests EPA consider the remaining useful life and asset 

value of Arizona's coal plants, together with lowering CO2 emissions to achieve meaningful 

long-term reductions. Commenters 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. Finally, AUG's proposal would also lower the cost burden to be borne by 

consumers.

Commenters 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. Commenters stated the redispatch of Deer Creek Station to a level of 70% capacity would in tum result in a dispatch of 

South Dakota's lone coal-fired EGU to a level of 23%, a wholly unreasonable and uneconomic 

level for a baseload coal unit. 

Commenters expressed concern that, in projecting a non-economic dispatch of natural gas EGUs 

to become baseload generation, the EPA's models 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. Commenters stated coal plants will 

close not only because they are not dispatched but also because their economics were based on 

baseload, high capacity factor operation and 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. 

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; operating 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. The 
24

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” 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:

Must-Run Requirements

Commenters stated that re-dispatch of NGCC resources may also interfere with NERC 

compliance requirements regarding capacity reserves, spinning reserves and similar 

requirements. Commenters stated that the EPA cannot presume that certain coal units can be 

retired or curtailed in favor of increased natural gas generation because coal generation and 

natural gas generation serve different functions. Commenters stated that coal generators serve an 

important function in providing local reliability support, including black start capabilities (the 

ability to restart without any electrical input), voltage stability, and other ancillary services. 

Commenters stated that, as a result, certain coal facilities may be "reliability must run" units 

which cannot be retired without imperiling local grid reliability. Commenters cited a Western 

Electricity Coordinating Council study (2022 Resource Options, July 25, 2013, p. 51): "The path 

rating for Path 8 [the Montana to Pacific Northwest corridor] is currently highly dependent on 

remedial action schemes that are directly linked with the coal-fired and hydro generation in 

Montana. There are inertial concerns in the area. The local balancing authorities have advised 

caution when running studies that 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 Services

Commenters 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. 

Commenters stated that, while unit upgrades and re-powering with natural 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.

Commenters 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. Commenters

stated it is arbitrary and unreasonable for EPA to ignore these factors when making assumptions 

about the displacement of coal generation. Commenters 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). Commenters stated this approach ignores the 

non-generating services that coal-fired EGUs provide to the electricity generation and 
25

transmission sectors. Commenters stated that coal-fired EGUs may be located strategically to 

provide voltage support and other grid reliability benefits and that existing and under 

construction NGCC facilities at other locations cannot replace these functions. Commenters

stated that certain coal-fired EGUs 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 regional transmission organization (RTOs). Commenters stated these coalfired EGUs cannot be retired and replaced by existing or under construction NGCCs.

Commenters 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. Commenters stated this is particularly true in States where EPA's BSER 

analysis projects that coal-fired generation will cease entirely. 

Commenters stated that it is important to note that all generating resources do not provide the 

same services to the electric grid and that all electrons may not be able to serve all customers due 

to electric transmission or other constraints - different sources are needed to ensure that electrons 

actually reach end-users. Commenters indicated that while all generating units produce 

electricity, some types of units only supply energy, others supply critical grid services 

(balancing, back-up and ancillary services like 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. Commenters added that renewable generation units can 

provide electrons, but are limited in their ability to provide grid or peak period capacity services. 

Commenters asserted that retirement of base load coal-based units diminishes the pool 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.

Commenters 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. Commenters noted that reactive power, for example, 

does not "travel" over distances and is, therefore, a "local" requirement that can be provided only 

by a few resources when needed. Commenters indicated that FERC recognizes the following as 

ancillary services: scheduling, system control and dispatch; reactive supply and 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). According to the commenters, under FPA 

sections 205 and 206 all public utilities that own, control or operate facilities used for 

transmitting electric energy in interstate commerce are required to take transmission service, 

including these ancillary services, for wholesale sales and purchases of electric energy under 

open access tariffs. (Commenters 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 

generating 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 first 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.) Commenters stated that ancillary services, in addition to capacity and energy, are necessary 
26

to support the transmission 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 essential that FERC 

also requires that transmission service providers - absent third-party service - provide them to 

ensure the reliable delivery of electricity.

Commenters added that natural gas units are vulnerable to pipeline disruptions while coal units 

have the ability to stockpile fuel on site. Commenters 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. Commenters 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 frozen pipelines to deliver natural gas and because suppliers cut off 

interruptible load to serve other load under much higher spot prices. 

Commenters also expressed concern that the EPA's calculation of each state's best system fails to 

account for fuel-pricing stability. Commenters 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

Commenters 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. According to the commenters, 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. Commenters 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). Commenters noted that utilities minimize cost to consumers while 

still meeting ramping and regulation requirements, and that what type of unit meets ancillary 

service demands depends on factors such as system demand, a unit's cost, a unit's ability to 

respond to ramping and regulation needs, and the system's capacity mix. Commenters added that 

depending on the time of the year, different unit mixes may be committed to meet expected 

demand shapes 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. 

Commenters provided a figure with examples of seasonal load shapes over a 24-hour period for 

the winter, spring/fall, and summer seasons. 

Commenters 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 

Southern Company footprint, and noted that a winter month's ramping and regulation 

requirements can be quite different than a summer month's requirements. Commenters 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, Power 
27

Augmentation) with minimum up and down times of approximately 8 hours. Commenters 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 given time period, the ability of NGCCs to reduce output 

further (turndown) is valuable. Commenters added that because NGCCs serve several different 

roles over the course of a year, they may maintain different capacity factors across the seasons. 

Commenters indicated that historically, NGCC's have run at higher capacity factors during the 

summer, but it is important that these units maintain operational flexibility throughout the year to 

assist in meeting load. Commenters provided figures illustrating NGCC quick cold startup 

capability compared to typical coal-fired EGUs; the contribution to total load by various power 

generation sources over the course of a 24-hour day in summer; the contribution to total load by 

various power generation sources over the course of a 24-hour day in winter; and the capacity 

factor for NGCC units in summer, transitional seasons, and winter. 

Commenters 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. Commenters

indicated that other units would need to perform these duties - impacting system reliability and 

generation costs. According to the commenters, the EPA modelers recognize the turndown 

constraints of other technologies (e.g., coal and 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 

strictly as peaking units, which would be inconsistent with their operating capabilities". 

Commenters 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 variable 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 order 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 the peak load segment of the LDC".

Commenters also stated that almost all of Southern Company's NGCC fleet (excluding IGCC 

and CHP units) is Automatic Generation Control (AGC) capable. Commenters indicated that 

maintaining AGC capability allows a unit to dynamically follow system demand in 10 minute 

time increments, which is necessary to serve regulation and frequency requirements. 

Commenters added that NERC also requires minimum amounts of regulation 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). Commenters asserted that NGCCs are an important part of fulfilling these NERC 

requirements 

Commenters stated that as unit pricing has changed over time, so have the types of units 

fulfilling system regulation needs. Commenters provided a figure showing a comparison between 

3 years of the types of units regulating the Southern Company system (i.e., the units on AGC), 

which illustrates the relative percentages of regulation performed by resource types. The 

commenters presented three pie charts, which show the changes in percent utilization of various 

sources for AGC over the period from 2008 to 2012. Commenters asserted that as 23 percent of 
28

Southern Company's 2012 AGC resources close or transition to gas, Building Block 2's dispatch 

requirement that further limits units available for regulation becomes more problematic. 

Commenters stated that as demonstrated in the figure, the units performing regulation 

requirements can change as fuel prices change. Commenters indicated that NGCCs are being 

called upon more often to perform regulation and as additional coal-fired EGUs switch fuel or 

retire, NGCCs will be asked to perform even more regulation. Commenters concluded that 

maintaining NGCCs' future flexibility is important to ensure regulation needs are met, and that 

operational limitations, such as EPA Building Block 2, will impede NGCCs from performing 

regulation.

Commenters stated the EPA fails to consider the role of NGCCs in an integrated electric system 

in asserting that states can set a standard based on achieving a fleet-wide capacity factor of 70 

percent. Commenters stated the NGCCs are frequently called upon to provide ancillary services 

because of their unique operational capabilities (e.g., high annual availability and quick ramping 

capability). Commenters explained that ancillary Services commonly 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 Response; Energy Imbalance; Operating Reserves; and Supplemental 

Reserves.8 Commenters 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. Commenters added that, 

even though an NGCC may frequently operate to meet ancillary services, this does not mean the 

unit is operating at a high capacity factor (e.g., 70 percent). 

Commenters stated that it is not uncommon for NGCCs to operate at lower output levels in order 

ensure that a unit is available to meet the system's ramping or regulation needs. Commenters

stated that, as system demand reaches a minimum level during a given time period, the ability of 

NGCCs to reduce output further (turndown) is valuable. Commenters stated that some NGCCs 

may cycle across the day while other NGCCs stay online through a single ramp up and ramp 

down cycle. Commenters stated that expecting NGCCs to generate at a 70 percent capacity 

factor despite system economics and the need for 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 provide critical regulation, ramping, and 

turndown needs for system reliability. Commenters 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. Commenters stated this reliability concern is exacerbated because 

emission reductions through the other building blocks are infeasible; therefore, NGCCs would 

likely be required to operate at an even higher capacity factor to compensate for the lack of 

reductions possible under the other building blocks. 

Commenters stated NGCCs often are utilized for ramping needs (scheduling, system control, and 

dispatch) and regulation (regulation and frequency response). Commenters stated that ramping 

requires units to move up or down as load varies throughout the day while regulation provides 

faster resources that respond to system demand changes minute to minute (or shorter duration). 

Commenters 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 at 
29

the same time making it harder to meet ancillary service requirements. Commenters stated that 

the CPP will effectively reduce a system's turndown (cycling) capability and increase the need 

for nimble ramping/regulation units by (1) adding more renewables, (2) removing coal units, and 

(3) hindering more nimble units' (NGCCs) ability to respond to the resulting system needs. 

Commenters stated these factors increase cost, reduce reliability, and complicate system 

planning needs. 

Safety-Valve

Commenters suggested the EPA should include "safety valves" to allow utilities to ramp up a 

coal facility, rather than increase natural gas generation, to address short-term conditions when 

dictated by reliability and safety. Commenters noted that in very cold winters, the price of 

natural gas spikes and, in addition, increased natural gas generation is dependent upon adequate 

pipeline capacity. Commenters stated that the reliability safety-valve would be similar to the oneyear compliance extension used to avoid retirement-related reliability impacts due to MATS. 

Commenters stated that there is no consensus as to what would trigger the safety-valve. 

Commenters stated the EPA should allow states to include a safety valve in their state plans to 

address situations where the increased dispatch of NGCC units could affect reliability.

Comment 8: Commenters expressed concern that, as the industry relies more on natural-gasfired capacity to meet electricity needs, it is important to examine potential risks associated with 

increased dependence on a single fuel type.

Response 8: The EPA disagrees 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 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, extreme events, 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:

Area-Specific

Commenters 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. Commenters stated these risks and the need to have flexibility and diversity are very 

important because natural gas cannot be stored and because hurricanes and other natural disasters 
30

or catastrophic events can cause a disruption in supply. Commenters stated the reliability of the 

entire state's electrical grid is in jeopardy if we become more dependent on natural gas as the 

primary fuel source. Commenters stated that price spikes in natural gas, like those that occurred 

in 2008, would have bigger impacts on customers' electric bills with less fuel diversity and a 

greater reliance on natural gas. Commenters stated the only way for Florida to achieve EPA's 

proposed reduction goals would be to use new zero-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 meet 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 reliability and integrity, 

adequate electricity at a reasonable cost, and the need for fuel diversity and supply reliability. 

Commenters stated that it is important for Florida to maintain a diversified generation fuel source 

mix when seeking to comply with relevant CO2 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 

capacity 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.

Commenters stated that the EPA's proposal threatens fuel diversity. Commenters stated that the 

EPA's estimates for building block 2 in Louisiana, if utilized for SIP purposes, would entirely 

reconfigure the state's economic dispatch from one that currently relies on a modest level of 

baseload coal generation, to one almost exclusively reliant upon natural gas generation. 

According to the commenters, the EPA's analysis 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. Commenters stated that this 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. Commenters quoted NERC as saying: 

"the power industry relies upon diversification of fuel sources as a mechanism to offset 

unforeseen events (e.g., abnormal weather, regional transfers, labor strikes, unplanned outages); 

ensure reliability; and minimize cost impacts. Fuel diversification is also a component of an "allhazards" approach to system planning, which inherently provides resilience to the BPS." 

Commenters 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 power 

industry will need to compensate for over 100 GW of retired coal-fired capacity. Commenters
31

stated that the EPA's proposal threatens to exacerbate this shift in the resource mix further 

threatening fuel diversity. Commenters 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 analysis, 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. Commenters 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 

units 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 considerable 

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) report 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. 

Commenters 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. 

Commenters stated that gas curtailment is a concern for electric generators who rely on natural 

gas, particularly in winter months when residential demand is high and supplies are jeopardized 

by freezing temperatures. Commenters stated that limitations on natural gas pipeline capacity in 

Texas occurred during the very cold weather in February 2011 and 2014, when a large amount of 

gas was being consumed for home heating. Commenters stated that, with increased reliance on 

gas for electric generation, there will be an increased risk of having to curtail NGCC generation. 

Commenters stated that relying 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. 

Commenters 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 residential and commercial customers. 
32

Extreme Events

Commenters 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). 

Commenters 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. Commenters

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. Commenters stated that natural gas units are best suited to 

follow load, rather than serve as baseload units and employing diverse fuel sources (coal-fired in 

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

Commenters stated that with this shift toward more natural gas consumption in the power sector,

the power industry will become increasingly vulnerable to natural gas supply and transportation 

risks. Commenters indicated that overdependence on a single fuel type increases the risk of 

common-mode or area-wide conditions and disruptions, especially during extreme weather 

events. Commenters referenced a September 2014 NERC report and stated that adverse winter 

weather, such as that experienced during January 2014, provided signs of natural gas supply and 

natural gas supply and deliverability risks. Commenters stated that this can be a local issue in 

areas where there is already a heavy concentration of natural gas generation. Commenters added 

that while there are several plants with dual-fuel capability, the capability to switch to a 

secondary fuel can be limited during certain operating conditions. Commenters 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. Commenters asserted that as reliance increases more on natural gas for 

both baseload and on-peak capacity, it is important to also examine potential risks associated 

with reduced diversity and increased dependence on a single fuel type. 

Commenters stated that generally, the power 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. Commenters added 

that fuel diversification is also a component of an "all-hazards" approach to system planning, 

which inherently provides resilience to the BPS. Commenters 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 

resources by 2020, largely anticipated to be natural-gas-fired NGCC and CTs. Commenters

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

Commenters stated natural gas units are best suited to follow load, rather than serve as baseload 

units. Commenters stated that employing diverse fuel sources (coal-fired in addition to NGCC 

and renewables, when available) ensures a secure and reliable energy supply. Commenters stated 

abnormally cold temperatures impact fuel delivery and the ability of the power grid to run 

reliably. Commenters stated reduced diversity in power supply restricts the power sector's ability 

to respond to these events. Commenters stated that, during the 2014 polar vortex the following 

fuel delivery complications were encountered: (1) 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. Commenters 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 

times; and (5) frozen instrumentation. Commenters stated 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 Holland Energy facility; as a result the plant ran only four days from 

1/1/2014 through 3/31/2014 and the facility had a capacity factor of only one percent based on 

MWh versus potential.

General

Commenters 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. 

Commenters stated that, without reliable natural gas, utilities have generally turned to coal which 

can be stored on site and carries much less risk on the supply side. Commenters stated a 

diversified electric strategy at any utility is needed to assure the availability of fuel to supply the 

electricity to meet customers' needs. Commenters 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). Commenters stated that, while the electric industry is spending 

major 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. Commenters stated that during the peak of 

the extreme cold temperatures and storms in January of this year, CWLP's natural gas supplier 

advised that it had no natural gas to supply us at any price, delivering its supply instead to its 

residential and commercial customers. Commenters 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 (less reliability).

Commenters 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. Commenters stated that, from a reliability 

perspective, it is essential that base load generation (coal and nuclear) remain a feasible and costeffective source of generation to meet existing and future energy needs. Commenters stated that 

over-reliance on any one dispatchable generation makes the electric system vulnerable to price 
34

spikes, distribution disruptions, and even intentional human acts such as vandalism or terrorism. 

Commenters stated it is unknown how operating at such a level will impact the long-term 

reliability and efficiency of such facilities. Commenters 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. 

Commenters 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. Commenters 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 

commenters, 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. Commenters

stated that it is concerning that EPA has failed to look at the impediments to greater use of 

natural gas for electric generation or consider the implications of over-reliance on natural gas for 

generation.

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

Response 9: The EPA disagrees with the interpretation of the 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 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. 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, 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. Commenters 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. Commenters stated this problem will become ever more 

challenging as demand from gas-fired generation increases in the future.

Commenters 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. Commenters indicated that the use 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 training 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. Commenters gave some examples of the changes that would be 

required, including closure of the North Valmy coal-fired plant which could result in concerns 

about voltage support in northern Nevada. Commenters 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. Commenters stated that at present, 

states have only begun to plan for the impacts of implementing the proposed regulation, and 

asserted that it is imperative that each state have sufficient time to implement its own compliance 

plan. 

Commenters asserted that it is not tenable for Nevada to meet the interim goal with Building 

Block 2 for the following reasons (which are addressed in greater detail elsewhere 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 accomplished within a three-year period, assuming 

that the EPA were to approve the state plan by 2017. 

• Replacing coal-fired EGUs with NGCC EGUs is not simple. The facilities would 

not likely be able to use the same footprint because new NGCC units must be 
36

constructed 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. 

Commenters 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. Commenters 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 natural gas and renewable energy generation. 

Commenters 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 retirements can be used in place of a re-dispatch strategy to achieve 

emission reductions.

Some commenters responded to points made by other commenters:

• Commenters agreed that reliability is a critical concern that must be addressed. 

Commenters 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 California Independent System Operator (CAISO), 

which will help bring more renewable resources into play for participants to 

utilize. Commenters added that the National Renewable Energy Labs (NREL) is 

conducting a long-range analysis, the Renewable Energy Futures Study of how to 

integrate high levels of renewable energy onto the grid, which is extensive and 

detailed. Commenters stated that Commenters 22732 should submit specific 

concerns to the NREL for analysis in this plan so that any potential issues can be 

addressed upfront, which would include addressing the voltage support concerns 

related to North Valmy. 

• Commenters indicated that with coal plants retiring westwide, major transmission 

lines will be freed up to serve other needs including wheeling renewable 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.

Commenters disagreed with the assertion that new NGCC EGUs will need to be built to redispatch from coal to natural gas, stating that the Western Interconnect is awash in excess natural 

gas capacity at present and it is growing. Commenters also refuted the contention that replacing a 

coal plant necessarily requires new gas to replace their "baseload" power, indicating that coal 

plants in Nevada in recent years, such as the Reid Gardner plant, have often been run as peaking 

units, starting up in the morning and shutting down at night. Commenters stated that this is 
37

inefficient and expensive 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: Commenters said that because of their locations and other constraints, the 

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 interpretation 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 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, infrastructure, and the “useful 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. 

Commenters 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, commenters said, units running even less that 10 percent below their operational 

norm on a continuing basis would be unable to generate enough revenue to service the 

outstanding debt on the unit. Commenters said running them less (which is what the EPA 

effectively requires when it suggests that cooperatives can build new, lower-emitting units or 

purchase electricity from lower-emitting sources in lieu of generating it from existing units) will 

lead to significant financial issues and a very high likelihood of creating stranded assets. 

Commenters noted that EPA's model presumes that Arizona's Tri-State Generation 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 commenters, the EPA modeling projects almost 

100% re-dispatch of coal resources in Arizona by 2030. Commenters explained that Tri-State 

built this 417 MW coal-fired unit in 2006, invested nearly $1 billion dollars in it and the 

expected useful remaining life of the plant extends until 2066. According to commenters, the 

Springerville plant is a state-of-the-art coal plant with air pollution controls including bag houses 

for particulate matter, scrubbers for sulfur dioxide, and selective catalytic reduction for nitrogen 
38

oxides. Commenters added that Tri-State will be installing additional controls in 2015 to reduce 

mercury emissions. 

Commenters described how the EPA modeling shows that Seminole Electric Cooperative coalfired generating facilities have been arbitrarily scheduled for retirement well before the end of 

their useful life. Commenters 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, commenters said that approximately 70% of the byproducts 

produced at the coal facility are recycled for use in products that consumers use every day, 

including wallboard and concrete. These continued investments have made Seminole's facility 

one of the cleanest coal-based power plants in the country, commenters said. Should the EPA's 

proposed CO2 rule be finalized, commenters stated, these costly investments will become 

stranded assets and Seminole's coal-fired power plant will be forced to close, leaving 300 hardworking, skilled employees without jobs. Additionally, commenters 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, commenters said, but 

could have sweeping unintended consequences for the fragile but recovering workforce and 

economy in Florida. Commenters said that numerous cooperatives will have units that face 

premature phase-out, creating stranded assets and consequently state regional economic 

disruptions.

Commenters 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, 

commenters said that during implementation it required all new electric generating facilities to 

be "coal capable." Commenters said that due to the capital cost differentials between facilities 

constructed to be "coal capable" and those designed solely for natural gas use, as well as the 

historically higher fuel cost of natural gas, the Fuel Use Act economically prohibited new EGUs 

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, commenters said, electric cooperative generation 

needs grew substantially and, as a consequence, about 60 percent of cooperative total baseload 

electric generation was constructed under Fuel Use Act and is coal based. 

Comment 11: Commenters expressed concerns that existing capacity agreements, transmission 

rights, complicated ownerships, and unique loads would interfere 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) 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 
39

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 comment:

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. 

Commenters stated that Big Stone is South Dakota's only coal-fired EGU, and there is only one 

NGCC plant, Deer Creek Station. Commenters stated 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. Commenters stated that the combinedcycle unit owner does has no obligation to provide energy to the owners and the customers of 

Big Stone Plant. Commenters also stated that Big Stone Plant operates within the MISO 

centralized market. Commenters stated that 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. Commenters stated that each 

Big Stone owner has a firm transmission right from Big Stone to serve their respective loads; 

likewise, the NGCC plant has a firm transmission right to serve its loads.

Commenters stated that Building Block 2 fails to account for the fact that facilities may have 

already committed 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 Proposal 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 proposed emissions standards under 

Building Block Two without impermissibly intruding upon the exclusive jurisdiction of FERC 

under the FPA. 

Commenters stated that Building Block 2 assumes 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. Commenters asserted that Building 

Block 2 fails to consider what percentage of electricity produced by NGCC units is currently 

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

Commenters stated that independent power producers (IPPs), which are contracted for specific 

amounts of generation, may not have the immediate flexibility to re-dispatch under the power 

purchase agreements (PPAs) between the buyer and the seller. Even in deregulated market-based 

systems such as ERCOT, commenters said, the operation of individual units and companies is 

still subject to the overall operational needs and constraints of the electrical grid. 

Commenters stated that PowerSouth's ability to meet a 70 percent capacity factor is constrained 

by its agreement to accept "must run" energy from SEPA hydro (for which it would not get 
40

credit in EPA's goal calculation). As a result of this, commenters stated PowerSouth reduces its 

NGCC's operation to fully utilize its "must take" hydro energy. Commenters stated this 

flexibility reduces system carbon emissions, but PowerSouth would be penalized for it if 

Building Block 2 were implemented in Alabama. 

Commenters noted that, depending on the market structure of the region, natural gas-fired 

generators may rely more heavily on firm contracts or interruptible contracts. Commenters stated 

that electric generation owners who have the 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. Commenters stated that, depending on the region, the utilization of the pipeline 

capacity, and the specific pipeline tariff, firm pipeline costs vary. Commenters provided a Figure 

5 (Firm Natural Gas Transmission Rates, Individual Pipeline Tariffs) which shows the average, 

minimum and maximum costs for firm natural gas fuel delivery in the respective regions based 

on existing pipeline tariff rates, assuming a 100 percent utilization factor of the pipeline. 

Commenters 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.

Commenters stated the EPA overstates the amount of existing NGCC capacity available for redispatch because the EPA needs to account for NGCC units that may be unavailable for redispatch because they are contractually committed to out-of-state service or availability. 

Commenters stated that plants with 10- to 15-year out-of-state power purchase agreements (PPA) 

would not be available for in-state re-dispatch. Commenters stated that, even where merchant 

units have not presently committed to out-of-state service or availability, such units have no 

obligation to serve in-state load. Commenters stated that, for these reasons, it is inappropriate to 

assume that capacity from merchant NGCC units will be available for re-dispatch. Commenters

stated that forcing PPAs to be dishonored would run afoul of the Contracts Clause and, where 

compliance would require PPA abandonment, credit markets would tighten causing economic 

impacts that EPA has not analyzed.

Commenters stated that NGCC ownership diversity may reduce the potential for re-dispatch. 

Commenters stated that virtually all of the 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. Commenters stated the availability of potential 

NGCC generation for re-dispatch, including transmission, is individual and specific to each 

Purchaser. Commenters stated the California Purchasers may determine that procuring 

underutilized NGCC in Utah may not serve their economic interest or may simply be 

unavailable. Commenters 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. Commenters stated the realization of 

NGCC re-dispatch as contemplated by building block 2 would be left to the EGUs in Utah 

exclusive of IPP. Commenters stated that, since IPP is a major source of generation in Utah, it 

may be difficult for the remaining EGUs to meet the re-dispatch goal. Commenters stated the 

EPA should allow adjustments for the effects of NGCC re-dispatch from sources outside of the 
41

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

the rate calculation. 

Commenters stated that Idaho must be allowed to re-dispatch out of state coal generation to the 

under-utilized Idaho NGCC plants and the EPA must reformulate Idaho's goal with a 70% 

capacity factor at the two affected units. Commenters stated that Idaho 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 current system for dispatching units. The 111(d) final rule requires that states 

develop plans that establish emission standards for affected EGUs, and, in response to additional 

analysis and many comments, we have modified the 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 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, 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

Commenters stated Block 2 ignores the manner in which the utility industry, Regional 

Transmission Organizations (RTOs) and Independent System Operators (ISOs) make dispatch 

decisions. Commenters noted that, in many parts of the country, dispatch decisions are not under 

the authority of state agencies or utilities but are made by RTOs or ISOs. Commenters stated 

that, in the utility industry, the dispatch decisions are made based on two factors: reliability and 

cost. Commenters indicated that coal units required for reliability should not be assumed to be 

able to back down when NGCCs increase their capacity factor. Commenters noted that many 

coal units provide voltage support to enable the transmission system to deliver electricity; other 

coal units must operate to enable 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

Commenters 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 reliability. Commenters 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 effects of operating generating units before the economic benefits of operating 

those same units). Commenters asserted that this is contrary to the purpose for which RTOs were 

formed and also violates those regional entities' obligations under the Federal Power Act to 

dispatch generation economically.

Commenters 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-effective electricity. Commenters stated Building Block 2 would drive 

dispatch decisions towards utilizing 70% of the NGCC capacity, seemingly at the expense of 

lower cost generation. Commenters stated that shifting our generation preferences from low cost 

method to the 4th most preferred method in terms of cost will do nothing other than significantly 

raise electricity rates. 

Commenters stated the concept of operating all NGCC units at a 70% capacity factor is 

unrealistic for Texas due to the design of the ERCOT market. Commenters stated that any 

dispatch method that preferentially selects resources based on emissions rates, without regard for 

underlying fuel cost structure, will lead to market uncertainty and severe price increases. 

Commenters stated that, when the grid is strained, ERCOT may need to require coal units to run 

outside of emissions constraints for reliability. Commenters stated this Building Block calls for 

an approximate 52% reduction in coal unit operation in Texas while CPS Energy's average 

NGCC capacity factor is around 35% for 2009-2013, thanks to CPS Energy's zero-emissions 

base load nuclear resource. 

Dispatch Decisions -- Managed by Independent Agencies

Commenters stated that the Ameren Corporation does not own an existing NGCC generating 

unit. Commenters 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. Commenters also noted that in RTO markets, the FERC and not the states regulate 

the RTOs; therefore, the proposed rule imposes a requirement on states that they do not have the 

authority to implement.

Commenters stated that Building Block 2 is incompatible with the current system for electricity 

dispatch, which is managed by independent agencies, not state governments and which is based 

on cost, not a regulatory preference for natural gas. Commenters stated that dispatch decisions 

are made by regional transmission operators (RTOs) and independent system operators (ISOs) 

like MISO, ERCOT, and PJM, which operate within the structure and governance of FERC. 

Commenters stated that many of these organizations serve multiple states, and their jurisdictions 

do not always follow state borders. Commenters stated that, since state governments have limited 

authority to dictate these organizations dispatch decisions, it will be impossible for a state to 
43

fully implement Building Block 2 simply because an individual state does not have the authority 

to fully control the dispatch decisions.

Commenters stated the EPA lacks the legal authority to order NGCC plants to operate at a 

particular capacity. Commenters stated that only a Regional Transmission Operator or 

Independent System Operator under the jurisdiction of the Federal Energy Regulatory 

Commission (FERC) jurisdiction has such authority. 

Commenters stated that, while the EPA has suggested that the Northern Tier Transmission Group 

(NTTG) could manage the regional re-dispatch of 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 methodology 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.

Commenters stated that altering market design to achieve a set capacity factor in New York,

which has deregulated the electricity market, will be almost impossible. Commenters stated the 

EPA should recognize the limitation and significant benefits of deregulated markets and 

encourage deregulated markets that have delivered significant reduction in GHG and not place 

those markets in peril.

Commenters stated that, while the EPA suggests that a state could effectuate re-dispatch of the 

generation within a state by requiring units to 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. Commenters stated that, because compliance obligations and costs differ 

greatly among states, it would be impossible for a unit in one state to determine the bid price 

necessary to ensure that it would or would not be dispatched before generating units in other 

states within the SPP region. Commenters stated this is further complicated in states that fall 

within multiple regions, such as New Mexico and Texas. Commenters 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) reliability and (2) least-cost.

Commenters 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 cost generating sources are dispatched first. Commenters 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 are 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 limited 
44

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.

Commenters stated 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). 

Commenters indicated that an RTO's control over the dispatch of generation will affect a state's 

ability to adopt measures that achieve EPA's proposed section 111(d) requirements and a utility's 

ability to control emissions from its overall fleet and comply with state plan requirements. 

Commenters noted that under Building Block 2 the 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 

factor for that state. Commenters stated that RTOs currently make dispatch decisions based upon 

economics - i.e., the lowest cost generating sources are dispatched first. Commenters 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 market (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). 

Commenters stated the EPA presumes that utilities will be able to rely on the interconnected 

nature of the electricity sector to accomplish Building Block 2 (79 FR 34837). Commenters

stated that PowerSouth is not part of an RTO or ISO, but instead owns and operates its own 

Energy Control System and must comply with the FERC and NERC requirements on its own. 

Commenters stated that FERC and NERC require 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 utilities. 

Commenters 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. Commenters 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.

Commenters stated the EPA proposal ignored the interstate nature of ownership, contracting, and 

supply for municipal and electrical loads. Commenters 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 small 
45

municipalities who have no ability to redirect their power supply along environmental lines. 

Commenters stated that the EPA incorrectly assumes that "generation at one EGU can be 

substituted for generation at another" because the EPA considers the nationwide grid to be fully 

interconnected, such that electrons can be 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. Commenters stated there are actually 

three different electrical grids in the continental United States that operate with different 

electrical characteristics (Eastern Interconnection, Western Interconnection, and the Electric 

Reliability Council of Texas).

Commenters urged the EPA to work with states and 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 table for re-dispatch that does 

not threaten the reliability of the regional grid nor impose undue stranded costs on states' electric 

ratepayers. Commenters stated the Western Electricity Coordinating Council (WECC) began a 

phased study process to provide an analysis of potential impacts of the Proposed Rule to the 

Western electric generation and transmission industry. Commenters stated preliminary WECC 

results indicate that a state's decisions made regarding compliance with the Proposed Rule can 

"drastically impact grid operations, system resiliency, and potentially, compliance opportunities 

for a neighboring state." 

Commenters suggested that the EPA may need to revisit their understanding of dispatching, as 

well as a review of availability using local, existing 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. Commenters stated that the EPA knows that 

available electric generating units are dispatched by cost, and when the cost of natural gas fell 

below the cost of coal in 2012 (in lb/MMBtu of heat input), the resulting generation change was 

obvious. The commenters disagreed with EPA that these data suggest that, since the industry 

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. 

Commenters 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. Commenters 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

Commenters stated that EGU owners can replace fossil fuel-fired generation with renewable 

generation through bilateral contract. Commenters 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 for the sale of power. [FERC Primer at 60-61.] Commenters

stated that such contracts require the EGU to supply a certain amount of power to a customer 

such as a distribution utility. Commenters stated a large volume of renewable energy used by 

vertically integrated utilities--including IOUs, municipal utilities, and co-ops--is procured 

through PPAs with independent renewable developers. Commenters stated those utilities that 
46

own fossil fuel-fired EGUs are free to reduce the utilization of their EGUs and replace it with the 

procurement of renewable energy from renewable projects owned and operated by third party 

developers. Commenters 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. Commenters 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 and 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 utilization of their higher emitting 

EGUs.

Commenters stated that IPPs that own only fossil generation can also sign bilateral contracts with 

IPPs that own renewable energy. Commenters 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 commenters, merchant fossil-fuel fired EGU owners 

that do not own sufficient renewable generation or do not own it in the right location can instead 

act as a power marketer by signing a separate 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.

Commenters stated the bilateral market for renewable energy is well developed. Commenters

stated there are no legal or technical obstacles to a fossil fuel-fired EGU owner acting as the 

counterparty of a bilateral contract for purchase of energy from a renewable generation facility. 

Commenters stated the ability of non-utility entities to sign contracts for the delivery of 

renewable generation is sufficient proof that such contracts are adequately demonstrated. 

Commenters stated that even end-users that are not in the power sector have entered into such 

PPAs, including: 

• OwnEnergy has a contract to deliver the output of 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 Concerns
47

New Mexico

Commenters stated that the final rule should evaluate and adjust Building Block 2 where 

necessary to account for dispatch decision-making capabilities. Commenters stated that redispatch considerations in goal setting should consider whether out-of-state utilities and 

balancing authorities make dispatch decisions that affect states' ability to accomplish full redispatch. Commenters explained that many of New Mexico's dispatch decisions are not 

controlled by in-state authorities. Commenters 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. Commenters 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.

Commenters stated that the final rule should evaluate and adjust Building Block 2 where 

necessary to account for dispatch decision-making capabilities. Commenters stated that many of 

New Mexico's dispatch decisions are not controlled by in-state authorities as New Mexico is 

connected to two different grids and exports between 30 and 40% of its power annually, making 

it dependent on other states' dispatch authorities to make appropriate dispatch decisions. 

Commenters added that many of the state's rural electric cooperatives purchase power from the 

Southwest Power Pool, for which dispatch decisions are made in their Corporate Center in Little 

Rock, Arkansas. Commenters stated, nevertheless, 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

Commenters 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. Commenters 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 decision 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/MWh, the two 

states will face completely different compliance economics. 

Commenters 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. 

Commenters 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 that year. Commenters noted that 

in the EPA's goal setting methodology for Building Block 2, Deer Creek is ramped up to a 70 

percent capacity factor, requiring South Dakota's lone coal-fired unit - Big Stone (co-owned by 

Otter Tail Power, Montana-Dakota Utilities and NorthWestern Corporation) - to reduce 
48

operations to an annual capacity factor of 23 percent. Commenters 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 serve different loads.

Commenters stated that an issue EPA fails to consider in its simplified approach on NGCC redispatch is its potential implications on how states/RTOs could dispatch units where there are 

multiple RTOs operating in a single state. Commenters 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 Stone Plant 

co-owners' loads presently served by Big Stone Plant. 

Commenters stated that, because Deer Creek Station's load is delivered into a different RTO than 

the coal-based load at South Dakota's only coal-based plant, Big Stone, therefore its power 

cannot be used to replace Big Stone's load, as EPA's rule assumes. Commenters stated that, while 

the EPA assumed that the Deer Creek Station will 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. 

Commenters stated the EPA should reevaluate the role its Deer Creek Station plays in South 

Dakota, as EPA's treatment of this facility is erroneous and this impacts South Dakota's state 

emission limit significantly.

Commenters 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. Commenters 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 energy between those entities 

would require a willing buyer and a willing seller. Commenters stated Big Stone Plant and Deer 

Creek Station are not merchant units with unsubscribed capacity and energy available for sale. 

Commenters stated that, since Basin Electric built Deer Creek Station to serve its own load 

obligation, energy from Deer Creek Station has not been available for sale to the co-owners of 

Big Stone Plant, and Basin Electric lacks incentive or means to sell energy committed to serving 

its own load. Big Stone Plant's co-owners have no right to the energy output of Deer Creek 

Station, making re-dispatch infeasible.

Commenters stated that detailed engineering studies and modeling are needed to ensure that 

energy can be transferred effectively from each generator to the load it is intended to serve. 

Commenters stated that, while adequate transmission capability and infrastructure supports 

delivery of Big Stone Plant generation to its 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. Commenters

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. Commenters stated 

Building Block 2 is technically infeasible in South Dakota and, in its final rulemaking, the EPA 
49

should remove Building Block 2 from the target-setting calculation for South Dakota. 

Commenters stated they supported the comments filed by Commenters regarding Building Block 

2 and the Big Stone Plant. 

Other States/Areas

Commenters stated that Michigan's IOUs are market 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 provide supply to their customers. 

Commenters 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 dispatch of all generation, including NGCC units. 

Commenters 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.

Commenters stated that EPA's re-dispatch approach consequently conflicts with the 

responsibilities assigned to RTOs by FERC, and the nature of electricity markets today. 

Commenters added the Southwest Power Pool (SPP) responded to a question from the Missouri 

Public Service Commission on whether 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. Commenters stated that close coordination between SPP, members, regulators and the 

applicable state agencies will be needed to ensure that SPP's SCED system appropriately 

accounts for emission goals, which will not be a simple matter and will take considerable time to 

develop the appropriate protocols and potential market system changes.

Commenters stated that, while fossil fuel-fired generation sources located within 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. Commenters stated 

those resources are owned and controlled by utilities in other states. Commenters stated Building 

Block 2 creates conflict between states that share a common generating station. Commenters

stated that Nevada cannot utilize non-jurisdictional NGCC and coal-fired EGUs to assist in 

meeting its emission reductions targets until the jurisdictional issue has been addressed. 

Commenters 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 be 

submitted under the proposed deadlines. Commenters stated the Nevada Agencies request that 

the USEPA provide a more streamlined approach.

Commenters added that SWEPCO's comments to the Texas Public Utility Commission identified 

concerns over Building Block 2 in Texas - SWEPCO noted that the Proposed Guidelines' redispatch approach is inconsistent with the current dispatch algorithms used by balancing 

authorities, and that noneconomic dispatch will lead to increased costs for customers.

Commenters stated that power simply cannot flow across the east/west systems without 

constraint, as EPA assumes. Commenters explained that Basin Electric has several DC Ties that 

bridge the national electric system, but only has a limited amount of available capacity across
50

those ties. Commenters 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 natural gas and wind largely 

on the east, where good wind resources exist. Commenters stated that, because environmental 

dispatch has never before been proposed or mandated, Basin Electric has not developed its 

generating capacity to transfer across the east and west grids. Commenters stated that Basin 

Electric only has ownership or capacity rights to 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. 

Commenters stated that, as a result, Basin Electric cannot meet its member load requirements by 

simply re-dispatching NGCC on one side of the grid to replace power lost from a coal-based 

EGU on the other, or likewise replace lost generation from a west-side EGU with east side 

renewables. 

Commenters 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 because the 

Proposal relies on these fundamental errors. Commenters 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-dispatch of coal with NGCC units as 

described under Block 2, grid reliability, and transmission upgrades. Commenters stated that this 

assumption is completely false and illustrates how EPA has stepped outside of its expertise in 

this rulemaking. Commenters stated that, while Utah Associated Municipal Power Systems 

(UAMPS) is an active member of NTTG, NTTG is not a regional transmission operator and does 

not have control over grid reliability, capacity markets, scheduling/dispatch decisions or 

transmission upgrades. Commenters stated that NTTG is a planning organization that is designed 

to provide a forum for State, industry and public stakeholders to study transmission scenarios 

that may be ultimately implemented by NTTG members. 

Commenters 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, Commenters noted that 

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 transmission infrastructure as a 

system (not necessarily within individual states) to maintain reliability and minimize cost. 

Commenters indicated that three of TVA's five NGCC units are located in Mississippi, but all of 

its coal-fired units are located outside of Mississippi (TVA does purchase power through a power 

purchase agreement from the Red Hills coal-fired unit in Mississippi). Commenters concluded 

that increasing the capacity factor of TVA's Mississippi NGCC plants would have minimal effect 

on coal-fired generation in Mississippi: virtually all of the generation displaced would be from 

TVA's coal-fired units in other TVA states.

Commenters stated that the U.S. Energy Information Administration ("EIA") describes the grid 

and the systems that provide efficient and reliable electricity to consumers in its "primer," a 

document accessible to all, including EPA. Commenters said that it is most important to 

recognize that the grid uses market mechanisms to dispatch the proper mix of resources at any 
51

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, communication, 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. Authority 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 planning 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 

regional 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 electric power industry and the Federal Energy Regulatory Commission (FERC) continue to 

implement the requirements of the Energy Policy Act of 2005. This Act amended the Federal 

Power Act by adding Section 215, which set the responsibility for overseeing operations, 

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 Entities 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. Under 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 standards 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 EPA 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 “provides 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 

establish 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 included in the 

building blocks in order to do so. For a more comprehensive discussion of these issues, please 

see 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 comments under this comment:

Commenters stated the Proposal seems to work under the assumption that a state (or the loadserving entities within a state) have full legal 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 constraints.

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 proposed 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 solutions 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, commenters 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 statproposal for increasing 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 customer 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 stated the commenter's organization Members are committed to 
53

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 

products, 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 said 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 the 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 monitoring 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 upgrades 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 utilities. 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

Commenters 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 EPA's goal. Commenters

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. Commenters concluded that the grid 

operator might be forced to call on the state'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.

Commenters stated the proposed rule fails to recognize scheduling and dispatch are controlled by 

regional transmission organizations (RTOs) and independent system operators (ISOs). 

Commenters stated Montana cannot unilaterally implement Building Block 2 without intruding 

upon the jurisdiction of these organizations and the Federal Energy Regulatory Commission 

(FERC). Commenters 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 jurisdiction only over retail sales of electricity, generating facilities, facilities used for 
54

local distribution, and facilities used for transmission of energy wholly consumed by the 

transmitter.

Commenters stated that, although EPA considers each state's best system to be one in which all 

NGCC generators operate at a 70 percent capacity factor, the EPA fails to provide any 

information as to how a state would go about obtaining that result. Commenters stated that 

neither the EPA, the states, nor FERC has the authority to order natural gas generators to operate 

at that or any other capacity factor. Commenters 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 capacity factor will depend on market conditions, including natural gas prices. 

Commenters 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.

Commenters 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 demand at a given point, the variable costs, and system constraints; commenters

quoted the proposal as saying that it is this "security-constrained economic dispatch [that] 

assures reliable and affordable electricity" (79 FR 34862). Commenters 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. Commenters

added that the CAA does not give states the authority to regulate the dispatch of power plants on 

the interstate grid, which commenters characterized as a fatal flaw in this building block. 

Commenters stated that the EPA cannot cite any law or rule that permits states to override the 

FERC to meet air pollution goals, noting that any 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."

Commenters noted that the EPA cites the ability for states to control dispatch by example of the 

Title IV program (79 FR 34862), but commenters found this comparison unpersuasive. 

Commenters stated that most importantly, Title IV was approved by Congress under the CAA 

and this proposal has not been. Commenters added 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. Commenters 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 inside-the-fence 

based on allocations received. Commenters asserted that the EPA is not comparing apples to 

apples in comparing Title IV and the intricacies of this system-wide proposal.

Commenters stated that EPA's assumption that a 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. Commenters 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. 

Commenters stated that setting emission rate goals based on such an assumption exceeds EPA's 

authority under Section 111(d). Commenters suggested the states are in the best position to 

determine whether existing NGCC capacity can, in fact, supplant existing coal fired EGUs taking 
55

into account transmission constraints, gas supply limitations, remaining useful life, contractual 

obligations of NGCC owners, load pockets, location and actual capacity of NGCCs (including 

climatic and altitude considerations) environmental constraints (some NGCCs are limited by air 

permits due to proximity to non-attainment areas) and market limitations.

Commenters 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. Commenters stated FERC's 

role under the Federal Power Act (FPA) is to ensure that the power market is fair and that just 

and reasonable rates are maintained. Commenters 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.

Commenters stated that neither EPA, FERC, nor the states' as they have currently configured 

their institutions have the authority to decree a 70% capacity factor for gas plants. Commenters

stated the "unadministrability" of building block 2 provides further evidence that the Proposed 

Plan will not survive judicial review under the principles stated in UARG. 

Commenters stated the EPA and state environmental agencies cannot order the market to become 

uneconomical or unreliable. Commenters stated this market is controlled and regulated by many 

agencies (FERC, NERC, the Commodities Futures Trading Commission (CFTC), RTOs/ISOs). 

Commenters stated FERC's role under the Federal Power Act (FPA) is to ensure that the power 

market is fair and that just and reasonable rates are maintained. Commenters 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 force. Commenters stated the EPA cannot incorporate this carbon proxy cost into 

the market price of electricity. Commenters stated that, due to this, all of the volatility and 

instability that entities managing the market work to avoid will occur. Commenters stated 

capacity factor is a function of unit availability and cost. Commenters stated that, in MISO, plant 

efficiency, demand, cost of fuel, and transmission constraints all play a role in determining 

which plants run and when. Commenters stated superseding current market design with a 

requirement to run certain units regardless of traditional dispatch factors counters the long term 

resource planning used by RTOs. 

Commenters asserted that states operating in competitive energy markets cannot increase 

utilization without supporting market mechanisms and signals. Commenters 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.

Commenters stated the EPA does not have primacy on regulation of the nation's electric grid and 

natural gas transmission and distribution infrastructure. Commenters stated the EPA's authority 

under Section 111(d) of the CAA is to best protect the public from excessive emissions from 

affected facilities, not to limit operations of those affected facilities. Commenters 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. Commenters stated 
56

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

Commenters 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. Commenters stated the FPA permits utilities to set rates with 

individual electricity purchasers through bilateral contracts, though contract rates must be filed 

with FERC before going into effect. Commenters indicated that under the filed-rate doctrine, 

"interstate power rates filed with FERC or fixed by FERC must be given binding effect by state 

utility commissions determining intrastate rates." Commenters went on to note that when the 

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

through the Supremacy Clause, and that the filed-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 [service] as well as quantity 

and price terms." Commenters 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 electricity from them. Commenters stated that in 

calculating possible reductions from Building Block 2, EPA fails to document or account for the 

number of facilities whose electricity is partially or entirely committed through such contracts. 

Commenters noted that the American Public Power Association estimated that in 2013, twothirds of new capacity in the U.S. was built with Power Purchase Agreements for the sale of 

power. Commenters added that while 64 percent of these agreements were with a utility, the 

EPA fails to acknowledge or at all account for the fact that a significant percent of NGCC units 

will be unavailable for re-dispatch due to long-term contractual commitments. According to 

commenters, these contractual commitments commonly span 10 to 25 years in the Southeast and 

the West, and project finance contracts in organized markets have similar timetables. 

Commenters 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 example of several hundred MW of 

generation from a NGCC facility in New Mexico that is committed to out-of-state off-takers for 

the next 32 years. Commenters added that this generation cannot be presumed available for redispatch in New Mexico. Commenters stated that the EPA also assumes, under Building Block 2, 

that any increases in capacity at NGCCs will be eligible for re-dispatch, again ignoring the 

potential impacts of long-term agreements. According to the commenters, if a facility has 

committed the entirety of its electrical output to a counterparty under a long-term Power 

Purchase Agreement, then even if it could increase its output, it may not be able to sell the 

incremental additional output into the wholesale markets. Commenters 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. Commenters concluded that as a result of 

these omissions, the EPA overestimates the amount of electricity eligible for re-dispatch under 

Building Block 2.

Regional Markets
57

Commenters also stated that EPA ignores the fact that a number of states are located in more 

than one regional market. Commenters 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. 

Commenters noted that, in South Dakota where EPA's best system would significantly reduce 

generation at the Big Stone coal plant and replace it with generation from the Deer Creek NGCC 

plant, the dispatch of these units is controlled by two different operators and therefore they are 

not seamlessly integrated. Commenters stated that 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. Commenters 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 

coordinated fashion given that they serve different markets. Commenters also noted that these 

two plants were built to their particular size and in their particular locations to serve the needs of 

their utilities' customer bases, not those of other utilities and each of the owners of these plants 

possesses firm transmission rights to ensure that the generation reaches load. 

Commenters stated the proposal does not take into account how the organized markets of an 

RTO like PJM function. Commenters asserted that states 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. Commenters 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. Commenters stated those federal,

wholesale market signals also serve as indicators for whether the EGUs should continue to invest 

in ongoing operation and maintenance expenses. Commenters asserted that States no longer have 

the ability to intervene to direct which resources are operated, constructed, or maintained. 

Commenters stated that, while states that have retained or returned to traditional regulation have 

some control over EGUs and how they are dispatched, restructured states have little to none.

Commenters stated the EPA's analysis of Building 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. Commenters stated that Pennsylvania, for 

example, has turned 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. Commenters stated that, unless and until EPA addresses this issue, any final rule relying on 

re-dispatch would be unsupported by the record.

Commenters stated that the EPA cannot assume states have jurisdictional control over the 

dispatch of electricity. Commenters stated the EPA should not assume that all of the NGCC 

plants are owned and operated by the same entity 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 regulator or system 

operator. Commenters 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. Commenters stated that the state 

also has no authority over this dispatch process and no mechanism to force or modify dispatch of 
58

these plants. Commenters stated the EPA has failed to explain how the state could control the 

dispatch of these NGCC plants given current Federal Energy Regulatory Commission (FERC) 

regulations. Commenters stated the EPA assumed a 70 percent utilization rate of all NGCC in the 

state without regard to how these units are dispatched by the utilities and Regional Transmission 

Organizations (RTO) and the USEPA has not identified any tools to do this and has not 

addressed federal regulatory barriers. Commenters stated that, in Michigan, the majority of the 

NGCC capacity is dispatched by the RTO and the state has no authority over this dispatch 

process and no mechanism to force or modify dispatch of these plants. Commenters 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 transmission 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.

Commenters stated there are limits on states' authority to mandate re-dispatch. Commenters

stated that MISO, like all system operators, dispatches electricity on a priority basis of (1) 

reliability and (2) least costs. Commenters stated that, because compliance obligations and costs 

differ greatly among states, it would be impossible for a unit in one state to determine the bid 

price necessary to ensure that it would or would not be dispatched before generating units in 

other states within the MISO region. Commenters stated this is further complicated in states that 

fall within multiple regions, such as South Dakota. Commenters stated the EPA assumed that 

generation from Deer Creek could be increased and, as a result, generation from Big Stone 

decreased; however, because Big Stone and Deer Creek participate in different markets, the 

presumed increase in generation from Deer Creek could not displace load requirements for Big 

Stone.

State-Specific Concerns

Commenters 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. 

Commenters 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. Commenters

asserted Indiana does not have regulatory authority to control the dispatch of electricity within its 

own borders, let alone on a regional basis, and thus lacks the authority to implement Building 

Block 2. Commenters stated that, even if the state were to establish the authority to mandate 

dispatch of electricity from NGCCs at a certain level of capacity, implementation would have to 

be conducted by an RTO, not the state. In that case, commenters stated Indiana would not be in a 

position to properly oversee and enforce implementation, or ensure adequate recordkeeping.

Commenters 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. Commenters

stated the EPA must revise how it applies building block 2 in goal setting because it must reflect 

realistic and reasonable outcomes. Commenters 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 generation in New Jersey, which, according to Commenters is 

not a realistic or reasonable outcome. Commenters stated that in deregulated markets, such as in 
59

New Jersey, the dispatch of units is determined by economic merit. Commenters offered that 

states can influence 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. Commenters 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. Commenters stated that, as EPA defines "affected EGU", New Jersey's in-state 

affected generation comprises approximately 40% of New Jersey's annual in-state power 

generation (from only 30% of New Jersey's electric generating capacity) and dispatch may be 

provided by a multitude of various source types throughout the PJM region. 

Commenters indicated that the Pennsylvania DEP and the Pennsylvania Public Utility 

Commission (PA PUC) lack the authority to dispatch EGUs, and there is no practical way for 

Pennsylvania to implement Building Block 2. In Pennsylvania, commenters said, the dispatch of 

generating units is under the direct control of PJM Interconnection, LLC (PJM), which does not 

have the authority to act as an environmental regulator and must dispatch units based on its tariff. 

Commenters said that Building Block 2 should not be included in the determination of BSER 

because re-dispatching from one stationary source category to another category is not consistent 

with BSER as prescribed in the CAA. 

Commenters also stated that in Ohio it is the EGU owners 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. Commenters asserted 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. Commenters

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? 

Commenters 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. Commenters

stated that this element of the proposal must be dropped from further consideration.

Title V Permit

Commenters noted that the EPA suggested that states could implement increased re-dispatch of 

NGCC by limiting the operation of coal-fired EGUs through permits (79 FR 34862). 

Commenters 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. Commenters asserted that placing a specific limit on the number of hours a baseload coal-fired EGU could operate reflects the EPA's lack of knowledge on the federal mandates 

of large utility plants to operate for reliability purposes.

Comment 14: Commenters said that not all EGU owners have the 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:

Commenters 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 within their 

control" (79 FR 34889) is faulty and unsupported assumption. Commenters 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. Commenters stated that facilities may be 

ordered to either increase or decrease generation by the regional authority to ensure the integrity 

of the electrical grid. Commenters added that there are aspects of Block 2 that are clearly outside 

the authority of the affected sources, e.g., 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. Commenters 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. 

Commenters stated that new legislation would be required if, as the EPA' s IPM model indicates, 

the State of Louisiana will likely find its best compliance option to be to direct the retirement of 

RPS-2. Commenters 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 generation alternatives. Commenters 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.

Commenters stated that the responsibility to achieve the emission performance level may 

be assigned solely to EGUs, but it leads to some questionable scenarios. Commenters stated that 

one scenario is when a regulated unit is subject to a System Support Resource Agreement (SSR) 

that requires a unit to operate to maintain system reliability. According to commenters, Michigan 

has three power plants in the Upper Peninsula that are subject to an SSR Agreement: the Presque 

Isle Power Plant, the City of Escanaba Plant, and White Pine No. 1. Commenters asked, if a unit 

cannot run because of a CO2 limit, how would this interact with a SSR ordered by FERC? 

Commenters said that the state has no control over dispatch or SSRs, and the EPA should explain 

how the interrelationship between CO2 dispatch and a SSR order could work under this rule. 
61

Comment 15: Commenters asserted the EPA failed to describe the mechanisms states can use to 

develop and implement an approvable plan.

Response 15: The EPA disagrees. In response to additional 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. EPA believes that the 

preamble of the final rule describes mechanisms that a state may use to develop and implement 

and approvable plan. See sections V.D, VIII.A, VIII.C and VIII.G of the final rule preamble of 

the CPP. 

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

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

and implement a plan that will reliably demonstrate compliance. Commenters explained that 

Building block 2 cannot require states to interfere with the economic dispatch or reliable 

operation of the grid because states cannot interfere with the existing regulatory authority and 

enforcement responsibility of the federally authorized agencies that control unit dispatch 

decisions and plan for the reliable operation of the electricity grid. Commenters stated that it is 

unclear how EPA would envision a regulatory requirement be structured and enforced to achieve 

the types of redispatch assumptions that were used to derive the state goals. Commenters

indicated that a review of recent permits for NGCC units and other fossil units and found no 

examples of facilities that have an enforceable minimum capacity factor limit. Commenters

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, 

and current permits and regulatory requirements for the existing NGCC fleet are sufficient for all 

units to sustainably achieve a 70% capacity factor. Commenters stated the EPA's own modeled 

outputs indicate that the targeted 70 percent capacity factor used to create the state goals would 

not in fact be achieved by the proposed CPP. Commenters 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 reflect the operation of the electricity grid.

Commenters 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. Commenters 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 

percent in any given year. Commenters 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 forecasts about the future 

trajectory of electricity use decades into the future, something even the federal government 

admits is beyond its capabilities.
62

Commenters 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. 

Commenters 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. Commenters

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. Commenters 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. Commenters 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 needed to serve load in a different 

part of the state.

Commenters 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. 

Commenters stated 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.

Commenters noted the EPA requested comment on whether it should 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). Commenters stated the EPA neglects to 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. Commenters stated that the 

EPA has no authority 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 oversight by state 

utility commissions and the Federal Energy Regulatory Commission. Commenters stated the 

decision making authority to increase the capacity factor of NGCC units as well as whether to 

dictate whether reductions come first from coal generation or oil/gas generation is based on a 

number of factors and clearly does not belong to EPA and therefore should not be considered.

Commenters referred to comments made by Nevada DEP et al. ("Agencies"), who question 

whether EPA has jurisdiction to authorize re-dispatch of various EGUs to achieve emissions 

reductions, and stated that they do not see this as a major shift from other Clean Air Act 

strategies to reduce criteria pollutants including ozone or PM.

Comment 16: Commenters stated that Alaska should be exempted 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, commenters

stated that the goal calculation for Alaska should not include any provision for re-dispatch.
63

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

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

Commenters 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. (Commenters noted that the calculation does not account for Healy Unit 

2.) Commenters 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. Commenters 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 and, 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. 

Commenters stated that the NGCC EGUs that EPA's goal computation assumes can replace 

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 commenters, this 80 MW transmission line is 

already generally operated at capacity to deliver hydroelectric and 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. 

Commenters added that the Healy units provide 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, 

commenters asserted that Alaska cannot execute the second building block. Commenters 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 fossil-fuel 

fired units. Commenters 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 compromise the state's ability to 

address the PM2.5 non-attainment finding for Fairbanks. Commenters believed that these options 

are not realistic.

Commenters went on to state that if the rule is applied to Alaska, the goal calculation should not 

include any 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. 

Commenters concluded that Alaska cannot re-dispatch coal generation at a reasonable cost.
64

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

certain cases.

Response 17: The EPA disagrees. We are providing states with substantial flexibility as to how 

they structure their 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. 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 building block 2 does not provide Owensboro Municipal Utilities 

(OMU) with options for compliance because Kentucky has no operating NGCC plants and only 

one NGCC facility under construction. Commenters stated that, at the time of the issuance of the 

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 Plant17, OMU and other 

LGE/KU transmission system participants have no access to such units. Commenters 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. Commenters stated that 

bringing CCGT energy into OMU from TVA is possible but would entail incremental 

transmission cost and a capacity purchase agreement with an IPP in TVA. Commenters stated 

such a mandated power purchase agreement as a condition of OMU's compliance plan is most 

likely a violation of the Federal Power Act. 

Commenters stated that bringing CCGT power into the LGE/KU control area to serve OMU load 

from MISO or PJM entails increased transmission cost and would be subject to recall during 

Maximum Generation Events. Commenters stated that, in Kentucky there is a lack of natural gas 

infrastructure: there are no existing NGCC plants in Kentucky and the natural gas supply and 

delivery infrastructure does not exist to sustain a forced conversion to a significant percentage 

natural gas based generation in a state where 93% of electric generation is from coal. 

Commenters stated that, even if this were the most cost effective option for Kentucky's EGUs in 

a final rule, sufficient time to site, permit, engineer, procure and construct the required pipeline 

and natural gas storage capacity is impossible by the interim compliance date. Commenters

stated that, for a FERC regulated pipeline company to build new natural gas pipeline, they would 

first require a firm commitment from shippers on the proposed pipe before FERC would 

authorize the project. Commenters stated the proposed rule and the RIA did not adequately 

account for the time of the construction of the necessary natural gas pipelines or 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. 

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 

regulatory requirements and infrastructure. The rule provides Florida 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:

Commenters 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. Commenters stated that Florida's geographical 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.

Comment 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 Rate

Commenters 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: 
66

• Commenters stated that implementation of Building Block 2, including the redispatch 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 NGCC, Plant Lowman's heat rate is likely to increase 

because operational stability is the single largest factor in heat rate.

• Commenters stated Building Blocks 1 and 2 are economically inconsistent, since 

on the one hand, Building Block 1 assumes emission reductions from heat rate 

improvement projects at existing coal-fired boilers, while on the other hand, 

Building Block 2 assumes increased utilization of NGCC units at the expense of 

coal-fired units. Commenters stated the EPA fails to acknowledge this 

inconsistency.

• Commenters stated Building Block #2 will negate some if not all of the heat rate 

improvements from Building Block #1. Commenters 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. Commenters 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 reduction strategy (or strategies) implemented will not lower the 

annual average heat rate as much when compared to base-load operation. 

Commenters stated that, in some cases, any HRI improvements achieved by 

undertaking the relevant options described in Building Block #1 could be negated 

by load-cycling. Commenters 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 graphically represent in Figure 6 by the 

Dispatch net load by date. S&L also evaluated heat rate over the operating range - figure 7 and 

table 10 of Attachment B - net unit heat rate 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 

Block #2.

• Commenters 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 brought on as a result of applying building block 2 as 

proposed by EPA. Commenters 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 reductions achieved by building block 
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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 coalfired fleet. Commenters 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%.

• Commenters 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. Commenters stated that coalfired EGUs are not designed for load-following and cycling, which reduces their 

efficiency, thereby increasing heat rates. Commenters stated a coal-fired EGU's 

heat rate is highest (i.e., least efficient) at the minimum load point at which the 

unit can safely operate. Commenters stated that extra energy is required to shift a 

unit from low to higher loads to overcome inertia in the system. Commenters

stated the more frequently a unit must move up and down the load curve, the more 

excess energy will be required to produce the desired load and, thus, the unit will 

be less efficient on average.

• Commenters stated that, under the Proposal, coal units would be operated more as 

peak demand units even though coal units operate more efficiently as base load 

units. Commenters 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 improvements. 

• Commenters 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.

• Commenters 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 commenters, 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. Commenters 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 capacity factors. 

• Commenters stated that, while AEPCO can attempt to reduce utilization of its 

highest carbon intensity sources, it must also meet its members' load requirements 

and, thus, reduced utilization thus must be undertaken in conjunction with another 

alternative, purchase or construction of another generation asset, or market power 

purchases. Commenters noted that reduced utilization also adversely affects the 

heat rate of the EGU compared to full utilization.
68

• Commenters 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 of the 

country. Commenters 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. Commenters 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 increased load-following generation that will likely occur as 

renewable generation increases. 

• Commenters stated that cycling coal-fired units on and off could lead to increased 

pollution from unit startup and shutdown.

• Commenters stated the re-dispatch of coal-fired 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. Commenters

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 thermal 

efficiency and increase the CO2 emission rate of the formerly base-loaded EGU. 

Commenters stated such degradation in heat rate at coal-fired EGUs could also 

offset any potential heat rate improvements due to equipment upgrades or changes 

in operation and maintenance practices set forth in Building Block 1, and would 

impact the economic viability of such upgrades and changes.

Commenters stated that implementation of Block 2 affects other building blocks and suggested 

Building Block 2 be calculated first, then Block 1 evaluated after determining which coal units 

continue to operate based on modeling runs and how the coal and gas units will be dispatched. 

Commenters stated that increasing the capacity factor of NGCCs and subsequently reducing the 

capacity factor 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. 

Commenters stated these building blocks are not additive for this reason. 

Commenters stated that EPA must establish a floor for operation of existing coal-fired EGUs that 

prevents degradation of their heat rates. Commenters noted that the real heat rate begins to 

degrade significantly when the capacity factor for Wisconsin EGUs falls below 50%. 

Commenters stated that, as a result, the EPA should not allow the capacity factor of Wisconsin 

coal-fired EGUs to fall below 50% when determining building block 2. Commenters stated that, 

in applying this criterion, the EPA must also maintain operation of all of the coal-fired EGUs. 

Commenters noted that significant investments have recently been made in these EGUs to 

continue their efficient operation into the foreseeable future. 
69

Discourage Investment

Commenters 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 discourage continued investment at Lowman, which would make heat rate 

improvements unlikely. Commenters stated the EPA fails to address why EGUs would make 

heat rate improvements if their utilization is undercut by increased NGCC utilization. 

Comment 20: Commenters 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 

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. 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 CPP final rule. 

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

Fossil Fuels

Commenters stated that if the EPA's goal is to curb the effects of climate change, then the EPA 

must revise the proposed rule to ensure that the standards do not phase out one fossil fuel, coal, 

just to replace it with another fossil fuel, natural gas, for power generation. Commenters stated 

that the market is already pushing the switch from coal to gas, but the rule may assist in 

accelerating the trend if it isn't carefully designed. Commenters suggested that goal achievements 

would be canceled out if states increased CO2 equivalent during the duration of the plan as a 

result of increased natural gas-fired power plants.

Commenters expressed concern that the CPP will lead to an over-build of new gas plants, with 

commercial lives of 30 or more years. Commenters 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, 
70

including the US, has to achieve near complete independence from carbon emissions to avoid the 

worst risk of climate change by 2050; it is critical to avoid inducing too much new gas 

technology in 2020. Commenters stated that an oversupply effectively removes the incentive to 

deploy additional technology; thus locking in a large amount of new gas resources will have the 

side effect of locking out renewables and other new clean technologies, in both competitive 

market and regulated utility regimes, for an extended period. Commenters 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.

Commenters expressed concern that the CPP could accelerate the lock-in of large amounts of 

new natural gas generation, particularly in some regions, while generally delaying the 

deployment of tomorrow's cleaner and cheaper renewable energy and emerging competitive 

distributed energy resources. Commenters stated the NRG warns that this could result in the 

overbuilding of new natural gas plants, which would reduce the incentive to add new renewable 

generation capacity to the grid, locking out energy resources that are truly clean. 

Commenters stated the Proposed Rule's drive to increase natural gas consumption would have a 

negative effect on the expansion of renewable 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 this 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.

Hydro, Nuclear, Solar and Wind 

Commenters stated that achieving a set capacity factor for a specific fleet of units in states who 

have instituted deregulated electricity markets will be challenging. Commenters 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 could 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.

Commenters 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.

Commenters 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. Commenters stated that, because CO2 

emissions are lower when NGCCs dispatch in concert with renewable energy resources rather 

than alone, the Proposed Rule would increase, rather than decrease, emissions in areas with a 

high integration of variable energy resources.
71

Commenters 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. Commenters

stated that, in order to achieve the NGCC dispatch target, North Carolina would be required to 

cycle down nuclear units and dispatch NGCC units in their stead. Commenters stated that, due to 

their operational characteristics, nuclear units are not capable of cycling to allow for NGCC 

generation during these off-peak months. Even if technically feasible, commenters stated that 

cycling of nuclear generation would be counterintuitive because nuclear generation produces 

zero CO2 emissions while NGCC does not. Commenters stated that it is inconceivable that EPA 

intended such an illogical result when propounding this building block. Commenters stated that 

any building block based on increased natural gas dispatch should be directly based on the ability 

of a state to increase its NGCC units' dispatch consistent with sound environmental and 

economic principles. Commenters stated that, based on the data discussed above, the emission 

reductions attributed to North Carolina's increased use of NGCC units is overstated and the EPA 

should recalculate the emission reductions attributed to this building block in light of the 

additional NGCC dispatch that is technically feasible in North Carolina.

Commenters expressed concern that Arkansas receives almost zero credit for nuclear and 

hydroelectric power plants that produce no greenhouse gas emissions. 

New York

Commenters stated that the EPA's re-dispatch approach fails to account for two important 

considerations relevant to New York. Commenters 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 the re-dispatch assumed would require not using available generation from nonemitting resources to "make room" for the NGCC output, undermining the intended impact on 

overall CO2 emissions. Commenters stated that the flaws with the Clean Power Plan that would 

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. Commenters 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 Building Blocks.

Commenters stated the EPA's assumed increase in the capacity factor for New York's NGCC 

EGUs would require a dramatic, highly-uneconomic re-dispatch that would compromise 

reliability and would actually require backing down lower emitting generation resources. 

Commenters stated that most of New York's NGCC EGUs are located in the western part of the 

state along with the bulk of the state's hydropower and nuclear generation and that operating the 

NGCC EGUs at the levels assumed by the EPA would produce more electricity than the 

combined total of the demand in that portion of the state and the transmission transfer capacity to 

the areas of greater demand to the southeast. Commenters stated it is not possible to run NGCC 

resources at the levels assumed by the EPA without reducing the use of generation from nonemitting wind, hydropower, and nuclear units that are also located in the western portion of the 

state. Commenters stated it would be illogical and counterproductive to pursue such a re-
72

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

renewable generation in the name of reducing CO2 emissions.

Comment 21: Commenters stated that, despite concerns regarding methane leakage, expanded 

dispatch of NGCC can provide immediate, substantial emission reductions, as the EPA and other 

observers have recognized.

Response 21: The EPA agrees. See section V.D. of the final rule preamble of the CPP, and the 

Regulatory Impact Analysis of the final CPP for the EPA’s response to this comment.

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

Commenters stated the much lower GHG footprint of gas-fired generation (as compared to coalbased 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,” however 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.

Commenters stated that, although natural gas is currently a cheap form of electric generation, it 

is not a long-term solution. Commenters stated that emerging technologies like wind and solar 

are rapidly decreasing in price and already employing thousands of Missourians. Commenters

stated that, with strategic investments to reach new economies of scale, wind and solar will soon 

become the cheapest form of electric generation available. Commenters stated that, as a nation 

we should not waste this regulatory opportunity on technologies that will always be based on 

finite resources that emit large amounts of carbon into our atmosphere. 

Commenters stated natural gas is not clean energy. Commenters suggested minimizing the 

reliance on industries such as coal and natural gas and oil, which will create more demand for 

renewable clean energy and alternative energy that truly is sustainable.
73

Commenters stated that the proposed rule should be improved so that it ensures that states are 

pursuing renewable energy and energy efficiency as the first priority. Commenters stated that the 

EPA should not approve compliance measures that would incentivize the construction or 

utilization of new fossil fuel generation. Commenters also stated that the EPA should not 

undersell what states can do with RE and EE, which commenters stated will help states reach 

their targets more effectively. Commenters stated that the proposed rule will increase gas 

generation with a potential increase of 180 percent by 2020. Commenters stated that no CPP 

should incentivize the expansion of fracked gas in the electricity sector. 

Commenters referred to a Stanford University study titled, "Changing the Game: Emissions and 

Market Implications of New Natural Gas Supplies" and stated that the study shows that the shale 

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. 

Commenters noted the Stanford study did not address some of the debate about methane leaks 

from hydraulic fracturing drillings and other production supply chains steps. 

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. Commenters 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. Commenters 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 gas reduction diminishes. Commenters 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. Commenters stated the Clean Power Plan will drive too much of the 

electrical utility generation market to natural gas power plants resulting in a short-term failure to 

meet greenhouse gas reduction goals and undermining more effective immediate steps with 

energy efficiency, demand management, energy storage, and development of existing as well as 

future renewable energy generation alternatives. Commenters 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. 

Commenters asserted the Clean Power Plan should promote a rapid transition away from fossil 

fuels towards renewable sources of power, such as wind and solar. Commenters 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. Commenters stated that, even without taking into account methane leakage, however, 

natural gas is a fossil fuel that emits greenhouse gas pollution when burned and thus cannot be 

part of a common-sense solution to climate disruption. Commenters 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 in dirty energy infrastructure. 

Commenters stated that instead of promoting the increased use of gas, we must transition rapidly 

to truly sustainable energy sources. Commenters stated that increased reliance on fracked gas at 

best significantly delays and at worst may altogether displace the development of solutions such 

as wind, solar, and energy efficiency. 
74

Commenters stated the promotion of greater dispatch of gas-fired power plants as a substitute for 

coal should be removed from the description of building block #2. Commenters stated the rule 

should not accept the greater dispatch of gas-fired power plants or replacement of coal-fired 

power plants with gas as measures of compliance pursuant to building blocks #2 or #3. 

Commenters stated the EPA should set much more aggressive goals for zero-emission 

renewables. Commenters stated avoiding climate catastrophe will require that the U.S. swiftly 

and dramatically reduce its consumption of both coal and gas. Commenters stated that, because 

natural gas does not 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. 

Commenters objected to the proposed regulations because natural gas electricity generation 

would be 18-19 percent higher by 2030 under the EPA's plan than it would be without the plan. 

Commenters stated this is a problem because, if we are to meet our larger G-8 commitment, we 

need to remove fossil fuels from our mix. Commenters stated that natural gas plants, once built, 

stay in use; in analyzing lifetime emissions for a natural gas plant, the National Energy 

Technology Laboratory assumed a lifetime of 30 years. Commenters stated the way to transition 

off of fossil fuels, and the greenhouse gas dangers that they present, is not to build more fossil 

fuel plants that will stay in operation well into the middle of this century. 

Commenters stated the trajectory of increasing use of natural gas is incompatible with the far 

deeper reductions in CO2 emissions that will be required in the decades following 2030. 

Commenters stated the CPP has given no consideration to this issue. Commenters stated 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. Commenters stated this should factor into the 

EPA's analysis of the potential problems associated with increasing natural gas production for 

use in the electricity sector. Commenters stated 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 increase natural gas use in electricity production, until a more definitive assessment 

in its favor is demonstrated. Commenters stated that, since plenty of options with a more certain 

and a cleaner path to CO2 emission reductions are available, the EPA should indicate that these 

would be preferable and less open to question than an increase of natural gas use in electricity 

generation. 

Commenters suggested the trajectory of short- and medium-term policies should be compatible 

with a global phase-out of all CO2 emissions by the end of this century, a topic that has been 

broached in the IPCC5 report. Commenters stated this report estimates that a trajectory limiting 

global average temperature rise to 2o

C would have to reduce global greenhouse gas emissions 

between 78 and 118%. Commenters 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 net CO2 removal from the 

atmosphere. Commenters stated the EPA's natural gas use trajectory is even more intensive than 

that in the 2014 AEO of the EIA, which projects that 30.6% of electricity generation in 2030 

would use natural gas. Commenters stated the EPA's modelling of the electricity sector for the 

year 2030 suggests that about 34% of the generation in 2030 would use natural gas as fuel. 

Commenters stated the EIA reference case for natural gas in EIA AEO 2014 projects total 

natural gas supply for U.S. use of 29.56 trillion cubic feet in 2030. Commenters stated that, using 

a 2.5% venting rate, 20-year warming potential of 86, and assuming that 80% of natural gas is 
75

burned as fuel, the total emissions from the natural gas fuel system would be about 2.3 billion 

metric tons of CO2eq 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.

• Commenters stated that natural gas development leads to global warming. 

Commenters 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. Commenters also stated that natural gas 

development leads to global warming through massive deforestation for the 

purpose of constructing injection wells and infrastructure. Commenters used 

Pennsylvania, which has lost hundreds of thousands of acres of old-growth forest 

to natural gas development, as an example. Commenters stated that this deprives 

the plants of the natural process of transpiration. 

• Commenters stated that regulatory agencies should cease granting fracking 

permits and should cease saying that natural gas is the answer to atmospheric 

pollution and climate change. Commenters 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. 

• Commenters stated that natural gas may be necessary over the short term, but it is 

not as clean as previously thought and so does not belong in the clean energy 

plan. Commenters stated that natural gas 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. Commenters stated that starting at extraction through 

processing and transportation, natural gas emits methane from leakage, the 

amount of which is about one half to three times as much methane as estimated. 

Commenters pointed out that methane is a much more potent gas than CO2. 

Commenters cited extraction as a problem with natural gas; all of the easy natural 

gas has been depleted, and fracking is the only economical option left. 

Commenters attributed a lot of the methane to fracking and expressed support for 

the EPA's support to control leakage.

• Commenters stated that the proposed rule is deficient in its reliance on a building 

block of replacing coal generation with natural gas plants, which the rule assumes 

will be less carbon intensive. Commenters stated that the proposed rule fails to 

increase efficiency standards for natural gas plants. Commenters stated that there 

is scientific evidence that the proposed rule understates the climate harms of 

natural gas generation by failing to use reasonable means to account for methane 

leakage and the intense and short-term greenhouse gas effects of atmospheric 

methane. Commenters stated that encouraging natural gas development would 

impose substantial externalities on the communities directly affected by drilling 

infrastructure and fracking.
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• Commenters expressed concern that a switch to natural gas is not the solution we 

need if we are serious about protecting the environment from all effects of power 

generation, not simply carbon emissions. Commenters 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 panel 

on climate change, and leakage above three percent is enough to negate the 

climate benefits of natural gas over coal.

• Commenters stated that replacing coal with carbon cannot get us to the 80% 

reductions needed by 2050.

• Commenters 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. Commenters 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. 

Commenters stated the rule should not accept the greater dispatch of gas-fired 

power plants or replacement of coal-fired power plants with gas as measures of 

compliance pursuant to building blocks #2 or #3. Commenters stated that 

avoiding climate catastrophe will require that the U.S. swiftly and dramatically 

reduce its consumption of both coal and gas.

• Commenters stated the proposed regulations 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. 

Commenters stated replacing CO2 with methane is not a "clean power plan." 

Commenters 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 would 

make natural gas just as bad, or worse than, coal as an overall driver of climate 

change. Commenters stated a series of scientific studies clearly demonstrate that 

methane is not an environmentally acceptable alternative to coal. Commenters

stated the political pragmatism of the CPP's encouragement of natural gas cannot 

be justified by real scientific or economic analysis. Commenters stated methane is 

not a "bridge fuel"; it will lock us into a fossil-fuel dependent future, and is 

therefore a road to climate chaos. Commenters 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 change than a commensurate 

amount of carbon dioxide. Commenters stated our aging methane infrastructure 

leaks, and should be gradually decommissioned, not expanded. Commenters

stated the economic and ecological damages resulting from coal and oil users 

switching 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 climatefriendly equipment such as is needed to support geothermal, solar, and wind. 
77

• Commenters expressed concern that, while many coal plants are receiving a "new 

lease on life" via conversion to natural gas, this is not necessarily the most 

appropriate long-term solution. Commenters stated the energy prices will remain 

volatile due to global factors beyond our control - so long as we are paying for 

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

geothermal-based technologies. Commenters stated that self-sufficiency should 

begin with energy efficiency, rather than building yet another carbon bubble.

• Commenters 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 perspective. Commenters suggested that the leakage of methane during 

the extraction, processing and transportation of natural gas needs to be evaluated. 

Commenters stated recent studies suggest that a leakage rate higher than 2.4-3.2% 

will mean that natural gas is more of a global warming threat than coal is. 

• Commenters stated that the EPA should re-visit the definition of re-dispatch and 

its usefulness to achieve the goal of reduced emissions. Commenters stated that 

there is no legally binding language in the 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. Commenters stated that zero-emissions standards should mean zero 

emissions and have no permitted allowable releases or venting of permissible 

levels of toxic air contaminants or radioactive releases.

• Commenters stated that federal action is also needed to ensure that decreased 

electricity sector demand for 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 associated 

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 represent 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.

• Commenters expressed concern that fracking threatens water supplies and 

releases pollutants into the air including benzene, formaldehyde, and particulate 

matter. 

• Commenters expressed concern that the proposed Clean Power Plan BSER 

encourages unsustainable practices that neither reduce climate change nor best 
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protect environment and human health. Commenters 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 not all, natural gas will soon 

come from unconventional sources including shale gas retrieved by hydraulic 

fracturing. Commenters stated that the science on fracked gas is controversial, and 

it is unclear if the lifecycle of fracked gas causes fewer greenhouse gas emissions 

than other carbon based sources. Commenters also stated concern with possible 

ground water and surface water contamination from fracking practices. 

Commenters also stated that it is unclear the extent to which fracked gas depletes 

scarce water resources. 

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

• Commenters expressed concern that the new rule will further enable shale gas and 

oil industries to secure its hold in Pennsylvania and do more damage to ecological 

and human health. Commenters stated that the new rule would force Pennsylvania 

to reduce its air pollution and burn less coal, but commenters stressed that it is 

how less coal occurs is what makes the difference. Commenters stated that doing 

nothing but replacing coal with fracked gas will cause the air and atmosphere to 

worsen. Commenters stated the rule implicitly give consent to burn more trash, 

tires, coal sludge, and other forms of toxic waste for electricity. Commenters

stated the rule is a good first step, but it will the unintended consequence of 

replacing one dirty fuel with many others.

• Commenters stated that the CPP promotes fracking, and fracking contributes to 

climate change and threatens Americans' air and water quality. Commenters cited 

a 2010 study by Theo Colburn and later the Colorado School of Public Health 

which found that fracking releases volatile organic compounds (VOCs) into the 

air; the VOCs can combine with diesel emissions to form ground level ozone due 

to high truck traffic which accompanies fracking. Commenters 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. Commenters also mentioned the 

link between the disposal of toxic fracking waste in injection wells and 

earthquake activity in many states.

• Commenters 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. Commenters noted that the overall methane 

emissions are considerably higher than the official inventories report.

• Commenters suggested that the EPA consider water quality and quantity issues 

related to fracking before encouraging additional fracking. Commenters referred 

to a congressionally mandated drinking water study of the shale gas extraction life 

cycle and the notice and comment process evaluating the promulgation of 

hydraulic fracturing chemical and mixture disclosure rules under the Toxic 

Substance Control Act (TSCA). 
79

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

outside-the-fence limitations such as water withdrawal and thermal restrictions.

• Commenters 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. 

• Commenters also stated that the rule should not incentivize using more natural gas 

by counting changes to fracked gas power as an emissions reduction. Commenters

mentioned that fracked gas has lifecycle greenhouse gas emissions close to and 

possibly worse than coal. Commenters also mentioned the associated release of 

methane.

• Commenters stated that natural gas companies cause irreversible environmental 

destruction. Commenters called for no subsidies or incentives for the natural gas 

industry. Commenters said that taxpayer money should instead be used to 

encourage clean, sustainable, renewable energy and not build infrastructure for 

pipelines.

• Commenters stated that increased dependency on gas would also lead inevitably 

to more fracking, with its associated air and water contamination, earthquakes, 

and its attendant litany of other environmental and human health problems. 

Commenters stated methane is a dangerous substitute for coal: fracking destroys 

landscapes, contaminates air and groundwater, and 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 

methane 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. Commenters stated the EPA must factor 

in the cost of the 72 trillion gallons of water used to operate the current 500,000 

fracking wells. Commenters 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. 

Commenters 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. 

• Commenters expressed concern about several adverse impacts related to natural 

gas. Commenters stated that natural gas obtained by hydraulic fracturing is not 

clean from a public health or climate perspective. Commenters stated that 

fracking is associated with local and regional air pollution, adverse birth outcomes 

and contamination of drinking water. Commenters questioned 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. Commenters stated that it may also be necessary to 
80

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 hydraulic fracturing or "fracking" to extract natural gas. Commenters

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 causes 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. Commenters asserted that both the health effects and 

environmental impacts of fracked gas are still very unclear. 

• Commenters expressed concern that the process of fracking will be with us for a 

very long time. Commenters stated that currently about 30% of our national 

power plants rely on natural gas to generate electricity and, if the 38% of coalfired power plants are converted under the re-dispatch program, then 68% of our 

power plants will rely on fracked gas. Commenters 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.

Commenters 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. Commenters 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. Commenters 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. Commenters recommended the final rule include 

language to encourage adherence to best practices for hydraulic fracturing to mitigate associated 

adverse impacts. Commenters recommended encouraging best practices related to (i) having a 

systematic approach to assessing and managing human rights and health impacts, (ii) ensuring 

adequate community consultation to minimize impacts, (iii) requiring disclosure of the chemicals 

used in the fracking process, (iv) using best 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 Dioxide

Several commenters were concerned that the global warming potential of methane be accurately 

portrayed.

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

Commenters stated that the EPA's failure to use the most up-to-date 20-year GWP 

for methane and accurately account for methane loss creates the dangerously false 

impression that meaningful greenhouse gas reductions can be achieved by simply 
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running (dispatching) gas-fired power plants more and coal-fired plants less - the 

primary emphasis for building block #2 of the rule. Commenters stated that, since 

re-dispatch relies on excess capacity, this is an 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 need for additional new gas-fired 

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

• Commenters 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. Commenters 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. Commenters stated that, regardless of which GWP is used, 

measurements of methane over gas fields suggest that leaks are large enough to 

eliminate any advantage over coal even without inclusion of leaks in pipelines and 

storage facilities. Commenters 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 discrepancies in measurement can be resolved and adequate 

reductions achieved during the time frame of the Clean Power Plan. Commenters

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. 

• Commenters 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." Commenters stated this is misleading because the rule regulates only 

CO2; however methane is 34 times more potent, pound for pound, than carbon 

dioxide as a greenhouse gas over one hundred years and 86 times more potent 

over twenty years--the most critical timeframe for taking action to avoid climate 

catastrophe. Commenters stated climate scientists agree 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 permafrost 

which further accelerates climate change. Commenters stated this makes the 

powerful global warming potential (GWP) of methane over the next two decades 

extremely damaging. Commenters stated the EPA discounts these effects by using 

an outdated GWP for methane, and by focusing its analysis on the hundred year 

timeframe.

• Commenters stated the EPA's failure to use the most up-to-date 20-year GWP for 

methane and accurately account for methane loss 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. Commenters stated that, since 

re-dispatch relies on excess capacity, this is also an inherently temporary measure 

in the face of growing demand; unless fossil fuel alternatives become a much 
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greater portion of the nation's energy portfolio, greater dispatch of existing gasfired facilities will simply hasten the eventual need for additional new gas-fired 

capacity or the eventual need to resume the increased dispatch of coal. 

Commenters stated that, while the rule does not specifically rely on the 

construction of new gas-fired facilities in the development of targets for building 

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. 

Commenters stated these are fundamental problems with the rule as presently 

structured. Commenters 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 greenhouse gas emissions, including 

methane lost to the atmosphere prior to and during combustion.

Time Dependent Impacts

Commenters stated that potentially higher upstream methane emissions and their time dependent 

impacts, as well as the costs of additional climate change mitigation efforts, should be taken into 

account by the EPA. Commenters stated the effectiveness of the EPA's policy formulation 

regarding upstream methane emission is dependent on two important assumptions: 1) an 

expectation of the continuation 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. Commenters stated it is because of these assumptions that, despite the growth of 

natural gas production, the agency expects a net reduction of upstream methane emissions. 

Commenters stated the EPA's calculations simulate a constant level of effort toward voluntary 

reductions into the future, as noted in the Regulatory Impact Analysis published along with 111d, 

but no corrective measures are detailed in case voluntary reductions do not occur. Commenters

stated that potentially higher upstream methane emissions and their time dependent impacts, as 

well as the costs of additional climate change mitigation efforts, should be taken into account 

accordingly. Commenters stated that significant additional upstream emissions reductions are 

required when the time-dependent emissions impacts of methane are recognized.

Commenters 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 decrease 

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 assumptions about upstream 

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.

Commenters 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. Commenters stated that, even if different greenhouse gases are regulated by 
83

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. 

Commenters 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 resultant emissions impact remain constant over time, 

which does not reflect the time-dependent effects of short- versus long-lived greenhouse gases. 

Commenters stated a new set of dynamic metrics captures the impact of emissions timing 

relative to an intended 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. 

Commenters 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. Commenters stated 

that, using the instantaneous climate impact metric (ICI) to assess the CO2-equivalent value of 

methane in the years 2020, 2025 and 2030, estimated emission reductions do not reach the target 

30% reduction of power sector CO2-equivalent emissions by the year 2030 (compared to 2005 

levels). Commenters stated that, based on the ICI, emissions reductions range between 22% and 

18.2% in the near term (2020), compared to the anticipated 27% (2020 compared to 2005), and 

between 20.6% and 7.9% in the long term (2030), compared to the anticipated 30%. Commenters

stated the wide range of estimated emission reductions required is a result of uncertainty 

estimates for methane emissions from natural gas systems and coal mining, published in the 

2013 US GHG Inventory. Commenters stated that higher percentages of emission reductions are 

generated assuming a continuation of historical 2% per year methane emissions reductions from 

natural gas production overall between 2005 and 2012 until the year 2030; and lower percentages 

result from upper bound EPA estimates. Commenters stated these results demonstrate that even 

using lower bound estimates for upstream coal and gas emissions, the projected emissions 

reductions (-16.4%) are roughly half the expected percentage for 2030 (30%), when climate 

stabilization goals are taken into account.

Commenters stated the plausibility of EPA's expectations regarding upstream emissions 

reductions can be assessed by looking at past achievements. Commenters 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. Commenters 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. Commenters stated that, despite these accomplishments, addressing the 

time-dependent effects of GHG emissions will require significantly larger efforts: the closer 

methane is emitted to a target stabilization year, the higher its impact may be. Commenters stated 

that, as a consequence, the margin for allowed methane emissions becomes smaller and smaller 

over time, requiring tighter constraints on emissions despite rising production levels. 

Commenters 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 range 

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. Commenters stated that, even in a scenario with 2% 

annual emissions reductions starting in 2011 (the base year of EPA's calculations), emissions 

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%). 
84

Commenters stated that, while this calculation leads to quantitative targets for reducing upstream 

methane emissions, it is also important to highlight the opportunities to meet these targets. 

Commenters stated that a number of recent studies indicate that not all devices in natural gas 

production and processing contribute equally to upstream emissions, suggesting that knowledge 

of the distribution of upstream emissions across devices and sites can create opportunities for 

regulators to take action. Commenters stated that well-designed regulation might allow for 

significant reductions with limited cost increases. Commenters stated that, in a widely cited 2006 

EPA study of five gas processing plants, less than 1% of devices account for a plant-specific 

range of 30% to 90% of overall emissions, while a 2014 study of well pads in Pennsylvania 

identifies several high-emitting pads responsible for a 4-30% range of regional methane flux. 

Commenters stated that, in a projection of 2018 oil and gas methane emissions by source 

category, a recent ICF International study attributes roughly 40% of methane emissions to only 

five device types. Commenters stated that, comparing direct measurements in different locations 

Allen et al. find significant variability. Commenters 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. Commenters stated that more data on high-emitting devices is needed-heavy tail 

distributions in current samples 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.

• Commenters 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. Commenters stated that private testing shows that 

there are places where it is 20 percent, and L.A.'s is 17 percent. Commenters

stated that leakage from distribution is a problem in cities like Atlanta, and 

Atlanta is not closely monitoring it. 

• Commenters stated that natural gas powered generation would result in a 40 

percent emission reduction, but this could result in methane leakage at any point 

in the process. Commenters noted that the leakage rate is higher than what the 

EPA uses in its formulas. Commenters stated 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. 

Commenters stated that the technology forcing requirements of the CAA should 

be enforced by requiring increases in efficiency at existing natural gas plants. 

• Commenters 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 greater emissions of fugitive methane from the natural gas distribution 

network. 
85

• Commenters 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 use to create electric power. Commenters 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 period. According to the commenters, studies 

indicate that methane leakage at levels above 3% is enough to negate the climate 

benefits of natural gas over coal. Commenters believed that the EPA may be 

proposing in the near future a rule that addresses methane emissions from EGUs 

and other sources, which commenters welcome. Commenters 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. Commenters also stated that concerns have 

been raised about the effects of natural gas extraction on drinking water supplies 

due to the use of fracking. Commenters recommended that the Proposed Rule 

acknowledge the potential dangers of fracking and that states take all precautions 

necessary to protect drinking water supplies from the effects of fracking. 

• Commenters stated the EPA's failure to use independently-produced and peerreviewed data and analyses about natural gas venting and leaks may hide critical 

errors that would preclude designation of natural gas as BSER. Commenters

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 

completely negated, especially if the 20-year warming potential of methane is 

used. Commenters stated it is essential to consider effects on this shorter time 

frame since greenhouse gas accumulations are now creating impacts faster than 

previously estimated. Commenters 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.

• Commenters noted that, in order for these emission reductions to mitigate rising 

atmospheric levels of greenhouse gases, it is also critical that EPA act to reduce 

the methane leakage that occurs during the production and distribution of natural 

gas and during the mining of coal. 

• Commenters stated methane leaks associated with natural gas used in the 

combustion processes for thermal electric power production should be included in 

the accounting for electricity production. Commenters stated that substituting 

natural gas for coal lowers carbon dioxide during combustion, but the leakage rate 

of natural gas during production and transport can far exceed the reduction in 

carbon dioxide equivalents. Commenters stated that natural gas that is supplied 

with certified zero leaks should get the full credit, but all other sources would 

count only the difference between the avoided emissions from not burning coal 

and the actual global warming from burning natural gas including the warming 
86

due to leaks. Commenters stated that, while the leakage of natural gas is a carbon 

intensity continuum, one may think of natural gas with few or no leaks as "low 

carbon natural gas,'' and natural gas produced with large leaks as "high carbon 

natural gas." Commenters stated that, in some cases, the global warming 

associated with "high carbon natural gas" will exceed that of coal combustion. 

Commenters stated that, perhaps coal bed methane leaks associated with coal 

mining should be counted as well in determining the baseline for coal 

consumption. Commenters 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.

• Commenters 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 respect to climate change. Commenters 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. 

Commenters 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. Commenters stated that, when 

the full life-cycle emissions of methane are considered, it becomes clear that 

switching from coal to gas has little climate benefit and could in fact make 

matters worse. Commenters stated that, depending on the extent to which states 

try to comply with the rule's meager targets by switching from coal to gas instead 

of taking useful action like improving the efficiency of existing power plants or 

renewables, carbon dioxide reductions could be substantially masked by the 

climate driving impacts of methane. 

• Commenters stated that natural gas is not a satisfactory "bridge" fuel. 

Commenters stated that methane emissions from the production, processing, and 

transportation of natural gas need to be dramatically reduced. Commenters stated 

that investors should be put on notice now as to when the end of the bridge will be 

reduced. Commenters stated that natural gas may burn more cleanly 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. 

Commenters 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. Commenters stated that the end 

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. Commenters stated that 

investors would otherwise invest more in natural gas plants and will face more 
87

stranded costs than is reasonable. Commenters stated that the sooner we move to 

zero-carbon generation, the better.

• Commenters stated it is clear that a great deal of the natural gas will come from 

fracking and studies show that methane leakage from unconventional drilling, 

such as fracking, is significantly higher than it is from conventional drilling. 

Commenters 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. Commenters stated that, while methane degrades more 

quickly in the atmosphere than carbon dioxide, pound-for-pound it is more 

efficient at trapping heat. Commenters 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 

dioxide over a 100-year time frame. Commenters stated these 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. 

• Commenters noted that, with the recent advances in natural gas extraction 

technologies, environmental concerns have been raised that could erode or negate 

the EPA objectives. Commenters stated natural gas can leak from wellheads, 

valves, tanks, pipes, processing plants, and other parts of the energy supply chain. 

Commenters 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 calculated by EPA. Commenters

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. 

• Commenters expressed concerned that, although natural gas power plants have 

lower carbon emissions than coal, they are not emissions-free. Commenters 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 concern. Commenters 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. 

Commenters expressed concerned that the proposal puts too much stock in natural 

gas as a compliance strategy and should instead shift more focus toward 

renewable generation and energy efficiency measures. 

• Commenters expressed concern about the climate and public health impacts of 

fugitive methane emissions from natural gas production and transport. 

Commenters stated methane is a powerful climate warming pollutant, 87 times 

more powerful than carbon over a 20-year time span. Commenters stated the EPA 

estimates that gas leaks from the oil and gas sector are responsible for 29 percent 

of U.S. methane emissions. Commenters stated the EPA's estimate may be too 

low and fugitive emissions from this sector will significantly increase because of 

the Clean Power Plan. Commenters stated that, if methane leaks are not 
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controlled, the climate gains of moving away from coal-fired power may be 

completely cancelled out. Commenters stated it is not enough to reduce carbon 

emissions; instead greenhouse gas pollution (including methane) must be 

considered as a whole, and targeted accordingly. Commenters 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.

• Commenters 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 processing, transmission, and 

distribution phases of the industry, may cause climate change impacts on a par 

with those of coal combustion. Commenters stated that Building Block 2 has the 

favorable attributes of being objectively determined using current data, 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. Commenters 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. Commenters stated that displaced coal 

should be replaced with renewable energy and energy efficiency (as opposed to 

natural gas) to the greatest extent possible. Commenters 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. 

• Commenters 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 Inventory. Commenters

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 cooccurring compounds such as ethane or isotopic composition of atmospheric 

methane. Commenters 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 recently, 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 Denver-Julesberg Basin have concluded that during gas production 

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 methane leak rates in Utah's Uinta Basin. 

Brandt et al. (2014) systematically reviews eleven top-down and a number of 
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bottom-up studies, including the studies discussed above (with the exception of 

Petron et al (2014), which was not published at the time of Brandt et al's review). 

Brandt et al. demonstrates that for many years top-down studies have very 

consistently shown higher emissions from oil and 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. 

• Commenters stated the EPA has not shown that increased natural gas use by using 

NGCC generation 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. Commenters stated that a 

more careful examination of leakage data using both 20-year and 100-year 

warming potentials is needed to make such a 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 reduction. Commenters stated that, 

in the worst case, it may not reduce CO2 equivalent emissions at all or could even 

exacerbate them somewhat. Commenters suggested that a constraint on 

compliance plans should be that there should be no net increase in natural gas use 

in the power sector; changes in the use of natural gas can be allowed within that 

overall constraint.

• Commenters stated the EPA's estimates of methane emissions from natural gas 

production, processing, transportation, storage and distribution are 

underestimated, which has resulted in a skewed representation of the climate 

benefits of switching from coal to natural gas. Commenters stated there is 

compelling evidence that leakage rates from natural gas operations are far higher 

than EPA emission factors suggest. Commenters stated the EPA currently 

assumes that natural gas systems have a combined upstream and downstream 

leakage rate of 1.8 percent. Commenters stated this was recently reduced from 

2.5% for conventional gas and 3.9% for fracked natural gas (the revision occurred 

after the publication of an industry study that was not subject to peer review). 

Commenters stated that, since that time, the Office of the Inspector General has 

issued a report indicating that EPA must improve its emission factors to better 

reflect direct measurements of methane leakage from natural gas production. 

Commenters stated that, for instance, a recent study using atmospheric 

measurements estimated fossil fuel methane emissions at more than two times 

higher than EPA's emissions factors would indicate. Commenters stated that 

observations from oil and gas operations in Colorado indicate that inventories 

underestimate methane emissions by at least a factor of two. Commenters 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. Commenters stated that a 

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

7.1%.

• Commenters stated there are multiple aspects of natural gas production that may 

result in significant undercounted fugitive methane emissions. Commenters stated 

that one study surveyed methane plumes over Marcellus shale operations in 

Pennsylvania. Commenters 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%. Commenters 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. 

Commenters stated that this study provides another indication that current leakage 

rates are significantly underestimated. Commenters stated that new work also 

suggests that both plugged and unplugged abandoned wells in Pennsylvania 

leaked at much higher rates than reflected by current emission factors. 

Commenters stated that the EPA must revisit its assumptions regarding cradle to 

grave leakage to create a sound scientific basis for the Proposed Rule.

• Commenters stated that another major source of methane emissions from the 

natural gas sector is leaks from pneumatic devices. Commenters stated a recent 

study calculated emission factors for these devices at likely at least twice the 

amount predicted using the emission factors in EPA's official U.S. greenhouse gas 

emissions inventory. Commenters stated that recent reports have also 

substantiated an alarming rate of leaks from 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. Commenters

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. Commenters stated that more than 5,800 leaks were detected 

from aging gas pipelines underneath the streets of Washington, D.C. Commenters

stated the Office of the Inspector General issued a report this year indicating that 

the EPA should work with other agencies to track emissions from distribution 

pipelines, consider future regulation, and update its emissions factors.

• Commenters stated the EPA must use accurate estimates of methane leakage from 

natural gas systems. Commenters stated that vented, fugitive and other methane 

emissions from natural gas undercut the climate benefits of using natural gas to 

produce electricity. Commenters stated the Proposed Rule's analysis assumes a 

methane leakage rate that is contradicted by recent studies to which the EPA does 

not refer and apparently has not taken into account. Commenters stated that 

employing an accurate leakage rate is another crucial component in the analysis of 

the climate impacts of switching from coal to natural gas. Commenters expressed 

concern that, while many of these studies are peer-reviewed and directly on point, 

the EPA does not include them in its references. Commenters stated that the EPA 

cannot cherry-pick the data on which it relies but must take these scientific studies 
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into account. At a minimum, EPA must explain why it dismisses this information. 

Commenters stated that the observational data indicate that much more methane is 

reaching the atmosphere from natural gas production than EPA currently 

estimates. Commenters stated that whether from super-emitters or indicative of 

higher average methane emissions per site, or both, there is a clear underrepresentation 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. 

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

rules must be adopted for capturing fugitive methane and other volatile organic 

compounds from oil and gas operations.

• Commenters stated the most serious failure with the EPA plan is that it shifts 

fossil fuel usage for electric generation primarily to natural gas, while 

simultaneously not dealing with the extraordinary methane emissions from 

production, storage transmission and distribution. Commenters stated that 

commitments have been made by the Administration and EPA to control methane 

and they are looking for that commitment to be realized. 

• Commenters 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 

• Commenters urged the EPA to use the Clean Air Act to address fugitive 

emissions of methane resulting from natural gas development. Commenters stated 

that a clean energy plan under which states 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 measures and renewable energy 

sources, and reduce America's use of all fossil fuels.

• Commenters 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 electricity generation based on combustion emissions only. 

Commenters stated this will lead to poor choices regarding energy production, as 

seen in the rule's own Regulatory Impact Analysis (RIA). Commenters stated that, 

compared to baseline forecasts, the rule would boost the amount of additional 

electricity generation from natural gas by nearly ten times the meager gain 

projected for renewables before 2020. Commenters 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 
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incentive for utilities to reinvest in renewables because the massive capital outlay 

for gas infrastructure will have already occurred. 

• Commenters stated the EPA's projections include extremely optimistic forecasted 

results of voluntary emission reduction programs. Commenters 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 uncertainty. Commenters 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 should use a lifecycle analysis to determine the net 

emissions of methane associated with the CPP.

• Commenters stated that CO2 and methane are lost during the production, 

processing, and transmission of natural gas. Commenters stated that this coupled 

with a consideration of natural gas's lifecycle emissions shows that natural gas is 

not any better than coal from a climate change standpoint. Commenters stated that 

the effect and intent of the proposed rule was to accelerate the use of fracked gas 

and to facilitate the development of gas-fired power plants, which is a problem. 

Commenters 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 lead to bad decisions. 

• Commenters stated that, if one considers the fugitive gas from mining to transport

to storage, natural gas is not any better than coal. Commenters asserted that the 

proposed rule would be improved by less emphasis on natural gas, which is a 

fossil fuel that "emits 50 percent carbon dioxide into the atmosphere" when it is 

burned. Commenters recommended putting more emphasis on energy efficiency 

and green renewable energies to make the rule stronger and provide us with less 

health threats 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. Commenters emphasized that the rule not 

incentivize shifting from natural gas to coal and calling it an emission reduction. 

Commenters said that the rule must not allow states to let polluters buy pollution 

offsets to meet emissions requirements. Commenters cited current cap-and-trade 

programs that allow polluters to pay farmers, foresters, et cetera to reduce their 

emissions and then claim those cuts for themselves.

• Commenters stated that the proposed rule would accelerate the conversion from 

coal to natural gas by only quantifying the smoke stack emissions at generating 

plants and by disregarding the release of methane in the natural gas lifecycle. 
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Commenters said the president's address to natural gas is wrong in many ways, 

and that the president's approach is poisoning us. Commenters stated that there is 

scientific evidence that shows that carbon-based fuel is no better than and 

sometimes worse than the coal industry. Commenters 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. 

Commenters 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 exacerbated climate change and to stifle 

investments and the expansion of renewable and sustainable energy.

• Commenters expressed great concern over practices used to obtain coal, oil, and 

natural gas, and their effects on the environment. Commenters stated that the 

proposed standards fail to consider the process from extraction to combustion, and 

fracking is used an example of this. Commenters stated that methane gas is 

released at drill sites, and byproducts affect the air, soil, aquifers, and streams. 

Commenters also 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. Commenters stated that natural 

gas is a bridge fuel to nowhere. Commenters stated that promoting natural gas to 

deal with climate change is like an alcohol treatment that urges sobriety by asking 

members to switch from vodka and whiskey to beer and wine.

• Commenters 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. Commenters noted four independent

studies which show that lifecycle methane emissions have a global warming 

potential as bad, or worse, than coal. Commenters 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. 

• Commenters objected to the proposed regulations because recent scientific studies 

suggest that current estimates of methane emissions from natural gas extraction 

are too low, Commenters stated the Office of the Inspector General reported that 

"[t]he EPA's existing methane emissions data for distribution pipelines may not be 

valid." Commenters stated the EPA estimates emissions using a bottom-up 

approach, beginning with an inventory of all of the different industry activities 

undertaken in a given year and then uses largely dated estimates of average 

emissions of each activity to arrive at an estimate of total emissions from the oil 

and natural gas systems. Commenters stated this approach relies heavily on 
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voluntary self-reporting from the industry. Commenters stated that 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. Commenters stated that 

scientists 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. Commenters 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. Commenters stated Caulton et al. published a 

study of methane emissions during the drilling stage at well 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. Commenters stated P'tron et al. published a study looking at 

methane emissions in the Denver-Julesberg basin in Colorado over a two-day 

stretch in 2012 using monitoring equipment on 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." 

Commenters stated the EPA needs to conduct a more comprehensive assessment of upstream 

GHG emissions and an examination of emissions from potential changes in upstream emissions 

generated by changes in natural gas and coal production, processing, and transportation activities 

outside of the US. Commenters 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. 

Commenters 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. Commenters stated (1) the EPA 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 from natural gas extraction, 

processing, transportation and distribution systems that are far too low; and (3) the EPA does not 

fully account for the increased methane emissions associated with natural gas extraction through 

fracking and similar unconventional methods. Commenters 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

Commenters 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 rulemaking's effect, and 

adjust the building block targets and their interrelationship according.

Commenters stated they identified six significant technical deficiencies in EPA's analysis of 

methane emissions. Commenters agreed with the IEER comments that EPA has not properly 

reviewed the impacts of methane releases in the fuel cycle and stated six points from IEER are of 

particular concern: 
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• The EPA relies mainly on industry-supplied data for estimating natural-gasrelated methane emissions, especially for emissions from hydraulic fracturing 

operations. EPA also used an earlier joint study it did with the Gas Research 

Institute which included field measurements done in 1992. 

• In the one case where the EPA concluded that a set industry data underestimated 

emissions from completed hydro-fractured wells, the EPA estimated emissions 

using the defective industry data and made another estimate without it; but it 

never used its own, much higher venting estimate. 

• The EPA oil and natural gas technical support 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 

not 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 EPA 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 occur between now and the end of the century, when the 

IPCC analysis indicates that essentially all fossil fuel use needs to be phased out if 

the temperature rise is to be kept below 2 degrees C.

The EPA did not consider the impact of setting a 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 greenhouse gas emissions.

Clarification

Commenters 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. Commenters stated that, under 

Option 1 of the Proposed Rulemaking, coal production is predicted to decrease by between 22 

and 24% in 2020, while natural gas production for the same time frame and option is predicted to 

increase by only 3 or 4%. Commenters 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% 
96

(the two building block approach). Commenters stated that, as to the key question of how much 

additional gas will be produced, the preamble 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. Commenters

stated this point is critical because the RIA's comparison of methane emissions from coal versus 

natural gas assumes 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 units significantly 

decrease greenhouse gas emission reductions. Commenters asked that the EPA clarify which 

values are actually correct. 

Oil and Gas NSPS

Commenters 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. Commenters stated the EPA's assumption that compliance with 

that rulemaking will result in methane emission reductions between 60 to 96% from the targeted 

leakage areas is overly optimistic. Commenters stated that these values are much below those 

established by the direct-observation studies cited by commenters. Commenters stated that the 

EPA assumes no leakage during drilling operations, which is clearly incorrect. Commenters

stated that, although it is not clear from the RIA, fugitive methane emissions from coproducing 

wells presumably are not included even though a number of studies have found significant 

methane leakage from hydraulically fractured, co-producing wells. Commenters stated the 

current NSPS for the oil and gas sector does not require these wells to perform green 

completions. Commenters 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. Commenters 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. Commenters concluded the 

EPA should revise its estimates of the oil and gas NSPS' impact on methane leakage.

Ozone Nonattainment

Commenters stated the EPA should evaluate the increase in emissions caused by the increased 

use of natural gas under the Proposed Rule, including impacts on ozone. Commenters 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. Commenters 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 permitting 

requirements. According to the commenters, this could lead to additional economic burdens and 

additional costs for controls. Commenters stated that the timing for this rulemaking will be 

inappropriate for integrated planning regarding ozone, as discussed further elsewhere in this 

document. 
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Commenters urged the EPA to address emissions of methane, a potent climate pollutant, 

Commenters stated that President Obama committed to taking action on methane as part of the 

Climate Action Plan and it is vital that EPA follow through on this pledge by promptly 

commencing a rulemaking to set standards limiting emissions of dangerous climate and public 

health harming pollutants from new and existing sources in this sector.

Commenters stated an increase in natural gas usage from re-dispatch may increase NOx, VOC 

and methane emissions from upstream oil and gas operations in areas that are at risk for ozone 

nonattainment. Commenters stated that, if these areas become designated as nonattainment, new 

constraints would be necessary regarding production. Commenters stated that all of New 

Mexico's NGCC facilities are located in areas at risk for ozone nonattainment. Commenters

stated that increased usage 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. Commenters stated the timing for this 

rulemaking will be inappropriate for integrated planning regarding ozone.

Comment 23: Commenters 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 Regulatory Impact Analysis of the final 

CPP for the EPA’s response to this comment.

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

Commenters stated the EPA must fully account for emissions from unconventional gas 

extraction methods such as hydraulic fracturing, or fracking, which cause much higher methane 

emissions than conventional methods. Commenters stated that unconventional gas currently 

accounts for about 60% of gas production, and is predicted to increase to 75% by 2035.

Commenters stated that, although large methane emissions are associated with flowback and 

drill-out of hydraulically fractured wells, particularly for gas extraction from shale, the EPA does 

not currently distinguish between conventional and unconventional sources of fugitive and 

vented methane. Commenters stated that, in 2011, when EPA updated its emission factors for 

natural gas production, it did differentiate between conventional and unconventional (shale) gas, 

with values of 1.6% and 3.0%, respectively. Commenters stated that the EPA action in 2013, to 

reduce these emission factors and remove the distinction between 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. Commenters stated that, as detailed in 2011, during the development 

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. Commenters stated these estimates have since been 

corroborated by other studies. Commenters stated, for example, a new study has provided 
98

evidence that another potential difference between conventional and unconventional gas is the 

incidence of impairment and consequent leakage from cement and/or casings of fracked wells; 

the study, which examined public records to construct a database and model of impaired 

structural integrity of wells in Pennsylvania, showed that unconventional wells were two times 

more likely to experience a loss of integrity and increased methane leakage than conventional 

wells. Commenters stated that another study that found methane emissions during the drilling 

phase to be two to three times higher than EPA's emissions factor was conducted at wells subject 

to hydraulic fracturing. Commenters 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:

Commenters 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.

Commenters expressed concern that natural gas extraction is subject to leakage and loss of 

methane during transportation. Commenters 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. Commenters stated that studies 

indicate that methane leakage at levels above 3 percent is enough to negate the climate benefits 

of natural gas over coal. Commenters stated the TEPC understands that EPA may be proposing 

in the near future a rule that addresses methane emissions from EGUs and other sources. 

Commenters 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 natural 

gas sector, and Ohio, which requires natural gas drillers to conduct quarterly inspections to detect 

and fix leaks in their systems. 

Commenters urged the EPA to take action to reduce fugitive methane emissions released during 

the natural gas extraction, transportation and delivery process. Commenters encouraged the EPA 

to engage in updated research to assess the extent of the fugitive emissions problem and begin a 

rulemaking under its CAA authority to control it. Commenters stated the EPA should assign 

responsibility for reducing fugitive discharges to firms across the supply chain. Commenters

stated that failure to control these emissions may seriously undermine the EPA's national climate 

pollution reduction efforts.
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Commenters noted that the EPA is considering fugitive methane regulations for the oil and gas 

sector, and that draft rules may be published soon. Commenters encouraged the EPA to pursue 

strong standards with this rule, and to treat the upcoming proposal as a critical component of the 

Clean Power Plan strategy. Commenters stated the knowledge and technology needed to reduce 

methane leakages is well known and available, and in many cases preventing leaks has financial 

benefits. Commenters 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. Commenters stated 

that some industry leaders are beginning to take action to reduce fugitive methane, but many 

others are failing to make the proper investments; EPA action is therefore necessary to level the 

playing field and ensure all industry players take the needed steps. Commenters stated that, if the 

EPA fails to take strong action on this issue, the Clean Power Plan will not live up to its intended 

promise, regardless of whether states achieve their 2030 carbon emission targets. 

Commenters suggested that the EPA undergo rulemaking in a timely manner in order to address 

the potential dangers from fracking, such as contamination of ground water supplies, stress on 

the availability of water supplies, and management of wastewater. Commenters also expressed 

concerned with air emissions from flares operated at some fracking installations. Commenters

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. Commenters urged the EPA 

to pursue rule-making to address this waste and unnecessary pollution in a timely manner. 

Commenters expressed concern with any potential addition/expansion of pipelines due to the 

increased use and production of natural gas. Commenters 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.

Commenters 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: Commenters stated that, because upstream emissions or impacts are not part of 

the source category sought to be regulated, and the EPA has appropriately not considered those 

impacts in this proposal.

Response 25: See section V.D. of the final rule preamble of the CPP and Chapter 3 of the GHG 

Mitigation Measures TSD for the CPP Final Rule supporting the final CPP for EPA’s response to 

this comment

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

Commenters noted that, as part of the Regulatory 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. Commenters stated that the EPA's consideration of these 

impacts was appropriately limited to an appendix to the chapter of the RIA considering economic 
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and energy impacts. Commenters stated that CAA section 111(d) provides for state plans to 

regulate "any existing source", thus, the EPA cannot include "upstream" emissions in its 

determination of guidelines for state determination of BSER. Commenters stated the affected 

sources in this proposed rule are fossil fuel-fired boilers, IGCC units, and stationary gas-fired 

combustion turbines. Commenters added that, on the specific analysis EPA performed in this 

area, ANGA did not agree with EPA's use of the 2013 Greenhouse Gas ("GHG") Emissions 

Inventory for underlying data in the analysis as opposed to the more recent 2014 GHG Emissions 

Inventory. Commenters encouraged the EPA to rely on the most recent inventory, given the 

significant changes to the inventory over the past five years. Commenters added that they do not 

support the use of the inventory for regulatory purposes and we look forward to continuing to 

work with EPA to update the inventory to more accurately reflect emissions.

3.2.2 Magnitude of generation shifts among existing EGUs

This section discusses specific issues related to the EPA’s building block 2—Generation Shifts 

Among Affected EGUs. Issues are largely related to NGCC units and include historical capacity, 

nameplate capacity, baseline capacity, permit constraints, individual unit limitations and abilities, 

annual average availability, and peak 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 met 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 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 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. 
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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 that 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 these 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 baseline 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 states 

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 permit restrictions on 

NGCC units that limit ramping up operations.

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

of the CPP.

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

Commenters questioned why EPA's analysis didn't account for permit limits on NGCC units 

that limit ramping up operations. If the EPA corrects this error, the commenters questioned if this 

will this change be made prior to finalization and reflected in reduced state goals with adequate 

time for comment.

Comment 3: Some commenters generally supported the EPA's proposal for Building Block 2

with respect to a 70 percent capacity factor.

Response 3: The EPA disagrees with the establishment of a CO2 emission reduction standard 

calculation using less than a 75 percent capacity 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.
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The following are summaries of the specific public comments under this comment:

Commenters stated that the CPP's emission reduction targets reflect an achievable, adequately 

demonstrated and cost-effective system of emission reduction, and that the Proposed Rule has 

appropriately determined that it is feasible and 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 existing 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 

increasing 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-following 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 capacity 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 

modeling 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 climate 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 carbonintensity 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.

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 chapter 3 of the GHG 

Mitigation Measures TSD for the CPP Final Rule.
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The following are summaries of the specific public comments under this comment:

Operating experience 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 significant 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 cases, 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-maintained 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 (greater 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 further 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 at 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. 

NGCC units are more efficient running at a higher capacity.

Commenters stated it is worth noting that LS Power's experience with these units demonstrates 

greater efficiencies can be achieved when operating at even higher and more steady state 

conditions. The commenters further stated these units are quite capable of operating at or near a 
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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 capacity 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 issues 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 the 

price of electricity.

1. Economic or merit order dispatch: Even with today's historically moderate to low natural 

gas pricing, not all NGCCs can compete in all markets based on bidding into competitive 

markets. EPA proposes that states will fix this situation 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 fuel 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 plant 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, 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 

compliance requirements. Commenters stated that some public commentary misconstrues EPA's 

70 percent target utilization as an assumption that every plant is capable of running at 70 percent 

every day of the year, concluding that limits on natural gas supply for power generation during 

peak demand makes it impossible to meet the standard. Commenters stated this conclusion is 

inappropriate and inconsistent with EPA's analysis. The commenters recommended that, in 

evaluating feasibility on a unit by unit capacity utilization, the EPA should continue to use an 

average annual approach, consistent with the rule's compliance requirements. The commenters 
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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. 

Data 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 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. 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 operated 

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 lower 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 of 64 percent or higher, and that 16 states have operated at a monthly utilization factor of 

at least 64 percent.

Commenters stated that forecast analyses suggest 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 Future 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 could 

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 proposed 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 in 

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 and 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).) 
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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 the 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 factor EPA derived in building 

block 2 in the CPP proposal. Commenters stated that the NorthBridge modeling predicts that in 

several states, natural gas combined cycle units 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 percent. 

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 the 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 both 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, Maine, 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 have 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 economics 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. 

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 at 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 
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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 hourly 

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 commenters 

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). Commenters 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 operate 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 in 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 turbine 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 reported 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 estimate of plant level availability of 

87 to 92 percent is generally achievable across the operating fleet. 

NGCC can meet load-following needs at the 70% 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 fully 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 sources. Commenters stated the existing fleet of highly efficient, flexible and 

fast-ramping NGCC facilities can deliver electricity at the assumed 70% utilization rate, while 

operating as load following units, which are often controlled directly by the relevant independent 

system operator ("ISO") and have their output 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-ramping capabilities of the existing 

NGCC fleet, commenters stated there is no inconsistency between the assumed 70% utilization 
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rate and the role NGCC facilities will increasingly play in enabling the integration of intermittent 

renewable generating sources 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, depending 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 exempt 

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 stated 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 energy 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 significant 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 utilized at a rate of just 59 percent in 2012. Commenters concluded that Alabama 

has sufficient underutilized capacity to allow for re-dispatch up to the target rate 70 percent.

Commenters stated that a key related consideration is whether Alabama has sufficient natural gas 

supply. Commenters stated the EPA's analysis 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 allow their NGCC units to achieve 70 
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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 Economics, 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 stated that 

Synapse determined that additional gas infrastructure would not be needed as a result of redispatching 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 existing NGCC capacity and 

sufficient natural gas supplies for re-dispatch to a 70 percent capacity factor, the EPA's 

assumptions for Alabama under Building Block 2 are not unreasonable. Commenters noted that 

Alabama is not bound to pursue natural gas re-dispatch 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 reduction will work for Arkansas, with 

the initial and highest carbon emission reductions coming from increased deployment of natural 

gas through CCGT, combined cycle gas turbines, and a reduction of 30 percent, or 68 percent of 

the target from the state.

Commenters stated that Georgia has both sufficient existing NGCC capacity and sufficient 

natural gas supplies for re-dispatch to a 70 percent capacity factor. Commenters stated that, 

under Building Block 2, EPA assumes that Georgia can reasonably and cost effectively increase 

the dispatch of its natural gas fleet by another 13.8 million MWh, while proportionately 

decreasing its coal generation over a period of 14 years. Commenters stated such a shift is both 

feasible and in line with pronouncements by 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 gas 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 gas 

delivered to consumers during the peak winter month would increase by approximately 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 determined that, while some amount of additional 
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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 performed 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 determined 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 underconstruction 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 underconstruction NGCC capacity in North Carolina and that the three million MWh of re-dispatch to 

under-construction NGCCs would lower North Carolina's target emission rate by an increment of 

126 lbs/MWh. The commenters further asserted that 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 this 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.

Commenters 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 assumed 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 allow for re-dispatch of the state's NGCCs up to the 70 

percent maximum. 

• 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 capacity of the gas pipelines delivering into 

Tennessee is 14,685 MMcf per day. The 70 percent capacity assumption would 
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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 subtracting 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 available, unused natural gas generation that could 

feasibly displace coal-fired generation on a region-by-region basis. Tennessee is 

in the SERC Tennessee Valley subregion. The Synapse analysis indicated that this 

region could exceed EPA's natural gas re-dispatch 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 

Virginia 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 

inflow capacity from the LNG terminal and the 2,175 MMcf per day that flows out of 

Virginia to other markets the average daily amount of pipeline capacity available to 

supply Virginia markets would still be more than two and a half times the peak month gas 

use (~4,000 MMcf per day of capacity vs. ~1,600 MMcf per day of consumption). Thus, 

existing pipeline capacity should be able to accommodate the additional capacity at 

existing natural gas EGUs. In addition, Synapse Energy Economics analyzed the 2012 

U.S. electric dispatch system and evaluated the available, unused natural gas generation 

that could feasibly displace coal-fired generation on a region-by-region basis. Parts of 

Virginia are in three different sub-regions: SRVC, SRTV, and RFCW. The Synapse 

analysis indicated that each of these three regions could exceed EPA's natural gas redispatch target of 70 percent and could, under the assumptions modeled, reach an 80 

percent capacity factor. 

Commenters stated that, based on utility plans and the reasonableness of the assumption as 

applied to Virginia, they included the 70 percent 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. 

Commenters stated that Clean Wisconsin's own analysis of NGCC EGUs in Wisconsin provides 

evidence both that those 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 
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was operating at capacity factors between 45% and 55% in 2012, with an overall system average 

of just under 40%. Commenters stated these capacity factors are significantly higher than those 

of so-called "peaking plants," which have an average capacity factor of less than 10% in the 

Midwest Reliability Organization's territory, according to the EIA suggesting that they could 

easily ramp up in the short-term, even before 2020, without a significant impact on their existing 

operation. Commenters supported the assumption that existing natural gas EGUs could operate at 

a 70 percent capacity factor in Virginia. 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 Doswell), 

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 to 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 referred to an analysis conducted by 

Synapse Energy Economics, Inc. which concluded that in the eGRID subregions that Wisconsin 

is in, there is a combined potential to increase generation from NGCC to 54 TWh assuming an 

80% capacity factor. Commenters stated 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: Commenters 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 units are appropriately 

considered to have a capacity factor of 55 percent. EPA has reviewed comments on this topic 

and is retaining the 55 percent capacity factor 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). Commenters 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 and 

adjusting the capacity factor from 70% to 50-55% provides opportunity for carbon reduction to 

be achieved while maintaining reliability and affordability for CPS Energy customers.
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Commenters questioned EPA's assumption regarding allocation of capacity for "under 

construction" 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 under 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 (versus 55 percent unavailable) that is assumed 

in the draft proposal. Commenters said that EPA has overestimated the amount of generation that 

will be utilized to meet new power demand because many under construction NGCC plants are 

being built to replace retiring 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 California 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 characteristics 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 

preferentially 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 outside 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 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 
114

states may consider local circumstances as they develop their plans, including system reliability, 

fuel diversity, and other regulatory requirements. Peak load and dual fuel units are addressed in 

the preamble of the final CPP. See sections V.A, V.B, V.D, VIII.A, VIII.C and VIII.G of the 

final rule preamble of the CPP and Chapter 3 of the GHG Mitigation Measures TSD for the CPP 

Final Rule supporting the final CPP. 

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

Commenters stated there are constraints on re-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 

reliability 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 seasonal 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 hours 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 during 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-fuelfired alternative.

Commenters stated that the EPA fails to acknowledge that other gas and coal units are needed 

during peak usage periods for reliability purposes, and are often dispatched when every NGCC 

plant is already running at full capacity. 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 do 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).
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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 time load period or winter periods 

when natural gas deliveries are constrained and preferentially routed to residential customers, 

NYISO rules require generators in the NYMA to combust oil in dual fuel units to ensure the 

reliable provision of electricity in the event of an unforeseen contingency on the natural gas 

transmission and delivery system. Commenters stated this requirement and its consequence for 

generation have previously been addressed by the EPA, particularly in its Cross State Air 

Pollution Rule (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 operating constraints that apply to certain generators in New York City and 

Long Island, which are referred to here as the N-1-1 Contingency, the Minimum Oil Burn 

Rules, and local out-of-merit-order dispatch 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 ozoneseason NOx budgets based on comments 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 facility 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: Commenters 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 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 
116

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 ability 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 

federal 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 prices which will provide an 

economic benefit to rate payers in our region.

Commenters agreed that 65% is more feasible than a 70% capacity factor and a lower capacity 

factor would provide greater operational flexibility and infrastructure transition.

Comment 9: Commenters recommended that, where appropriate, the EPA should consider 

capacity factors for NGCC units greater than the 70 percent benchmark identified in the proposal

using average annual capacity.

Response 9: The EPA disagrees with the establishment of a CO2 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 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 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. 
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 proposal, 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 achievement of a certain capacity factor on a unit-by-unit basis - a 

capacity factor in excess of 75 percent at a larger base load plant may facilitate far lesser 

capacity factors at smaller NGCC units relied on for the peaking power, while still averaging a 

fleet-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. Commenters indicated that in the 

RGGI region, there are over 70 affected NGCC plants representing 25,559 MW of nameplate 

capacity.

Comment 10: Commenters requested that states be required to explore even greater dispatch 

targets if they seek lowered compliance targets due to the infeasibility of other building blocks.

Response 10: The EPA disagrees. In response to additional 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 regulatory 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 Measures 

TSD for the CPP Final Rule supporting the final CPP. 

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

Specifically, commenters recommended that, if a state suggests that BSER should be weakened 

for a state due to some particular 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: Commenters 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 performance 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 

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. 

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

Block 2.

Response 12: The EPA 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 existing 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 13: Commenters 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 13: EPA thanks the commenters. 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 redispatch from natural gas-fired, combined-cycle combustion turbines that are under construction 

because the first 55 percent 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 recognize, there are many available 

options for reducing carbon dioxide emissions from existing power plants through modifications 

or upgrades at these plants. Commenters said, an analysis focused on these "onsite" measures 

would by necessity be expansive in scope - including not only significant improvements to the 

efficiency or "heat rate" of the plant, but also other emission reduction measures such as cofiring or re-powering with lower-carbon fuels; utilizing renewable energy sources to provide 

supplemental 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. Commenters 

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 14: Commenters stated that the EPA has not demonstrated that a 65 percent 

utilization rate for NGCCs is achievable.

Response 14: 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. 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 reasonable 

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 considered 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 expansion 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 

percent 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, should 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 stated that, while the EPA notes that 16 

percent of the NGCC plants had utilization rates of 65 percent or higher during 2012 (79 FR 

34866), the EPA has not provided a reasonable basis for its determination that a 65 percent 

utilization rate is achievable.

Comment 15: For Utah, commenters provided analysis of two different capacity factor 

assumptions, 50% and 60%, and suggested the EPA's 70% capacity factor assumption is 

unrealistic.

Response 15: 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. 

The commenters’ 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 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. 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:
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 shrink 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 different 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 emissions 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 largest 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 16: Commenters questioned whether the EPA's assumption that Washington's NGCC 

capacity factor can go from 23% to 40% is reasonable.

Response 16: 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 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 baseload generation, including: 1) meeting peak loads, 2) real-time integration of variable energy 

resources (VERS), and 3) occasionally, to maintain system stability. Commenters stated that 

resources used for these types of purposes generally have a low utilization rate - both in terms of 

number of hours operated and the proportion of generating capacity used when operated.
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Comment 17: Several commenters stated that the 70% average capacity 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 17: 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. 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 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 of the commenters' general statements are summarized 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 costeffective, 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 reliability, 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 

capabilities 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. 
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• Commenters stated that the homogenous energy mix resulting from such explicit 

preference 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 peak 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 electricity 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.

• Commenters 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 the 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. 

• Commenters stated the EPA's proposal suggests that massive re-dispatch of the 

entire electric generation fleet can occur without regard to ownership of the 

facilities. Commenters stated that power generator location is a critical factor for 

electric reliability but is not addressed by EPA's IPM model.

• Commenters stated that the appropriate measure for determining whether existing 

units can be operated at higher utilization rates 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 transmission 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 facilities 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 disparities 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 reliability, and 

consumer cost impacts.

• Commenters asserted that a portion of natural gas plants must be set aside to be 

utilized to regulate real time changes in load 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 resources 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 design, 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 maintenance 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 operation 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 unable 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 lowerutilization 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 seems 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 

limitations, water supply, fuel supply and transmission availability, it is 

irresponsible of EPA to simply "plug'' in a number and believe that operation at 

this capacity is feasible for any of those units. 

• Commenters asserted that existing natural gas infrastructure 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 stated that NGCC units may be limited in their operations by air 

permit conditions and noted that at least one NGCC in Mississippi has a permit 

condition that limits the hours of operation for 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 EPA 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 nature 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 available 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 that, 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 for 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 

operating 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 to 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 requirement 

that establishes a minimum capacity factor from the regulated source. 

• Commenters stated NGCC units vary significantly due to differences in the age of 

units, the varied climates where the NGCC units are located, varying designs an 

design criteria, operation requirements in 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 electric production in 2012 does not justify its use as 
127

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 technical 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 Minnesota 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 reliability 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 opinion 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 well 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 aggregate 70 

percent capacity factor.

• Commenters stated there is no technical or economic evidence that these plants 

can sustain generation at this high level. 

• Commenters stated that some of the NGCC units attain high capacity factors only 

through cyclical 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 factors 

for the short terms as outlined in EPA's TSD's, it is quite unlikely that NGCC's 

can maintain that level in a sustainable fashion. 
128

Some commenters expressed general concerns that 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 analysis, 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 either 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 the 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 associated 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 

unreasonable 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 electric 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 electric 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 includes 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 expectations. 

• Commenters stated the EPA's estimate of the cost of this rule does not include 

costs related to pipeline construction, gas supply, transmission services, storage 

and prices for firm pipeline service. Commenters 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 transmission infrastructure typically operates 

at maximum capacity.

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

relative to new and older units.

Response 18: The EPA disagrees, and believes the data support 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 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 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 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, underconstruction, 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 new, 

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 found that small NGCC units 
130

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

Commenters stated that, while the EPA describes NGCC units as technically 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 that 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 19: 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.

Response 19: 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 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 generation 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 stated 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 acknowledge 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 the 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 in fact, during 2012, with historically low natural gas prices and 

high natural gas consumption from the electricity 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 reliably 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 existing NGCC utilization (GHG Abatement Measures TSD at 

3-9 to 3-10). However, commenters asserted that the EPA fails to note that even after this 

expansion - which was largely a function of historically low natural gas prices in 2012 due to the 

widespread development 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 capacity 

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 capacity 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 Hampshire-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 achievable, 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 a 
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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 outages, 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 EPA 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 cyclical 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. Commenters 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 DOE report which stated that "policies that encourage the 

use of natural gas to substitute for coal in power generation could very well lead to spectacular 

price increases for households and industry." The 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 of 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, for a NG2CP ratio of 1.4. 

According to the commenters, at a ratio of 1.8, the price of natural gas would be at 

$4.28/MMBtu. The commenters further stated that the 1.8 NG2CP ratio has been exceeded for 

19 of the 21 months between November 2012 and July 2014. In February 2014, according to the 

commenters, the cost of natural gas delivered to electric utilities reached $7.01/MMBtu as 
133

compared to coal prices of $2.33/MMBtu, for a ratio of 3.03. In July 2014, the commenters 

reported that the ratio fell back to 2.01. 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 operational 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 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 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 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:

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 operating 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 did 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 demand 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 

the electric system. In some cases, NGCCs operate as base load resources; in 

others, they operate as non-base load resources - such as load following, midmerit or even peaking resources, playing a critical role in providing essential 

ancillary services to balancing areas. 

• Different NGCC plants may operate different 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 

feasibility. 

• 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, economically, 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. Reg. 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). This 

determination cannot be based on "mere speculation or conjecture." Lignite 

Energy Council v. EPA, 198 F.3d 930, 934 (D.C. Cir. 1999) (per curiam). 

• Many of these high-utilization units are likely not representative of the source 

category, given that the EPA excluded a number of them from its calculations of 
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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. 

• Commenters 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, particularly 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 purposes 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 capability 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% operating 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 not the factors that 

caused these units to operate at higher rates than the remaining 90% of the NGCC 

units. 

• Given the small fraction of units that have achieved consistent, or even 

intermittent, operation at 70% of capacity, the NGCC capacity target set in 

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 presumption 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 of 
136

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 higher, 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 representative 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 inability 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 the 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 capacity 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 year. Commenters 

stated that, given that natural gas prices were at historical lows and the summer 

load demands at all-time highs that year, it is 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 baseline year in the EPA's goal 

calculation because 2012 was the year of lowest coal generation utilization rate in 
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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, 

therefore, 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 70 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 levels 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 foolhardy. Commenters stated that, based on common usage in the electric industry, 

this clearly indicates that 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 that 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 significant 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 electric 

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 the 
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importance of analyzing 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 transmission 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 cited 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 their 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 assumption 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 this 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 goals 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 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 
139

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 stated 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. Commenters 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 not have any gas-fired plants, they cannot redispatch. 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 redispatching one for the other is simply impractical. Commenters stated this impacts North 

Dakota because both plants are billed on integrated system costs, which means that North Dakota 

customers get power from the coal plant in South 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 reliant 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 likely 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 anticipated 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 % of 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; in those four months alone, redispatching 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 the 
140

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 electricity load 

can be met by natural gas.

Commenters stated that, since Missouri River Energy Services has no existing NGCC resources, 

the application of building Block 2 is impossible. Commenters stated that Block 2 of the 

proposed rule is based on the flawed assumption 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 that, 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. Commenters stated that MRES (a relatively 

small municipal entity) provides a classic example of a utility that owns only one coal resource 

and no NGCC; further, in the state of Wyoming, 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 capacity factor goal for several 

reasons, such as many NGCC units were not designed for cycling duty, significant upgrades 

would be needed, and unit-specific limitations; 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 

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 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. 
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 others 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 NGCC 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 proposed 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. Commenters 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 Combustion 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 fleet, 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 

influence 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 stated 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 

facilities 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 operate - 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 capacity 
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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 the 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 scheduled 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 evaluation 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 address 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 achieved 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 at 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 and, 

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 failed 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 

consideration 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 stated that, while in some parts of 

the country certain NGCC plants achieve a capacity factor close to the 70 percent capacity factor 
143

used by EPA, many existing NGCC units in the Midwest are considered intermediate resources 

with much lower capacity factors. Commenters stated that achieving this much higher capacity 

factor requires significant capital investment; for Hoosier Energy's Holland Energy Facility, this 

investment is estimated to be $60 million. 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 

nation-wide NGCC fleets. 

Determine capacity on a state-by-state basis.

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

Commenters stated that issues with grid boundaries that run between jurisdictions can also pose 

problems. Commenters stated that, for example, 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, or 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 should 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 increased 

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 criteria 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 several 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 the 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 

minimum, 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 offsetting 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 stated that, if the EPA maintains the approach of 

applying a single capacity factor to all NGCCs on a national basis, then this capacity factor 

should be based on what is achievable in the most constrained state (i.e., the state with the lowest 

historic 3-year 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 facility 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 state. 

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 consideration 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 altitude 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, transmission 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 

existing NGCCs, environmental constraints (such as permit limits due to proximity to nonattainment areas), national security risks, and market limitations.

Need to consider the maintenance outages and the equipment availability factor.
145

Commenters expressed concern 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 periods 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 less 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 historical price of natural 

gas relative to coal has played a significant role in the utilization of both Smith units and Buck; 

they have been dispatched as baseload units because of the recent historically low price of 

natural gas ($0.03-$0.04/kWh) combined with their 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-dispatch. 

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 capabilities. 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 

doesn't meet their minimum load profile and (2) it could result in selling that power 

below generation costs.

Commenters stated the EPA's analysis does not 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-onones," 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 capacity 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 capacity 
146

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, depending 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% capacity 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 commenters’ survey of over 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 obligation 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% capacity factor because 

they were economical and otherwise available to run, this in no way adequately demonstrates 

that a minimum 70% capacity factor threshold could be manifested into a permit condition for 

any or all units that could be sustainably 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 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 

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:
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 overall annual average, and the 

Agency suggested that the current system is able to support national average capacity factors "in 

the mid to high 50's for NGCC for peak" (i.e., 11 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 Abatement 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 that 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. Commenters 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 have 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 some 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

Commenters 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 not 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 unit 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 regional 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 assumption for reaching the capacity 

factor is based on a simplistic view of excess NGCC capacity that assesses an annualized 

capacity factor rather than seasonal load demands. Commenters stated that the EPA needs to 

conduct a more robust evaluation of available 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, 

because 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 outstrip 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 that, on an average annual basis it might seem possible that natural gas-fired 

plants could replace coal-fired generation; however, a more granular look shows that they will 

not be able to do so during peak load months. Commenters provided a Chart showing the 

operating history of two combined cycle plants used by Avista to serve load in 2012. 

Commenters stated that, while the average capacity factor for the two plants was approximately 

fifty percent in 2012, to achieve this level, both operated well above seventy percent in four of 

the 12 months. Commenters stated that, because 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 coalfired 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 carbon 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

Commenters stated the EPA should tailor targets for natural gas based on the actual in-state 

capacity factor to reflect the true capacity factor in the state. Commenters stated the average 

capacity factor (45%) used by EPA for purposes of setting South Carolina's emissions reduction 

target over-estimates the ability of South Carolina utilities to increase the capacity factor at 

existing NGCC units currently on their system. Commenters stated the four NGCC units 

controlled by South Carolina utilities actually performed 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 (NGCC) 

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 factor 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 stated 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 annual 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 recently 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: Commenters 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 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, 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 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 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, only 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 percent. 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. 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 and other regulatory requirements. The 

111(d) final rule does not require every individual NGCC to meet a CO2 emission performance 

rate, but rather the 75 percent capacity factor was used in the calculations to establish a rate. See 

sections V.D, VIII.A, VIII.C and VIII.G of the final rule preamble of the CPP and Chapter 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, require 

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. Commenters stated that the EPA failed to acknowledge that some of 

these units may have permit restrictions that limit the emissions, amount of fuel, or hours of 

operation, making 70% utilization a legal impossibility. Commenters stated there may be 

operational constraints 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 limitations:

• 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 permit 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 capacity 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 Corporation'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 Air 

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 significantly 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 replace 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 local 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 (HGB) 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 nonattainment 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 attainment 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 restrictions 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 could 

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 should 
153

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 constraints 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 ensure 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 reducing 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 

EPA 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 determine 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 percent 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 its 
154

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 

to 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 example 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, as 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 natural 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 would 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. Shafer 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 address 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 should 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 of 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 NGCC 
155

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 contains 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 permit 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 permits they have for their natural gascombined 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. Commenters stated that many NGCCs are 

located in densely populated residential areas and are permitted to operate at such a high level 

only during periods of peak demand. Commenters 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 dramatic increase will most likely not occur and will not therefore "produce the improved 

performance necessary to achieve the goal." 

Comment 26: Commenters stated the EPA did not consider that new NGCC generation must 

meet existing and revised NAAQS.

Response 26: The EPA disagree that analysis of the 111(d) final rule did not consider this. The 

111(d) final rule requires that states develop 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, NAAQS, 

and other regulatory requirements. The 111(d) final rule does not require every individual NGCC 

to meet a CO2 emission performance rate, but rather the 75 percent capacity factor was used in 

the calculations to establish a rate. See sections V.D, VIII.A, VIII.C and VIII.G of the final rule 
156

preamble of the CPP and Chapter 3 of the GHG Mitigation Measures TSD for the CPP Final 

Rule supporting the final CPP. 

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

Commenters expressed 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 significant 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 

impact 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 states 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 that 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 redispatch 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. Commenters 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 noncompliance 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 existing 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 27: Commenters expressed concern that certain actions to achieve the CPP goals may 

trigger NSR.

Response 27: The EPA disagrees. The Rule does not require states to take particular measures 

and provides flexibility, including trading and more time, to states to consider reliability and 

local circumstances, such as other environmental issues and permits. The Building Block 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, 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 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 repermitting 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 transportation 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 40 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 winter's polar 

vortex CWLP's natural gas supplier advised that it had no NG to run the unit and, even if natural 

gas were more abundant, CWLP's use of its Interstate natural gas turbine would be limited by 

rule and permit. Commenters stated that, in the absence 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 the 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 (NAAQS) 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 28: Commenters stated the EPA must consider oil-firing backup.

Response 28: The Rule does not require states to take particular measures and provides 

flexibility, including trading and more time, to states to consider reliability and local 

circumstances, such as backup fuel. The Building Block 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. 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 not 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 capabilities, 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 29: 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 29: 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 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:
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 baseload 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 loadfollowing role will likely be taken up by a combination of coal units operating at reduced loads 

and/or simple cycle peaking units operating at increased capacity factors. Commenters stated that 

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 CPGS (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 redispatch of up to 70% does not result in additional costs to the operators or rate payers, in fact, 

there would be additional costs associated with 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 Creek 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 assumes that South Carolina could obtain as much as 10% of its total 

in-state generation from variable RE resources such as wind and solar, the integration of this 

amount of wind and solar generation would require 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 relatively 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 incompatible 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 renewable 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 this 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 capacity 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 patterns. 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 increasing 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 

respond 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 built 

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 

stated 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 utilization 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 support 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 failure 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 

sufficient 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-fired 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. Commenters 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 planning. 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 electricity. 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 unless they exceed 219,000 MWHrs of operation will remain 

exempt from regulation. This may put further strain on the natural gas delivery system. 
162

Otherwise, logically, backup power will come from a portion of the existing coal fleet that has 

been reduced in capacity factor in favor of natural gas combined cycles. However with careful 

modeling and planning, even at a 70% capacity factor, there can be adequate head room for 

NGCCs to still provide significant backup to renewables depending on demand. 

Flexible capacity 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 stated 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 capacity 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 generating 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, where 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 portfolio 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 units 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 operations. 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 flexibility 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 less 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 

that 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. Commenters stated this demonstrates the 

impracticability and downright hazard of trying to define the best system for operating a complex 

integrated portfolio of resources for the sole 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 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 load following, system balancing, 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. GHG 

Mitigation Measures TSD for the CPP.

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

Some commenters stated that this is further 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 during these periods. 

Commenters asserted that, if EPA ramps the capacity up to 70 percent for their natural gascombined cycle plants, their plants would not be available to serve as backup for intermittent 

renewable resources that do not generate electricity 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 displacement 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 operation.

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 the 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. Commenters 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 adjustments 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 usage 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 many 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 

capacity 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 consistently 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, Building 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 unanticipated 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 subsequently retired or reduced to comply with CO2 and other EPA 

emissions limits.
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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 compromised. 

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 more 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 should 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 the 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 states where BB2 results in zero 

coal generation after re-dispatch, to meet the BB2 goal; those states would still need to offset the 

reductions assumed from the application of BB2 with reductions from other building blocks or 

from non-BSER measures. Commenters stated that it 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 will 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 picture of the 

potential for re-dispatch.

Merchant gas

Commenters stated that this is further complicated by states in which there are significant 

amounts of merchant gas generation, which are used to meet peak demand not only in their home 

states, but also in neighboring states and stated that it is inaccurate 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 during 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 though 
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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 recognize that while large amounts 

of merchant owned generation are located in Arizona, much of the NGCC generation is delivered 

to California. Commenters stated that, in Arizona, this represents approximately 50 percent of 

the NGCC capacity in 2012 that the EPA assumed 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 achieve 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 

generation at a potential premium cost compared to its owned and potentially lower cost assets 

that would have to be idled? How should the utility commission treat the utility-owned assets 

that would be stranded by the offset? 

Commenters explained that, while NGCC units owned 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 lack 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 not have coalfired 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 available 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 merchant 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 Arizona 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 demand 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 two 

pipelines that provide service to SRP's gas plants have limited excess capacity available and are 
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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 SRP.

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 availability, 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 redispatching 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-fired 

combined cycle EGUs in northern Nevada are already operating at peak for 494 hours in the 

summer and autumn months and would not be available to displace existing coal-fired EGUs. 

Commenters stated that, if we were to assume that existing NGCC EGUs could 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 designed 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 are higher in cost, when compared to a modern combined cycle plant. 

Commenters stated that the Nevada Agencies express concern about "a large re-dispatch from 

coal to natural gas," and asserted that this is an issue which is unlikely to materialize given the 

multiple strategies available to Nevada to comply 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, nor does the assessment address the 
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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 by 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 experiences 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 generation peaked in the month of July at roughly 70 percent 

capacity, during the January 2013 cold snap natural gas use for heating purposes interfered with 

the natural gas supply available to EGU's for power generation and the monthly capacity factor 

was only about 35 percent. Commenters stated this 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 over 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 Arizona.

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 infrastructure 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 Arizona are large, complex units not designed and 

engineered to sit idle for extended periods of time and cycle. Comment stated that such practices 

would challenge reliable operation of the units and the staffing and maintenance to support such 

a scenario would not be economically justifiable. 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 generating 4,098 
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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% capacity factor). Commenters stated 

that nearly half of the time during August 2012 the demand that would normally be provided by 

coal and gas steam-fired generation exceeds the capacity of all NGCC in Arizona. Commenters 

stated the same phenomenon occurs during the months of May through October and, as a result, 

if all coal units were retired as modeled by the 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 obligation 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 demand 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 during 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. Commenters 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 provided 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. Commenters 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-required 
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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, assuming 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 

still 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.

• Commenters 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 generation 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 34887), at least in Arizona it does not appear that this would be 

possible. Commenters stated the projected depth and liquidity of the energy market in the 

southwestern United States is probably not sufficient to implement Building Block 2, nor is 

sufficient transmission infrastructure available to move the energy to where it is needed from the 

NGCC units that suddenly find themselves supplying power to meet far-away demand that was 

formerly served by coal-fired EGUs. Commenters stated that, to the extent that NGCC capacity 

is not already accounted for by out-of-state demand, the Arizona-based utilities with ownership 

or rights in these units will likely use their rights to that unused NGCC capacity in order to 

replace their own displaced coal-fired generation-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, according to the commenters, illustrates the various faults in EPA's methodology for 

Building Block 2. 
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• 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 utilized 

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 Interim 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 load 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 during 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 summer 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 permitting 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 Mitigation Measures 

TSD for the CPP Final Rule supporting the final CPP.

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

Commenters did not agree that the CO2 emission rate of the re-dispatched NGCC units will be 

equal to their 2012 emission rate due to duct 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 significantly higher 
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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 redispatched NGCCs in calculating state goals, EPA consider the fact that re-dispatched NGCCs 

operating under the assumptions in Building Block 2 will likely operate with increased duct 

firing - thus at a higher emission rate - than they did in 2012.

Commenters stated that duct burner firing should not be considered in assessment of NGCC 

capacity within the context of displacing 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 cycle does not derive maximum thermal efficacy. Commenters indicated that 

continual duty with duct burner firing is therefore rare and may not be economic. Commenters 

added that the use of duct burners can induce thermal stress in a unit's heat recovery steam 

generator (HRSG) and this accelerated component wear is incurred only in exchange for 

premium power prices. Consequently, Commenters believed that duct burners should be 

considered temporary operating modes and the incremental power derived should not be 

considered in any discussion of either gross or net capacity that can displace coal on an annual 

basis. Commenters stated that the additional power output and compromise in heat rate induced 

by duct burner firing can be significant, and gave the example of Oglethorpe Power's Thomas. A. 

Smith facility which has approximately 240 MW of 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 this one facility was therefore overstated by over 20% 

by including the duct burner capacity, and that the heat rate for these duct burners is 

approximately 2,000 Btu/kWh higher than the net heat rate for this facility operating at steady 

state conditions. According to the commenters, the desire by an owner to retain duct burner 

augmentation as a temporary mode is due to both a compromise in heat rate and the deferred cost 

of induced thermal stresses to the HRSG.

Commenters stated that, while NGCCs are equipped 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 particularly 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 for these 

impacts by setting less stringent targets. 

Commenters stated the EPA could also consider simply excluding NGCC units located in nonattainment areas or, alternately, assuming additional costs for installing NOx control equipment.

Commenters stated 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 premium power prices. 
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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 20%. 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 than 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 with 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 poorer 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). Commenters 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 32: Commenters stated the EPA fails to consider a specific category of natural gas 

electric generating facility “regulating units.”

Response 32: The EPA disagrees. The EPA has not ignored the role of simple cycle CT units in 

contributing to regulation. Many different types 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 change 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 nondispatchable, it is very difficult for a regulating unit to predict when it may need to operate to 

balance drops in wind generation. In response to 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-
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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 percent 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 fulfill 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 Energy Future and to many 

states' Renewable Portfolio Standards.

Comment 33: Commenters did not agree with the Proposal's treatment of CHP and/or retiring 

NGCC units.

Response 33: 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 permit 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 specific 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 

EGUs. The commenters explained that EPA presumes a state can and should re-dispatch from 

steam generating units (including those using CHP) to existing natural gas combined cycle 

facilities, even if those facilities do not use CHP. However, according to the commenters CHP is 

often installed for the host's industrial process 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 both the facility and at the NGCC facility, and 

therefore increase emissions overall. In conclusion, the commenters requested that Building 

Block 2 not assume re-dispatch from CHP to NGCC and that EPA not consider efficient CHP 

facilities affected EGUs to begin with.

Commenters stated the EPA improperly included 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 in 
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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 so 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 includes 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 unless 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 power 

plant exclusively dedicated to serving load and the needs of the grid in the following ways: CHP 

plants tend to have much higher capacity factors than EGUs, their electric output is directly 

related to their on-site industrial activity and heat (or steam) 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 stated 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 Company 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 combined 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 municipality 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 design 
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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 variations 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 cycle 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 Act 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 purposes at a constant, 

defined rate, incremental re-dispatch of particular CHP units is generally not possible; therefore, 

these facilities are not subject to typical dispatch decision-making. Commenters stated that 

highly efficient steam CHP systems may have 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 Syracuse 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 than a decrease. Commenters stated that, for many CHP facilities, a reduction in electric 

generation will not reduce the facility's emissions. Commenters stated this is particularly true for 

those units that primarily combust fossil fuel to produce useful steam-such as for industrial or 

district heating purposes. Commenters stated that, in such a case, reduction in electric generation 

will result in the same or similar amounts of 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, commenters 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: 
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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 calculate 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 units 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 redispatch will result in wasted useful steam, excessive fossil fuel combustion, increased 

emissions, and 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 four 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 as 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 and 
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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 new 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 generation 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 Greenhouse 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 subject 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 CHP 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 decided to regulate a CHP unit as only a NGCC electric generator. Commenters 

stated that, applying consistent reasoning in this proposal for existing units is prudent and EPA 

should exclude any mathematical adjustment for Useful Thermal Output (UTO) when 

establishing statewide emissions intensity for NGCC units.

Commenters asserted that the EPA should exclude CHP facilities from the Building Block 2 

calculations for NGCC. Commenters stated that major differences exist between the purpose, 

design, fuel flexibility and operating philosophy 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 economically 

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 equipment." 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 equivalent 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:
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• "Co-generation units are capable of providing both electric energy output and 

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 related 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" component 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 and 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 1,132 lb./MWh to 

602 lb./MWh - a rate that is not remotely close to have been demonstrated by any 

NGCC unit. In turn, the average NGCC CO2 emission 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 evaluated 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 to 

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 construction 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 emissions 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 

coal-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 Building Block 2 prior to their 

committed shutdown or conversion date.
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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 their states. 

Commenters stated that it should be unnecessary for a state to establish a goal or plans to achieve 

a goal that grows out of emissions from an affected facility that is already scheduled to close 

prior to the first interim compliance period in 2022. 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: Commenters suggested the EPA establish an exemption for EGUs that burn over 

75 percent coal refuse on an annual basis".

Response 34: The EPA has determined that coal refuse facilities are covered units under the 

111(d) final rule. See sections V.D, VIII.A, VIII.C and VIII.G of the final rule preamble of the 

CPP and Chapter 3 of the GHG Mitigation Measures 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, including 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" based 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. 

Commenters stated that failure to account for these practical implications will put citizens at 
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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 shortages 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 Pollutants 

(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 establishment 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 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 other regulatory 

requirements. EPA does not believe that achievement of the final rule requirements will result in 

over-construction of new generation. See sections V.D, VIII.A, VIII.C and VIII.G of the final 

rule preamble of the CPP and Chapter 3 of the GHG 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 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 programs 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 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 utilization is in place or to increase 

the use of other compliance strategies. Second, we recommend that 2012 generation from 
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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 ramp rate, Clean Energy Group members are concerned 

that EPA's proposed methodology for calculating the NGCC contribution to the interim goals 

would reduce the flexibility EPA intended to 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 their 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 goals 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 the 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 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. 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, Commenters stated the 

EPA could start increasing NGCC from 2012 levels in 2017 to the 70 percent target in 2029; 

alternatively, the EPA could consider reaching the 70 percent level in 2025. Commenters 

expected that EPA would arrive at a ramping rate 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 serve 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; however, 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 EPA'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, commenters recommended that EPA preserve at least 10 percent to 12 

percent of coal steam generation in calculating the state goals. Commenters stated these lower 

capacity factor units tend to be used for peak 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-dispatch 
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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 computation. 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. Similar 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 prices. 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 fuel-fired steam 

EGUs in 12 states. Commenters stated that capacity factors from coal- and oil/gas-fired EGUs in 

certain parts of the country have dropped significantly over recent years and, New England has 

become increasingly dependent on natural gas-fired power since many coal plants have shut 

down in the region. Commenters stated this shift in generation resources has led to reliability 

challenges to the region and, in response ISO-NE created the Strategic Planning Initiative (SPI) 

in 2010 to address issues arising from being highly reliant on natural gas especially in this highly 

natural gas delivery constrained area. Commenters stated the importance of baseload and 

intermediate load generation fuel diversity for reliability purposes was observed in January 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 snap 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 that the implementation of the proposal will create 

a greater reliance on natural gas-fired generation which requires pipeline expansion to meet 

demand, especially during the peak winter heating season. Commenters stated that, based on 

their experience in this 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 dispatch 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 around 
185

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: Simple cycle combustion turbines are not included in state goals, and may not be 

used to adjust a rate. 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. 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 Final Rule supporting the 

final CPP.

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

Commenters supported the Agency's decision not to 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 MMBtu/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 

calculations 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 promotes 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 technically 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 incorrectly 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 38: 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 units has multiple 

benefits and should be encouraged and incentivized under the proposal. Commenters stated that, 

not only would utilization of such converted units take advantage of existing infrastructure 

(similar to underutilized NGCC units), such conversion 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 stated 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 to 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) the 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 toxic 
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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 execute 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 construction and units that have not 

completed construction by the date of the adoption of the final rule should meet the new power 

plant NSPS.

Comment 39: Commenters recommended various approaches to 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 39: The EPA has finalized this rule and is not including new NGCC units. See section 

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 capacity 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 requested 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 now 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 existing coal-fired plants to cofire 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 equity 
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across states, and ensure that the effectiveness of EPA's proposal is not diluted by the 

construction of new NGCC plants. 

Address units that came on line during, and were 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 capacity 

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 these units in its determination of 

BSER and in calculating the state goals. Commenters stated the EPA has no basis to assume 

what generating capacity will be available for re-dispatch from NGCC units that had no 

operating history during or prior to the 2012 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 begin 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 appropriately 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 utilization 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 state 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 units 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 factor for North Carolina NGCC plants for 2012. Commenters stated that 

two of the units included in EPA's list of existing NGCC plants (H.F. Lee and Dan River) had de 

minimis generation in calendar year 2012 and were, in fact, under construction until very late in 
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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 IOU-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 Carolina 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%. Commenters 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, in 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 utility 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 

calculations 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 concern 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 

addressed in order to establish an accurate and more technically sound state goal for North 

Carolina.

Do not agree with the 55% capacity assumption.
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Commenters stated 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 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 circumstances 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 Power Plan. Commenters stated that the EPA's assumption that these units will run at only 

55 percent capacity factor therefore significantly overestimates the contribution that these units 

can have in displacing CO2 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 

assumed 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 assuming 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 capacity 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 circumstances 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 undergoing 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 levels in order for the Proposed Rule to accurately capture the status quo; as a result, 

Turk's 2013 generation and emissions values (where it operated as a baseload unit for 365 days) 

should be substituted in lieu of Turk's 2012 values. 
191

Commenters stated that the EPA was not consistent 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 

construction 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 goals, 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 Utah-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 31, 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 commissioned 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 considered), 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 believed 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 or 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 stated 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 in 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 asserted that the EPA must revise these 
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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 constructed, and that to the extent that these "potential" projects come to fruition, they would 

be subject to the new source standards under 111(b), not the existing source 111(d) guidelines. 

Commenters asserted that these "potential" units should not be considered 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 Dresden 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. Commenters 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 rates 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 facilities that commenters allege are 

not actual projects. 

Commenters asserted that the EPA must correct what commenters believe are errors in both the 

scope of "under construction" units considered and the assumptions for consistently estimating 

emissions from these units.

Commenters also stated that the EPA fails to 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 of 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 that 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 capacity factor, which produces an artificially high amount of NGCC redispatch, 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 2012 

(Dresden was commissioned 01/31/12 per Appalachian Power Company filing to the VaSCC on 

03/20/12; Fremont was commissioned on 01/20/12 per AMP, Inc. filing to the Ohio Power Siting 

Board on 02/23/12.), and provided a table comparing baseline capacity factors for these two 

facilities if calculated based on their in-service date versus the EPA's assumption that they were 

available for the entire year. 

Commenters asserted that if units commissioned during 2012 remain in the calculation of the 

"existing" category of units, then the potential re-dispatch for the existing NGCC fleet should be 

derived based on the historic capacity factor, not on the EPA approach of using historic 

generation. Commenters suggested a method of 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 

throughout the comments, would reduce the amount of NGCC re-dispatch calculated for Ohio 

from 5,793,981 to 439,452 MWh - a 92% reduction 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 - even 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 associated "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, commenters 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 rates 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 

calculate a 12-month rolling average, the basis for determining a standard of performance". 

Commenters asserted that the EPA should apply this same rationale and exclude units 

commissioned in 2012 from the calculation of existing NGCC units to be re-dispatched, and that 

these units could then be separately included in the "under construction" category of units within 
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building block 2 calculation. Commenters asserted that at a minimum, the EPA must at least 

revise the state goal calculations to properly account for the date that new units were 

commissioned in 2012.

Comment 40: Under Construction Unit (Deer Creek Station, SD)

Response 40: The EPA has decided not to finalize the relevant provision of the rule.

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 additional 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 not 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 startup 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 

method 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 additional 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 just 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 Deer 
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Creek Station does not have sufficient excess capacity to supplant such a significant 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 replace the energy. 

Commenters 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 and the continued viability of one of their 

primary sources of baseload electric energy should not be jeopardized by a flawed technical 

premise that EPA could rectify without affecting 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 emissions standards set under Section 111(d) must, by statutory 

requirement, take into account the remaining useful life of the unit in question [section 

111(d)(1)(B)] and that the EPA could prevent 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 that 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 NGCC 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 under 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. Commenters 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 Dakota's only coal-fired plant, Big Stone, is located in a 

different RTO, has an entirely separate ownership, and serves entirely different customers than 

Deer Creek Station, any form of re-dispatch from 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 exist.

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 

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, 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 these 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 

Marchetti, and APS incorporates his report and UARG's comments on this issue.

Commenters stated that data available in the docket suggest that a substantial number of NGCC 

units used in EPA's calculations would be excluded under Building Block 2 because they do not 

meet these required criteria for inclusion in 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 considered 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 turbine 
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that, inter alia, has a base load rating greater than 73 MW (250 MMBtu/h) and was constructed 

for the purpose of supplying, 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 

on 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 EPA 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 42: Commenters 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 specific public comments under this comment:

Commenters stated that, if Indiana elects to impose direct limits on the operating profile of 

higher-emitting EGUs, the EPA expects NGCC plants 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 intrinsic 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 43: Recommend Allowing Credit for Conversion from Liquid Fuel to Natural Gas.

Response 43: 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, 
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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 measure 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 excluded 

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. Commenters stated that, in 2012, 

the North Pole combined cycle unit produced 423,592 MWh of energy and emitted 222,586.3 

tons of carbon dioxide according to the EPA, which equates to an emission rate of 1,158.5 

pounds/MWh. Commenters stated that, according to 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 2012 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 producing 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 credit for that expenditure under 

the Proposed Rule. 

Comment 44: Commenters 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 44: 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 is 
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utilizing existing natural gas peaking units (OCGT). Commenters stated that, under this 

approach, an existing OCGT would be converted to a combined cycle natural gas (CCGT) 

providing a lower carbon dioxide emitting source 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 modified 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.

Comment 45: Building A number of commenters stated that the EPA should not have used 

nameplate capacity in calculating the capacity factor in Block 2.

Response 45: The EPA agrees and has modified the calculations in Building Block 2 to use net 

capability rather than nameplate capacity. See 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 measure 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, including 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 

maximum 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. Commenters 

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.
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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 that 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 block one assumption of 6 

percent. Commenters stated the EPA has failed even to acknowledge the implications of its use 

of nameplate capacity rather than net capacity, despite the fact that an accurate assessment of the 

existing NGCC capacity actually available 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 of 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 Arkansas 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, which 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 rates 
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over 100% in order 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 878 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 that in order to support the levels of redispatch 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- inflated 

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 generation; 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 statewide 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 inappropriately 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 estimates 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 units 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 requirements, or site-specific conditions 

such as ambient temperature, humidity or elevation, all of which can influence the 
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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 

by 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 turbines, 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 generate 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 should 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 calculating the 

emissions impact of building block two. Commenters stated the average of the 

summer and winter reliability capacity ratings for South Carolina's NGCC units is 
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15.7% lower than nameplate ratings, which results in a 2012 NGCC capacity 

factor of 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 staggering 35,054,309 

MWH. Commenters stated that the consequence of this difference is that, in 

Florida, NGCC units would have to operate at an 86.8 percent capacity factor 

based on their true availability represented by actual summer net capacity, to meet 

energy needs. Commenters cited the Marchetti Report and stated that, to support 

the levels of re-dispatch assumed in the Proposed Rule's state goals, NGCC units 

in much of the nation would have to operate at capacity factors far higher than 70 

percent: in Arkansas, units would have to run at 83.9%; in North Carolina, 80.9%; 

and in Texas, 80.1%. Commenters concluded that the use of nameplate capacity 

significantly distorts the actual generation that 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 unavailable across the affected 

NGCC fleet. Commenters noted that the EPA states in its GHG Abatement Measures TSD that 

it used nameplate capacity instead of net capacity because hour/minute net capacity data are not 

reported, but stated that this is not justification for the EPA to have calculated capacity factors as 

it did. Commenters noted that net summer and winter capacity data are reported in EIA Form 

860 for the vast majority of NGCC units, and the 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 EPA actually compares the nameplate and summer capacities for each existing electric 

generation source in the Regulatory Impact Analysis for the proposed rule, and that on a national 

basis for units combusting natural gas the summer capacity is 13% less than 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 electricity 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 recognition 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 potential for 

greater operation.
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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 calculation 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 differed 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 EPA 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 will 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, net 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 capacity 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 capacity, 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 summer and winter capacity ratings when determining reserve margins for 

planning purposes.
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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 data 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 Pennsylvania 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 tighten 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 calculations. 

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 46: Commenters expressed concerns regarding availability and capacity factors.

Response 46: The EPA disagrees 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 substantial 
206

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 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 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 availability and capacity factor. 

Commenters stated that annual availability is "the percentage of time that a generating unit is 

available to provide electricity to the grid." Commenters stated annual availability can also be 

characterized as the "total number of hours 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, transmission 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 combustion turbines 

(CTs) in its Base Case v.5.13 is 85 to 93 percent; however, capacity factors for these units are 

significantly lower due to the operational 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 for 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 data 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) information, 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 

given 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, by statistics on the average 
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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 to the grid, and is an indicator of the reliability of the unit and associated outage 

rates and, in terms of assessing the potential for increased utilization of the NGCC fleet, the 

availability factor is of trivial value. The commenters stated the fact that a unit is available does 

not automatically imply that it can generate all of its demonstrated capacity; for example, a 

hydroelectric unit or wind turbine facility may be available, but water levels or wind conditions 

may be insufficient for those units to achieve 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 

available; 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 in a vacuum is insufficient for 

evaluating the potential increased utilization that may be achievable by a unit. Commenters noted 

a table from NERC which summarizes the availability factor and net capacity factor from 2009-

2013 for various generation resources and stated 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 

that 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 redispatched 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 47: Commenters stated that, for areas that have high integration 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 47: 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. 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 
208

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 that studies by MISO, ERCOT, and the NREL demonstrate 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 stated 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 48: Commenters recommended allowing states to use multiple, representative data 

years, rather than 2012.

Response 48: The EPA generally disagrees. See section VI.D. of the final rule preamble of the 

CPP for EPA’s response to this comment.

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

Commenters stated that the 2012 data year, or any 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 operating during the base 

year of 2012? Commenters stated that instances such as this need to be reflected in the baseline 

data.

Commenters stated that the EPA improperly calculated the number of hours in Building Block 2 

and should correct its calculations. Commenters 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 2012 
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(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 could amount to several hundred thousand 

MWh. Commenters gave the example of Texas, in which the amount of NGCC generation 

calculated at 70 percent capacity factor over 8,784 hours is 230,875,142 MWh while at 8,760 it 

could be 201,331,956 MWh. Commenters stated that 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 states to use multiple years in setting baseline requirements as a solution for this 

issue.

Comment 49: Commenters stated that the EPA should calculate the CO2 emission impacts 

resulting from increased dispatch to existing NGCC power plants using different values than 

those proposed: no more stringent than a NSPS rate; equivalent to the EPA's proposed standards 

for new, modified or reconstructed units; multi-year; state-specific; incremental, or unit-specific.

Response 49: The EPA disagrees. We believe the 111(d) final rule clarifies the treatment of 

NGCC units. In response to additional analysis and many comments, we have modified the 

proposal and RIA – the establishment of CO2 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 

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:

No more 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 the development of BSER, EPA's calculations utilize the 2012 actual 

emission rate for all existing NGCCs re-dispatched to a 70% capacity factor, which results in a 

national-average emission rate for these units of 865 lb CO2/MWh. Commenters stated this 

average 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 same 
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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 NGCC 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 should 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 future years will be consistent with the single, baseline year. Commenters 

stated this assumption is not necessarily true for at least a couple of reasons: (1) equipment wears 

over time and efficiencies are lost over the life of the equipment and (2) the single 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, carbon emission rates will creep higher. 

Commenters stated the EPA recognized that equipment wears over time when it proposed the 

carbon emission rate standards for new NGCC units. In that proposal, commenters stated the 

EPA states "These values represent the emission 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 emissions in the goal setting formula for Building Block 2, for most states, this average 

NGCC emission rate is below the proposed standards for natural gas-fired stationary combustion 

units that EPA is requiring for new or modified and reconstructed sources under section 111(b). 

Commenters stated the unreasonable and unrepresentative state average emission rates cause 

state goals to be more stringent than what would be required if EPA's proposed standards for 

new or modified and reconstructed sources were used in the goal setting calculation. 

Commenters 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 the 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 operated 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, which 
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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 generation.

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 existing 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 base 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 emission 

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 significantly 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 operating 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 characteristics 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 decisions, 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 

recently 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 an 
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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 950-1,100 lbs/MWh.

Commenters stated that the EPA's unreasonable goals for Arizona represent an emissions rate for 

existing natural gas that is much lower than what 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 by the year 2020, let alone 791 lbs/MWh by 2030. Commenters stated the current rate 

of CO2 emissions at Gibbons Creek is over 2200 lbs. per megawatt-hour (MWh). Commenters 

stated a complete conversion of Gibbons Creek from coal-fired to gas-fired generation would 

reduce CO2 emissions to approximately 1,220 lbs/MWh. 

Incremental emission rate.

Commenters stated that, instead of using the 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 redispatch. Commenters explained that most of the most efficient, lowest emitting units are already 

generating at or near the basis 70 percent capacity factor, whereas the units that would actually 

be re-dispatched and contribute the most increase in net generation are the less efficient, higheremitting 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 

appropriately 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 redispatch 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 generator, 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 operating 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 average 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 units 

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 as 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 suggests 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 re-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 NGCC generator, calculate the annual CO2 

emissions increase (or decrease) by multiplying the baseline year limited CO2 

emission rate by the number of annual net MWh 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 available. 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 stated this means that, should the EPA require them to operate more by redispatching to these under-utilized existing NGCC, the average emissions rate would necessarily 

increase. Commenters noted the table uses operating hours reported through Clean Air Markets 

Database (CAMD) to calculate availability (with 8,784 total hours in calendar year 2012) and the 

emission rate values are referenced from EPA's calculations (20140602tsd-plant-level-date-unitlevel-inventory_0.xls). Commenters stated this is not a unique 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", 
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this means that those NGCC with 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 challenge 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, in 

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 appears that the EPA made no such 

attempt, and took a snapshot of actual annual data as appropriate for re-defining potential 

emissions from an entire power generation sector. Commenters stated the EPA must consider 

whether or not the units relied upon represented 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 stated 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 emissions 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 construction 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 used for coal units.

Comment 50: Commenters addressed provisions in the CPP related to emission rates and useful 

thermal output (UTO).

Response 50: The EPA generally agrees and has modified the 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 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 commenters, the CO2 emission rates for 82 other NGCC units were calculated 

using the UTO-related energy 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 EPA 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 multiple cogeneration units that may have much more significant impact. As an example, commenters stated 

that the EPA identified 14 co-generation facilities in Texas whose CO2 emission decreased on 
215

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 overestimated the UTO available from these units for re-dispatching as electricity generation. . 

Commenters 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. Commenters 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 identified 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 newer than the others have emission rates approximately 20% higher in some 

cases. Commenters stated this is not representative of real emission rates should the cogeneration 

facilities be re-dispatched for higher electric 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 rates. 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 additional electric 

generation from cogeneration facilities it must do so at an adjusted heat rate which reflects the 

unit's efficiency for primarily electric generation, as EPA's re-dispatching does not define 

demand for steam (where the cogeneration facilities are able to improve heat rate). Commenters 

stated the EPA actually included a state goal 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 useful 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. Commenters 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 states, 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 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:

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 capacity 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 mechanisms (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 reliable, costcompetitive electricity to its consumers. Commenters stated the EPA's analysis of NGCC redispatch opportunity under Building Block 2 ignores the fact that New Hampshire has already 
217

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 Hampshire 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 

decade 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 between 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 Building 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 Building 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 EPA 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 stated that this has resulted in a 

disparity in state goals between states. Commenters stated that, because the current proposal 

might allow a state to count new NGCC capacity towards compliance with its state goal, 

omitting such potential in the goal computation 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 State 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 limited coal
218

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-utilized 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 gasfired 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 (1,284 lbs/MWh) 

lower than the national average (1,442 lbs/MWh), is, as proposed, required to reduce emissions 

by a level greater than the national average (38% 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 

electricity 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 coalfired units are unfairly penalized. Commenters stated that states that rely primarily or almost 

exclusively on coal, and do not have NGCC capacity, are not asked to re-dispatch and therefore 

are not asked to reduce their CO2 emissions under Block 2. Commenters asserted that a state that 

has significantly increased NGCC capacity, is forced 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. Commenters 
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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) and 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, in Texas's utilization of coal fired electricity, 

which is more than the total coal generation in all but six other states. Commenters believed that 

the EPA's methodology inappropriately discriminates against Texas because of the existing base 

of natural gas fired generation capacity, noting 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-specific comments

Commenters stated that the EPA noted an average 24.5% capacity factor for Minnesota existing 

NGCC units in 2012, a year that they reported experienced unprecedented low natural gas prices 

that would not be commercially expected in the future. 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 disproportionately 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, resulting 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, because 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 stated 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 in 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 means 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 asserted that other states that have better 
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gas pipeline capacity but no existing NGCC do not have their state goal affected by the redispatch of their coal units to natural gas. Commenters stated that the failure of this proposed 

rule to capture and account 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. Commenters 

concluded that the Clean Power Plan results in the inequitable treatment of South Carolina and 

other states as the national goal is derived from an inconsistent methodology. 

Commenters asserted the EPA's Proposed Rule fails to consider that the regions 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 natural 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 discriminatory.

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 Texas. Commenters stated this 

reduction is greater than any other state and only North Carolina's (33 percent) and Michigan's 

(23 percent) reductions are even close to Texas'. Commenters noted that states like Kentucky (1 

percent) and Indiana (5 percent) experience 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 in 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 

neighboring 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 believed 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 underlie 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 52: Commenters stated the EPA should favor mechanisms that don't create "winners 

and losers."
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Response 52: 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 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 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 more 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 arbitrary 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 

example, one Utah utility operates the three largest NGCC plants in the state and, thus, redispatching to NGCC would require a large shift in generation from coal plants owned by several 

stakeholders to NGCC plants operated by a relative few. 

Comment 53: Commenters asserted that, in assessing the 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 zeroemission resources.

Response 53: 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 emission 
222

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 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 two will 

drive additional emissions reductions, and that all states should be expected to transition from 

hot coal, high-emitting coal and gas plants to cleaner resources over time.

Comment 54: 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 redispatch to be substantially overstated.

Response 54: 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 inclusion 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 concerns 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 been 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 in 
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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 MW 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 the 

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 55: Commenters pointed out what the commenters characterized as inconsistencies in 

the EPA's analyses and asked for clarifications. 

Response 55: The EPA agrees that data sets and calculations from the proposal can be updated. 

The EPA has modified its calculations for these 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:

Commenters 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 costbenefit 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 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 believed this is too 

high. To get 3.5 TCF from 450TWh of electricity one has to assume a heat rate of 7,964 

Btu/kWhr. However, EIA estimates the electric power sector consumed 9.1 TCF of natural gas in 

2012. Consuming an additional 3.5 TCF of natural 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 
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increase by 50%. Although the amount of power produced by simple cycles might be large 

enough to account for this discrepancy, the modeling results in the 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 higher than the value in 2012. It is 

uncertain whether this is due to the assumed impact of planned coal unit retirements and NGCCs 

taking up the slack or another reason. Page 3-26: At the top of the page it is stated: "This is 

because only 29 state goals 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." This second sentence is 

confusing 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: Although natural gas may be cheap and plentiful now and production increases are 

projected, general 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 future 

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:

Commenters 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.

Commenters stated that since many chemistry processes require large amounts of electricity and 

natural gas, both as a raw 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. 

Commenters agreed that natural gas production is increasing overall, but asked whether the 

increased production will be enough to offset the huge increase that will be required for power 

generation by switching to natural gas.
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Commenters 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. Commenters

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.

Commenters stated that while re-dispatch will ultimately reduce GHG emissions, reliance on this 

Building Block will increase the usage of natural gas. Commenters asserted that if this Building 

Block remains a component of BSER, options for mitigating this increased natural gas usage 

should be considered. 

Commenters stated that there are many critical issues and questions with a large-scale fuel switch 

to natural gas for 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 source 

demand? 

Commenters 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 lack of natural gas. Commenters 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. Commenters also asked what economic and 

environmental impacts those shifts will have on those who use natural gas for other purposes 

such as residential heating.

Commenters also expressed concern over the availability of natural gas and the transportation of 

natural gas during extreme weather events. Commenters emphasized the distinction between the 

availability of natural gas and the availability of natural gas transportation and balancing 

infrastructure needed to support the expected high capacity factor operations of existing NGCC 

units. Commenters referred to the 2013-2014 winter which posed unique natural gas delivery and 

operational flexibility challenges for Brazos 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. Commenters stated that during a normal winter, a cold 

blast will last a few days before fading to warmer weather, which allows pipelines to recover. 

Commenters stated that the consistent cold of the 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. Commenters stated that the assumption of readily available natural gas is 

inaccurate in the Brazos Electric's experience and for the nation as a whole.

Commenters stated that analysts at the Center for 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. 

Commenters 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 at 
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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 natural gas.

To develop a stable natural gas supply market to support stable electric power production, 

Commenters 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 production 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 export are successful.

Commenters stated that it is unwise to rely too heavily on any single source of energy because, 

like any other commodity, natural gas is susceptible to fluctuations in supply, demand and price -

not to mention the specter of additional environmental 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; competitive markets must remain liquid to 

aid efficient delivery of natural gas to customers, adequate infrastructure (including pipeline 

capacity) and an efficient and predictable siting 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 indicated 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. Commenters noted he has been involved in the energy 

production business for a long time and said ample supply and cheap prices will continue for the 

foreseeable future, making compliance with this rule relatively easy, or easier than we would 

have thought a few years ago.

Commenters 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. Commenters opined that a critical 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 demand. Commenters stated that new pipeline capacity 

will play an essential role in transporting gas to market. According to the commenters, the 
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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. Commenters added that regulators, including the FERC, should remove any 

structural barriers that inhibit the construction of new natural gas pipelines and should support 

market stakeholders as they seek to ensure adequate and timely infrastructure is in place to 

support the greater use of natural gas.

Commenters stated that the natural gas market 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. Commenters 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. 

Commenters concluded that taken together, these procurement tools can assist power market 

participants in accessing robust and reliable supplies of natural gas for their needs.

Commenters 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. Commenters asked the EPA to 

continue to use up-to-date assessments of natural gas supply and availability in this and future 

regulatory actions. Commenters 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 to EIA's AEO 2013 used by EPA to calibrate the IPM modeling platform 

used to evaluate the potential impact of the proposed rule.

Commenters stated that a recent analysis by Bentek supports the conclusion that natural gas 

production is expected to grow significantly across the country . Commenters indicated that such 

production growth has driven, and is driving, large investments in infrastructure to move gas 

from supply basins to demand markets. Commenters 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 commenters, this bi-directional feed relieves pipeline capacity constraints and 

hence creates new pipeline flexibility. The commenters 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 replacement 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 Final 

Rule supporting the final CPP. 
228

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

Commenters stated neither the Proposed Rule nor its Technical Support Documents address 

concerns about the historic variations of EIA projections of natural gas supply. 

Commenters 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, Commenters believed that EIA's methodology 

underestimates industrial demand for natural gas. Commenters 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 announced projects in the chemical industry.

Commenters stated that projections of the future natural gas supply are uncertain because shale 

gas reserves are more difficult to project than conventional gas reserves. Commenters 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. Commenters indicated that due to the fact that shale gas reserves are more 

difficult to project than conventional gas reserves, EIA has had to revise its shale gas numbers 

downwards several times in the last five years. Commenters 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. 

Commenters stated that natural 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 

commenters, various sources have made widely divergent predictions, so it remains an open 

question just how much shale gas exists in the U.S., and more fundamentally, what the 

production rate will be. Commenters indicated that all conventional gas wells tended to have 

lower production after 10, 20, or 30 years and that available shale gas production records from a 

few states (predominantly the Texas Railroad Commission 131) show shale gas wells tend to 

deplete significantly after about three years.

Commenters stated that insufficient information exists thus far to predict whether the dry shale 

natural 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. Commenters added that the availability and 

timeliness of drilling reports varies among states, further complicating the ability to predict 

supply, and that EPA staff may not be familiar with all the nuances of drilling reports or the fact 

that many EIA reports comingle liquid natural gas or wet and dry data when reporting on annual 

drilling and production records. According to the commenters, such commingling can 

inadvertently provide an overly optimistic picture of shale gas production.

According to commenters, 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. Commenters said that the 

EPA appears to take it on faith that EIA's current long-term estimates of low-cost, plentiful 

domestic natural gas supply are accurate. Commenters 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. Commenters stated that according to EIA, the 
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Marcellus formation, which stretches from New York to West Virginia, produced about 15.6 bcf 

of natural gas per day in August 2014, about 38% of total U.S. natural gas production for the 

month. However, according to the commenters, records are minimal for dry gas production from 

the Marcellus and Utica formations. Commenters 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 premature to assume these formations will be able to produce the 

gas needed for large-scale and long-term fuel switching.

Commenters stated that, while the EPA relies on EIA natural gas forecasts in determining, under 

BB2, that redispatching large amounts of coal-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. Commenters 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 would 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 fouryear-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 below 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 are 

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 breached $7.46/MMBtu and during February reached $7.78/MMBtu-
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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 proven 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 percent - 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 minimum, 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 too 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 forecasts, 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 

production 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 $9.00/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.
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Comment 4: The EPA failed to support its claims that sufficient 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 rates. 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:

Commenters stated that the EPA's analysis of the ability of the country to sharply expand 

generation is meager, just one page (GHG Abatement Measures TSD at 3-12) out of a 224-page 

technical support document that EPA uses to explain its building block assumptions. 

Commenters noted that, while the EPA recognizes 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. Commenters stated that, even if those efforts began today, they would have to 

be completed by 2020, which is just over five years away. Commenters added that, if those 

efforts do not begin until states finish developing their implementation plans (or, more likely, 

EPA approves those plans), only a few years would be left before the significant amount of 

additional natural gas supply would be needed to support EPA's proposal. Commenters 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 foot 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: The EPA needs to address competing 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 rates. 

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 is 
232

expected to be consumed by the LNG export facilities which have recently been approved. As an 

example, Commenters 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 table 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). Commenters recommended that the EPA 

clarify its assumptions for the potential magnitude of LNG exports to the potential price of 

natural gas. 

Commenters stated that in recent years, there have been a significant number of proposals to 

bring large industrial facilities and LNG export 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, commenters 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. Commenters added that the U.S. DOE has been evaluating applications 

to export LNG from the U.S. to countries with which the U.S. does not have a qualified free 

trade agreement in place - DOE has approved nine such applications to export LNG, and has 

more than 20 additional applications pending for review. Commenters asserted that when the 

EPA assumed that a 70% capacity factor is available for NGCCs, it does not appear that the 

Agency considered the significant impact that this increased natural gas demand could have on 

natural gas prices, and consequently the ability 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 failed to consider the impact exports of LNG and nonelectric utility demand will have on natural gas supply and prices. Regarding LNG exports, 

commenters indicated that given the recent applications to the DOE for approval to construct 

new LNG export terminals, U.S. producers will begin exporting natural gas to European and 

Asian markets where demand for gas is also increasing and prices are higher than in the U.S. 

Commenters added that the domestic demand for natural gas is also projected to increase for use 

by manufacturers as feedstock and by the transportation sector as a fuel source. According to 

commenters, the EPA apparently has not examined any of these issues that could impact the 

supply available for electric utilities or the price they would pay for the gas. Commenters

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 

CO2 emissions from power plants.

Commenters 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. Commenters added that European concerns 

about reliance on Russian gas have led to calls by some for the U.S. to export gas to the 

continent. According to the commenters, while it is still unclear how much domestic natural gas 

may be exported, it is very likely that exports would put upward pressure on domestic prices, 

which would impact electricity rates. Commenters 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 CO2 emissions from the utility sector.
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Commenters stated that more than 25 applications for LNG export terminals have been filed with 

DOE, and several have been approved. Commenters conceded that it is unclear how much 

natural gas will be exported, but indicated that given 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, commenters pointed 

out that the Sabine-Golden Pass project that was approved in late September is currently 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 future.

Commenters stated that the EPA also has not looked at the impact Canadian LNG exports could 

have on U.S. natural gas prices and supply, noting that the U.S. is the largest user of Canadian 

gas and many utilities use it for generation. Commenters 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. Commenters also pointed out that U.S. shale gas can be exported through Canadian 

LNG terminals to other international markets.

Commenters stated that Asia petrochemicals manufacturers want to take advantage of U.S. 

natural gas supplies and plan to build tanks and retool plants to store and process liquefied 

petroleum gas (LPG) derived from shale gas. Commenters 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 plastics. Commenters said that such Asian imports of LPG will reduce 

U.S. domestic supply of shale gas.

Commenters stated that many transportation companies have announced plans to move to 

compressed natural gas (CNG), some of citing the lower price of natural gas and others citing 

meeting other environmental regulations. Commenters indicated that while natural gas exports 

via LNG for international transportation demand may be at least five or ten years away, it is also 

relevant for consideration under the Proposed Rule. According to the commenters, Energy 

consultants Wood Mackenzie say global gas demand in the transport sector could grow from 

under 5 billion cubic meters (bcm) in 2012 to over 160 bcm by 2030, which would be equivalent 

to two-years-worth of current (2014) British gas demand (approximately 3 million barrels of oil). 

Commenters 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 Asian 

import markets (approximately $20 Mcf), the export of CNG for transportation markets is not 

implausible. 

Commenters stated the EPA failed to assess the economic effects on other economic sectors from 

higher natural gas prices or potential gaps in the incremental natural gas supply. Commenters

noted that many sectors of the economy rely on natural gas and have increased natural gas 

consumption since pre-recession levels, including the power, industrial, and transportation 

sectors. Commenters stated that natural gas exports will begin to coincide with the accelerated 

retirement of coal generators. Commenters 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 begin 
234

operations at the end of 2015 and has locked customers into 20-year contracts; and (3) U.S. 

exports of natural gas to Mexico are expected to rise by 3.5 bcfd by the end of this year 

according to DOE - nearly double the current rate. Commenters stated the EPA's analysis does 

not touch upon any of these market developments and how the proposed rule will affect the 

economic sectors and residential customers that depend upon natural gas. 

Commenters stated that recent history provides more than ample experience on the scope and 

depth of the consequences of over-relying on natural gas. Commenters 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. Commenters stated this occurred even when natural gas 

demand fell - but prices increased by 160%. Commenters 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 sectors. 

Commenters 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). Commenters 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 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 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 reassess 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 for documentation.

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

Commenters 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. Commenters asserted that assessing these effects is important because the electric 

sector represents only a portion of the natural gas consumption in Alabama, Florida, and 

Georgia. 
235

Commenters stated that nationally, the electricity sector represents even less of a share of total 

natural gas consumption - approximately 34 percent in 2013. Commenters concluded that the 

EPA must reassess its proposal in order to more fully estimate and reflect the significant effects 

and feedbacks it has on the U.S. economy. Commenters 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: The 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 sections V.D, VIII.A and VIII.C of the final rule preamble of the CPP, Chapter 3 

of the GHG Mitigation Measures TSD for the CPP 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:

Commenters 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 and then asserts that at current rates of 

consumption, the resources are enough to supply over 90 years of use (RIA at 2-23). 

Commenters stated that only a small subset of the TRR can be considered "reserves" (about 24 

years currently of potential supply) reasonably available for consumption. Commenters 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 nation's enormous coal reserves-the most cost-effective fuel for base load power generation. 

Commenters stated that, while the TRR are divided into three categories, speculative, possible 

and probable, only the probable TRR have been tested by drilling and known to be, in fact, 

technically recoverable. Commenters 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. 

Commenters stated that, using the TRR estimate of 2,214 Tcf, the probable TRR is 664 Tcf-or 

about 25 years of supply at the consumption rates over the past two years (26.60 Tcf) and 

converting the probable TRR to reserves equals about 332 Tcf that can be added to the already 

proved reserve base of 305 Tcf. Commenters concluded that the combined total of 635 Tcf 

leaves 24 years of supply at current consumption rates.

Commenters stated that, while economic viability is a key factor whether resources are 

eventually converted to reserves and developed and higher prices would convert more probable 

resources to reserves, these higher energy prices carry consequences for the other sectors 
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consuming natural gas and the economy as a whole. Commenters 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. Commenters stated that less than a quarter 

century of natural 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 adequate infrastructure.

Commenters 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 commenters, 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 segments 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. Commenters also stated that a second set of EIPC maps shows EIPC's modeled 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 there 
237

are predicted to be many fewer fully utilized pipeline systems in the summer months under either 

scenario. 

Commenters 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. Commenters believed, 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. Commenters noted 

that in December 2012 FPL issued a Request for Proposals to find the best option for new natural 

gas supply for its customers, which will result in a system comprised of two new pipelines and 

an interconnection hub. According to the commenters, the Sabal Trail Transmission and Florida 

Southeast Connection pipelines are progressing 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 November 2014. 

Commenters 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. 

Commenters referenced 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. Commenters stated that, while these studies address natural 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. Commenters

stated that, given the often significant availability of delivered 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. Commenters stated that recent pipeline capacity 

have been significant and pipeline capacity will continue to grow. Commenters 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. Commenters stated that natural gas infrastructure 

additions have been significant since 2007. Commenters 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 through 2006 

timeframe. Commenters 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 online by 2018.

Commenters 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. Commenters provided a Figure 7 (titled: “EIA 

Projections of Electric Sector Natural Gas Demand”) which shows a range of natural gas demand 

projections for the electric sector developed by the EIA as part of its AEO series. Commenters

stated that the AEO 2008 projected a steady decline in natural gas use by the electric power 

sector while, in contrast, AEO 2014 projected a 48 percent increase in natural gas utilization in 

the electric sector from 2011 to 2040, up from a projected 25 percent increase in AEO 2013. 
238

Commenters stated this shift is due to the expected retirement of coal-fired and oil-fired power 

plants and to confidence in the long term outlook for natural gas price and supply. 

Commenters noted that the height of natural gas consumption occurs during winter months 

mainly due to residential and commercial seasonal heating needs. Commenters 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 percent of the annual maximum 

consumption, on average. Commenters 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 infrastructure constraints. Commenters 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. 

Commenters stated that, while the 2013-2014 winter severely stressed the electric grid and the 

natural gas delivery system, no bulk power outages occurred, and natural gas customers utilizing 

firm contracts did not experience supply curtailments. Commenters 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 demand 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 Interconnection: 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 

winter conditions." 

• The Electric Reliability Council of Texas ("ERCOT") commissioned a study in 

2012 to examine the risk of gas supply curtailment to electric generators within its 

service. The study found that ERCOTs electric 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 study 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." 

Commenters stated the existing NGCCs in Arkansas have sufficient gas supply to run at 100% 

capacity now under most conditions. Commenters 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. Commenters

stated that, considering the enormous supplies available from the Arkansas wellheads and 
239

pipelines, no additional infrastructure is likely to be necessary for Arkansas NGCCs to operate at 

70% capacity factors. Commenters 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 has 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. Commenters noted Arkansas also lies on a massive pipeline corridor from the gas 

fields 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 average allows states to comply.

Commenters 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. Commenters added that the EPA's rule can be 

implemented through a mass-based allowance system, under which emissions allowances can be 

traded on an interstate basis with other states (which commenters recommended as discussed 

elsewhere in this document). Commenters concluded that all of this suggests that the existence of 

a current infrastructure constraint need not preclude CO2 reduction through re-dispatch.

Commenters 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. Commenters

disagreed with 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, commenters

stated that transport capacity is still available for re-dispatch in unconstrained regions and off 

peak times of the year. Commenters indicated that natural gas consumption in the United States 

peaks during the winter home heating season and interstate 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. Commenters

stated that this capacity could allow existing NGCC units to increase generating output without 

infrastructure expansion. 

Commenters stated that certain stakeholders' concerns regarding the adequacy of natural gas 

pipeline infrastructure to accommodate the increased utilization of existing NGCC units appear 

to be unfounded and provide no justification for reducing the utilization rate assumption in 

Building Block 2. Commenters referenced the NODA (79 FR 64543, 64546) and noted that some 

stakeholders have challenged the 70% utilization factor that provided the basis for Block 2 by 

pointing to alleged deficiencies in natural gas pipeline infrastructure. Commenters stated that, 

because Block 2 is not premised upon the assumption that every existing NGCC facility in the 

U.S. will be utilized at a 70% capacity factor, the anecdotal information offered by some to 

suggest that particular existing NGCC facilities may not be able to achieve a 70% capacity factor 

today, due to their geographic location and existing pipeline constraints, does not provide a basis 

for applying a lower capacity factor in the calculation of Block 2. The commenters stated that, in 

the event there are existing NGCC units that cannot increase their utilization due to existing 

pipeline constraints, the projected expansion of the natural gas pipeline system leading up to 
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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 commenters

referenced 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-act/pipelines/horizon-pipe.pdf (indicating 

that 21.96 BCF/d of new interstate pipeline capacity is in development). Commenters stated that, 

accordingly, claims about insufficient natural gas pipeline capacity provide no basis for EPA to 

amend its Block 2 benchmark.

New England's infrastructure is not representative of the U.S.

Commenters indicated that concerns regarding gas 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 Gas-Electric System 

Interfaces" (EIPC, Target 1 Report, Table 7, available at: http://www.eipconline.com/GasElectric_Documents.html). Commenters went on to note that the gas and electric industries, 

along with federal and state regulators, are engaged in multiple efforts to assess and, where 

needed, bolster the adequacy of fuel transport and storage systems. Commenters believed that for 

this reason, it is likely that any critical infrastructure constraints can be addressed.

Commenters 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.: 

• 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 not 

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 available 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") is 
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expected to greatly reduce volatility in the region. This project is scheduled to 

come online in November 2016.

FERC actions are enhancing the infrastructure.

Commenters stated that improvements to gas market design such as those currently being 

considered by FERC will considerably enhance gas supply and deliverability to power generators 

from the existing infrastructure, which would allow the electric power sector to reduce emissions 

at a lower cost than would otherwise be possible. Commenters stated that while some additions 

to today's natural gas delivery infrastructure may be necessary before 2030, the current natural 

gas delivery infrastructure is robust and is capable of delivering significantly more natural gas to 

the power fleet than it does today. Commenters indicated that this is particularly true on an 

annual basis, but is also true even during peak periods of demand. According to the commenters, 

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. Commenters noted that FERC 

is in the midst of efforts to refine the standards and rules governing interstate gas transportation 

to, among other things, ensure that the market design better serves natural gas-fired electricity 

generators. Commenters 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 schedule natural gas transportation services (79 Fed. Reg. 18, 223). According to the 

commenters, 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).

Commenters stated that beginning in 2012, 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. Commenters 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 scheduling 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). Commenters stated 

that the FERC proposal was issued in response to an interest in updating market design to 

enhance the ability of natural gas-fired generators to acquire natural gas, and to augment the 

means by which the pipelines schedule and deliver natural gas to power plants.

According to commenters, 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. Commenters indicated that in the proposal, FERC presented specific 

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-
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development process at NAESB. Commenters 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 subsequently filed a series of consensus standards with the 

Commission on September 29, 2014. Commenters added that while there remains an open issue 

regarding the start of the gas day, it is highly 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: Commenters stated that, if additional pipeline capacity is needed to support 

compliance 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://www.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:

Commenters 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 transportation service. In connection with this point and in order to 

ensure that there is no confusion regarding the process for developing new pipeline capacity, 

commenters provided some context and clarification to a statement in EPA's analysis. 

EPA states: The third consideration supporting the conclusion regarding the adequacy of 

the infrastructure is that pipeline and transmission planners have repeatedly demonstrated 

the ability to methodically relieve bottlenecks and expand pipeline capacity. Natural gas 

pipeline 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 market demand that 
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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 natural 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 firm 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 commenters, this is an important point in connection with satisfying 

the need for new interstate natural gas pipeline capacity that may be created by implementation 

of the Clean Power Plan. 

Commenters stated the legal and regulatory process for siting and permitting new pipelines and 

adding capacity on existing pipelines is a very complex multi-year process, in which the time 

between the inception of a pipeline project and an in-service pipeline historically has averaged 

about three years, depending on the size and complexity of the project and issues encountered in 

the permitting process. Commenters 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. Commenters 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. 

Commenters stated the state implementation plans must allow sufficient time to (1) identify the 

instances in which 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. Commenters 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.

Commenters stated that the part of 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. Commenters stated 

these permits ensure compliance with other federal resource and environmental laws, such as the 

Endangered Species Act and the Migratory Bird Treaty Act. Commenters stated that delays in 

processing and issuing these permits can add significantly to the time needed to construct a 

pipeline project. Commenters suggested the EPA should be mindful of how regulations and 
244

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.

Commenters 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 other public policy objectives, since Interstate natural gas pipelines fit 

squarely within this category. Commenters suggested the administration should work 

constructively with the Congress on statutory reforms that will make it possible to increase the 

efficiency and predictability of pipeline permitting. Commenters 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 implementation 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: Commenters stated the advantages of clean-burning natural 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 specific public comments under this comment:

Commenters stated that, although the winter of 2013/2014 created multiple challenges for grid 

operators, the majority of problems encountered during these extreme conditions were not an 

issue of natural gas availability. Commenters cited a letter from PJM in response to questions 

about the polar vortex from members of the U.S. 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 other capacity (including hydropower and oil). An increased focus 

on cold weather preparedness should help to mitigate these problems in the future. 

Commenters stated these "interruptions" were a function of the gas delivery contracts generators 

had with the pipelines. Commenters stated that, in times of high demand, generators holding a 

lower-cost, interruptible contract will see that service interrupted - that is wholly consistent with 
245

the contractual agreement and not a function of natural gas availability. Commenters stated this 

aspect is acknowledged in a separate communication where PJM noted that, "the gas supply 

problems experienced last winter were primarily contractual and economic, not physical 

constraints, meaning that for many gas-fired generators, 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.

Commenters 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 following 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. Commenters stated the operating characteristics of natural 

gas-fired power plants enable the expansion of intermittent resources, like solar and wind, 

allowing grid operators to keep supply and demand of electricity in balance. Commenters stated 

the presence of natural gas generation provides grid operators the freedom to accept capacity 

from renewable energy sources without putting electric system reliability at risk. Commenters

cited a number of studies that have affirmed the important role of natural gas-fired power plants 

in enabling renewable power. 

Commenters 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. Commenters 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 gas facilities are scalable and require only 

minimal lead time as compared with other traditional power sources. Commenters referenced 

EIA data and stated that, in light of the continued positive outlook for natural gas supply and 

availability, the electricity sector's use of 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. Commenters stated that NGCCs can effectively and 

efficiently supply baseload power to the electric power system. Commenters noted that, in 2013, 

natural gas-fired power plants accounted for over 50 percent of new utility-scale generating 

capacity with about half of that capacity in the form of NGCC power plants that provide 

intermediate and baseload power. Commenters stated that, over the first six months of 2014, 

natural gas-fired power plants again made up more than half of the utility-scale capacity 

additions in the United States and almost all of these plants were NGCC, the majority of which 

are designed to serve baseload power in the regions in which they operate. Commenters stated 

there is a recognition in the industry that current price and regulatory dynamics have created an 

opportunity for existing NGCCs to increase 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 disagrees 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 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 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. Commenters

cited the polar vortex from the winter of 2014 when stating that many natural gas system 

operators faced significant reduction of generation capacity as a result of curtailments and gasfired generation during extreme weather events. Commenters stated that, in an integrated natural 

gas/electric power market following implementation under the proposed rule, where gas delivery 

systems will be further strained as more gas-fired electric generating units displace coal-fired 

units, a similar polar vortex event could cause major interruptions in meeting peak heating 

demand. Commenters noted that the current natural gas pipeline system is 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 natural gas infrastructure to support expanded natural gasfired generation as a result of the timing of the proposed CPP. 

Commenters 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. Commenters

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. Commenters 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. Commenters also noted 

that many coal plants in existence today and which will be affected by the proposed rule were 

built in the 1970's when it was illegal to build natural gas plants.

Commenters 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. 

Commenters stated this would require a closer consultation by EPA with entities such as NERC, 

INGAA and PJM. Commenters stated the EPA's sole reliance on traditional historic EIA and 
247

INGAA reports fail to account for the impacts of extreme weather events and the stressors these 

events place on the system. 

Commenters 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 bottlenecks and expand capacity. 

Commenters stated the INGAA Report's principal findings indicate that significant infrastructure 

will be needed to support growing gas use. Commenters stated the base case assumes $100 per 

barrel of oil and shows gas prices rising from $4 per MMBtu to an average of $6 per MMBtu in 

the longer term. Commenters stated the base case projects significant supply development and 

growth in gas production, primarily from shale resources. Commenters stated producers are 

likely to develop shale resources with large quantities of oil and gas, which also have significant 

needs for new pipeline infrastructure. Commenters 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. Commenters stated a 

significant number of gas processing, pipeline, and fractionation facilities will also be required to 

accommodate growing gas production.

Commenters stated that, as last winter's "polar vortex" demonstrated, pipeline capacity failures 

during extreme weather conditions and general breakdown of pipeline infrastructure is a 

continuing reality. Commenters 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. Commenters stated the breakdown of forced outages by primary fuel type shows that 

natural-gas-fired generators accounted for 47 percent of the unavailable megawatts. Commenters

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. Commenters stated that, 

subsequent to January, PJM worked with generation 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 gas infrastructure. Commenters stated an example is a generator that burns oil but 

that needs natural gas to start up. Commenters referenced the 2014 NERC Report on the Polar 

Vortex and stated this report highlighted the contribution of gas supply shortfalls 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 redispatching 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 the 
248

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 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:

Commenters 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 commenters' trade association have operated above these levels for extended 

periods of time. Commenters indicated that whether the system as a whole can operate with most 

states' NGCC fleets averaging this utilization level by the early part of the compliance period (as 

implied by the goal computation) is less clear. According to the commenters, 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' locations in the electric or gas transmission 

system. Commenters stated that procuring adequate natural gas supplies to sustain a high level of 

utilization year round could mean, in the case of some states, building new pipelines or 

increasing the capacity of existing ones, while in others getting the electricity to consumers 

currently served by steam units without expanding transmission may be a challenge.

Based on these types of uncertainties, commenters recommended that the EPA establish a more 

strategic approach 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 guidelines without 

increasing NGCC utilization to 70 percent, commenters would support changes to the rate at 

which Building Block 2 is deployed as part of the goal-setting process. Commenters added that 

as much as the shift EPA has proposed as a part of Building Block 2 is about increasing NGCC 

utilization, it is also about decreasing boiler 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.
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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 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 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 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 annual 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 northwest 

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 displace 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 Indiana 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 whether older facilities will be able to run at 70% capacity factor 
250

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 newer 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

Commenters stressed that assumptions regarding 70 percent capacity factors for NGCC units do 

not consider market prices or firm pipeline capacity. Commenters asked the EPA to carefully 

consider the assumptions that underlie the proposed rule.

Commenters 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. 

Commenters stated that empirical analyses of spot prices identify those regions of the interstate 

pipeline network that are sensitive to constraints. Commenters identified pipelines and market 

areas that showed sustained price spreads (basis differentials) between the pipeline-based trading 

hubs and the reference Henry Hub market. Commenters noted that a hub was considered to be 

constrained on a trading day if its closing price was double the price at Henry Hub; if the hub 

was constrained more than 250 times between June 1, 2009 and October 6, 2014 then it was 

classified as congested. Commenters provided a table (titled: “Historically-Congested Pipelines / 

Trading Areas"), which listed ten natural gas pipeline hubs, including: Texas Eastern 

Transmission (TETCO) 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. 

Commenters stated that Building Block 2 is not a viable option because natural gas is not an 

available fuel without limitations. Commenters stated that SCANA, like many utilities, has 

insufficient firm capacity on the interstate pipelines to increase natural gas usage for many of its 

units. Commenters 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). Commenters noted that for the 

past several years, CGT has reported that its pipeline is "essentially full," and Transco and SNG 

are also fully subscribed. Commenters stated this means that additional pipeline facilities or 

system modifications would be required for SCANA to obtain additional natural gas capacity. 

Commenters stated that, pursuant to FERC regulations, projects to add capacity to natural gas 

pipelines are subject to a lengthy approval process. Commenters stated that, it may sound easy to 

re-dispatch from coal to natural gas, but this 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-cost 
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electricity throughout the United States and does not dispute that many NGCC facilities are 

capable of operating at an average capacity factor of 70% or more. However, commenters said 

EPA is arbitrarily and capriciously relying on the fact that all NGCC facilities in a given State 

are necessarily capable of simultaneously operating at a 70% capacity factor by 2020, when EPA 

assumes that Building Block 2 will be implemented, explaining that EPA did not fully account 

for several current challenges associated with existing NGCC units in its BSER analysis. 

Commenters continued, stating that while it is only a function of time until infrastructure and 

supply constraints, EPA must evaluate existing NGCC facilities within the context of the existing 

infrastructure in the States in which they are operated, and, when viewed in that context, there 

are a number of challenges that must be considered when determining whether existing and 

under construction NGCC facilities collectively can be dispatched at a 70% capacity factor in a 

given State. Commenters believed EPA's proposal is arbitrary and capricious because it does not 

adequately evaluate the potential impact of those 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 EPA 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 permits, and in some cases, those permits may limit a facility's 

hours of operation or total amount of fuel that can be used. Commenters said, for 

example, a facility may rely on a permit condition to limit operating hours or annual fuelfiring rates to maintain its status as a minor 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 coalfired electricity generating capacity that can be redispatched to NGCC facilities. 

Commenters said, because electricity demand is not consistent, EPA must account for 

cyclical demand when evaluating the amount of coal-fired electricity generation that can 

be displaced. Commenters said, for example, in high-demand summer months, NGCC 

facilities may already operate at or near 70% 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, commenters 
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suggested that EPA must incorporate seasonal variation to more accurately estimate 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 strategically 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 EGUs 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 suggested 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 not 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 additional 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 the 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 generation 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 stated 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 projects 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 permitting 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. 
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5. Commenters stated that EPA simply assumes in its calculation of State emission 

reduction targets, without support, that all NGCC facilities that are currently 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 EPA 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 cofired EGUs. 79 Fed. Reg. at 64,550. Commenters said, as an initial matter, EPA explicitly 

rejected co-firing natural gas as BSER in the 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 reverse 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 because 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 can 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 potential 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 whether 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 natural 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 capricious for EPA to rely on co-firing 

Infrastructure

Commenters 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 operate at 70 percent capacity factors. Commenters noted that these are questionable 

assumptions on which to build building block 2.

Commenters stated that the EPA has not fully evaluated the transmission and gas supply 

infrastructure issues that may significantly impact the feasibility and amount of potential redispatch. Commenters 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. 
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Commenters 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. 

Commenters stated 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. Commenters stated that, in the West, this likely means 

significant additional environmental reviews to permit infrastructure projects on public lands. 

Commenters stated that greater reliance on variable resources and gas-fired generation is 

expected: The CPP will accelerate the ongoing shift toward greater use of natural-gas-fired 

generation and variable energy resources (renewable generation). Commenters noted that 

increased dependence on renewable energy generation will require additional transmission to 

access areas that have higher-grade wind and solar resources (generally located in remote areas). 

Commenters added that increased natural gas use will require pipeline expansion to maintain a 

reliable source of fuel, particularly during the peak winter heating season. Commenters stated 

that pipeline constraints and growing gas and electric interdependency challenges impede the 

electric industry's ability to obtain needed natural gas services, especially during high-use 

horizons.

Commenters 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. 

Commenters stated this may be true in certain parts of the country, but not others. Commenters

(cited Moeller House Testimony and) stated that (1) gas pipeline developers are reluctant or even 

unable to build pipelines without anchor customers, like the natural gas generation owners that 

use gas; (2) these generation owners will not 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 generators 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 dispatch requirements. Commenters stated that, for these 

reasons, the Proposed Rule may actually be dis-incentivizing the development of the natural gas 

infrastructure that EPA assumes exists. Commenters 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. Commenters included the 

following description, analysis and findings:

The interstate pipeline system in the United States represents firm delivery capacity that was 

largely built to serve, and almost completely 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 take 
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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 had 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 support 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 

quadrant 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. 

Commenters 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. Commenters stated the ability to transport much larger volumes of natural 

gas will be a significant challenge, especially so with the age of existing natural gas 

infrastructure and the large amounts of new natural gas pipeline needed to support growing gas 

volumes. Commenters referred to a ScottMadden report 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 study 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 about 15,500 miles of new pipe per year will be needed in the future, with most of this being 

gathering line. Commenters also added new pipeline is estimated to cost $3.7 million dollars per 

mile.

Commenters provided a document in support of other comments that looked at impacts on 

natural gas and deliveries to electric utilities 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 be 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 demonstration

Commenters stated the EPA's current assumptions of the NGCC capacity are insufficient to 

demonstrate there is technical plant capability and infrastructure, available gas, gas 

transportation, gas storage, and electric transmission capacity available to sufficiently increase 
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NGCC generators' historical performance. Commenters noted that cooperatives across the nation 

own 12,000 MW NGCC capacity with NGCC plant capacity averaging 35% in 2012 and 27% in 

2013. Commenters 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. Commenters stated the EPA has not demonstrated that the NGCC fleet is 

capable of almost doubling its average performance in order to take on the demands of coal-fired 

re-dispatch.

Commenters stated the notion that BSER includes operation of gas units in sufficient number and 

at a 70% capacity factor to partially offset the lost generation from shuttered coal plants is 

undemonstrated both as a matter of history and in the record. Commenters 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 necessary to satisfy 

building block 2, albeit over a much shorter period if the 2020 deadline is maintained. 

Commenters stated the pipeline infrastructure build-up necessary for building block 2 cannot 

simply be wished into existence as a matter of capital investment, permitting, or construction. 

Commenters 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." 

Commenters added that the EPA has not demonstrated that the enormous capital required is 

available within the necessary period.

Regional

Commenters stated the EPA failed to consider 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 

certificate 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. Commenters stated that, to the extent a pipeline constructs facilities to 

provide a particular level of service, but does not have precedent agreements in place for that 

service level, FERC will place the pipeline "at risk" for any cost under-recoveries associated with 

underutilized facilities. Commenters stated 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 jurisdictional rates for firm interstate 
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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 capacity. 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

Commenters expressed concern that the re-dispatch would force the state to run down nearly all 

of its coal plants. Commenters noted that Arizona has a large amount of natural gas generation, 

but only 50 percent of those facilities are owned by state utilities. Commenters also noted that 

most of the facilities are located in one general area west of Phoenix. Commenters are concerned 

that the EPA fails to consider existing contractual obligations, transmission capacity constraints, 

pipeline availability, security considerations, and air quality limitations.

Commenters stated that, with limited pipeline capacity in Florida, the magnitude of this increase 

in natural gas consumption is a concern.

Commenters expressed that Hoosier Energy has experienced a lack of natural gas availability in 

times of extreme weather and under other conditions. Commenters noted that this occurred at 

both combined cycle and peaking facilities. Commenters stated that setting a goal 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. Commenters

stated that the EPA must examine these constraints and adjust state goals if gas availability 

cannot be assured. Commenters also noted that many combine cycle facilities were not built to 

run such a high capacity factor and that the constraints of the units themselves must be 

considered.

Commenters expressed concern regarding the amount of electrical generation that can be redispatched to NGCC units based on the current natural gas supply and infrastructure in Illinois. 

Commenters stated that, during the polar vortex period last winter, affected EGUs were severely 

restricted in purchasing gas because the supply was prioritized for other sources, such as home 

heating. Commenters noted that, while actions are being taken to improve infrastructure, 

estimated completion dates are several years away and may not entirely address the situation.

Commenters expressed concern regarding the adequacy of pipeline capacity in Missouri. 

Commenters stated it is important to examine the potential risks associated with an increased 

dependence on natural gas. Commenters stated that, unlike coal and fuel oil, natural gas is not 

typically stored on site and, as a result, real-time delivery of natural gas through a network of 

pipelines and bulk storage is critical for Building Block 2. Commenters noted that other states 

along interstate transmission pipelines presumably would also need additional capacity to meet 

Building Block 2, including Kansas, Illinois, Indiana, Ohio and Michigan. Commenters stated 

that natural gas pipelines serving Missouri were designed for winter heating 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 increased, resulting in a significant amount of gas-fired 

generation being unavailable due to curtailments. Commenters objected to the EPA's apparent 
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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. Commenters stated the EPA's assumption 

ignores the complex interrelationship between the electric sector and natural gas supply and 

pipeline capacity. Commenters stated the EPA is relying on the natural gas supply and pipeline 

industries which are not subject to the Clean Power Plan to commit to meeting the electric 

sectors requirements under the Clean Power Plan on the same timeline as that set by the EPA. 

Commenters stated that there is currently not sufficient gas capacity to support an NGCC plant in 

Missouri during the winter heating season. Commenters 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 Oklahoma due to the severely cold weather and a lack of sufficient capacity 

to transport additional supplies of natural gas.

Commenters stated that Nebraska does not have 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.

Commenters expressed concern regarding the lack of a major gas pipeline in the lower half of 

South Carolina. Commenters noted that the EPA seems to believe that natural gas is readily 

available and affordable in all parts of the country. Commenters noted that natural gas is not 

available to certain areas. Commenters stated that lack of a major gas pipeline in the lower half 

of South Carolina puts the state at a very high disadvantage. Commenters stated the increased 

natural gas target fails to recognize that South Carolina'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 infrastructure constraints and supply limitations of South Carolina particularly 

for natural gas. 

Commenters stated that is MRES built in states where it has load, it would face similar 

infrastructure issues as if it built in Wyoming. Commenters 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. Commenters noted that this cost estimate is for lateral pipeline 

development and does not include mainline construction costs. Commenters 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. Commenters 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. Commenters also noted that the cost associated 

with building of sufficient natural gas infrastructure should be considered in the cost assessment 

of the BSER in the proposed rule.

Storage

Commenters 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 formations to store gas that is needed by electric utilities for generation as baseload 

power, to back up intermittent renewables, or provide peaking power. Commenters asserted that 
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the Agency needs to look at these issues and adjust its assumptions about the timetables by 

which states and the electric utility industry can meet the requirements of building block 2.

Commenters suggested that coal piles at the plants are a form of energy storage and this coal 

resource should be continued until the natural gas infrastructure is able to handle increased 

volumes and variable demands of power generation, and as a hedge against price volatility of 

natural gas. 

Timing

Commenters 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. Commenters alleged that the 

EPA asserts that pipeline capacity can be added to enable the large-scale fuel switching the 

Proposed Rule envisions is needed to reduce CO2 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. Commenters 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 intrastate) between 2014-2035 to meet anticipated 

natural gas demand (INGAA comments filed regarding Endangered Species Act listings 

determinations, but not specifically for EPA's ESPS/NSPS for power sector 

http://www.ingaa.org/File.aspx?id=22680). 

Peak demand

Commenters stated that, while the natural gas supply/delivery analysis under the proposed rule 

only discusses averages, actual utility planning and installed infrastructure must deliver under 

peak demand scenarios. Commenters referred to the NERC's initial reliability review (Potential 

Reliability Impacts of EPA's Proposed Clean Power Plan, Nov. 2014). Commenters stated the 

NERC's review (1) challenged the CPP's gas pipeline infrastructure assumption that no major 

investments would be necessary; (2) cited current 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 bottlenecks; and (4) stated concerns that the 

CPP's timelines provide little time to add required pipeline or related resource capacity. 

Commenters added that the Department of Energy (DOE) is funding a study of gas supply 

adequacy by the Eastern Interconnect Planning 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 disagrees that these issues prevent achievement of goals. In response to 

additional analysis and many comments, we have modified the proposal and RIA; requirements 
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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 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:

Commenters disagreed with the assumption that, for NGCC units that operate at higher levels for 

a set period of the day, that level of operation can be extended and sustained without risk to 

natural gas pipeline capacity. Commenters stated this assumption is not valid when capacity is 

unavailable for base-load generation use because of competing purchasers and inadequate 

existing infrastructure. Commenters 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. Commenters 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 regarding utilization of the current NGCC fleet 

at a 70% capacity factor. Commenters suggested that actual available capacity may be far below 

100% of nameplate capacity due to bottlenecks in the system. Commenters referenced a 

November 2014 NERC report which 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.

Commenters stated that natural gas pipelines in the Southeast are fully subscribed; that is, all of 

the pipelines' capacities are subscribed on a firm capacity basis. Commenters stated that as a 

result, for any existing NGCC in the Southeast needing firm transportation capacity to increase 

generation, additional pipeline capacity will be needed. Commenters 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. Commenters 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.

Commenters 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.

Commenters stated the EPA did not consider transmission constraints unique to New York, 

which limit the system's ability to transmit NGCC capacity located upstate to high load areas in 

and around New York City. Commenters stated the proposal appears to assume that both gas 

delivery and electric transmission infrastructure will be in place to support that NGCC capacity 
261

without adequately considering economic, reliability, and technical concerns. 

Commenters 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. Commenters 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. 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://www.nyiso.com/public/webdocs/markets_operations/services/planning/Planning_Studies/

Reliability_Planning_Studies/Reliability_Assessment_Documents/2014%20RNA_final_091620

14.pdf.)

Commenters stated that, because natural gas demand in downstate New York for space heating 

will increase due to a recent New York City local 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. Commenters 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. Commenters stated that, given the relative size of New York 

City and its overall 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 redispatch.

Commenters stated that both SPP and the NERC have analyzed the Proposed Rule and 

concluded that existing transmission is not sufficient to maintain grid stability. Commenters

stated that SPP concluded, based on the generator retirements anticipated by the Proposed Rule, 

that it is "very clear that new generation and transmission expansion will be necessary to 

maintain reliability during summer peak conditions." Commenters 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. 

Commenters 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 availability. 

Comment 8: Commenters 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 they 
262

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. 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 its NGCCs are primarily used to regulate load, and neither of the units can 

support a 70 percent capacity factor year-round. Commenters stated that, while, the two plants 

have access to firm natural gas capacity of 80,000 mmBtu per day for November through March, 

the EPA's proposed 70 percent capacity factor would require approximately 95,000 mmBtu per 

day year round. Commenters stated the gas pipeline serving the two plants is a shared resource 

between PowerSouth and the Southeast Alabama Gas 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 because 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: Commenters 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. 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.A, V.B, V.D, VIII.A, VIII.C and VIII.G of the 

final rule preamble of the CPP and Chapter 3 of the GHG Mitigation Measures TSD for the CPP 

Final Rule supporting the final CPP. 

The following are summaries of the specific public comments under this comment:
263

Commenters stated two factors impede the ability of an NGCC unit to achieve a specific capacity 

factor: (1) natural gas pipeline and RTO scheduling procedures are not in sync and (2), if NGCC 

generation is bid into either the day-ahead or the reliability unit commit (RUC) markets, the bid 

might not be accepted by SPP if the offer price is higher than the market clearing price. 

Commenters stated that, in NPPD's case, current Southwest Power Pool (SPP) offer/award 

schedules for generation bid into the market occur after the points in time when NPPD must 

nominate gas supply needs under pipeline timely or Evening deadlines. Commenters stated that 

NPPD's only option in that situation would be to nominate gas in the Intraday market, but, even 

assuming available firm transportation capacity for the nomination, gas may not be available 

intraday during periods of high demand, when the pipeline declares System Over-run Limit 

("SOL") conditions. Commenters stated this latter situation remains likely despite recent drops in 

the cost of natural gas because gas still remains an expensive fuel for NPPD. Commenters 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 Gentleman 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 market. Commenters 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. Commenters 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. Commenters 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 Under-run Limit ("SUL") conditions.

Comment 10: Commenters 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 EPA 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 plans to 

achieve the 111(d) requirements. See sections V.A, V.B, V.D, VIII.A, VIII.C and VIII.G of the 

final rule preamble of the CPP and Chapter 3 of the GHG Mitigation Measures TSD for the CPP 

Final Rule supporting the final CPP. 

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

Commenters stated these measures could be 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 

electricity.
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 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 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:

Commenters 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 BSER 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 infrastructure necessary to 

increase the dispatch of NGCC units to 70% capacity factor, as expected by the EPA under 

building block #2 of the GHG Rule, is suspect, at best, given the existing US energy market.

Commenters stated that financing adequate pipeline infrastructure to support the demand that 

will remain and ultimately grow, even after the retirement of coal-fired electric generating units 

occurs, is a challenge that has been neither addressed nor considered by EPA's proposed rule. 

Commenters stated that, traditionally, 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: Commenters 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 redispatch does not occur 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.
265

Response 12: The EPA disagrees that the specific adjustment to the proposal is required. In 

response to additional analysis and many comments, we have modified the proposal and RIA;

the establishment of 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, 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 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 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 

date by which EGUs could or should be retired or cease burning coal. Commenters 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. Commenters

proposed the following: Re-dispatch from coal-fired EGUs to natural gas combined cycle EGUs 

should occur upon the later of any of the following, if re-dispatch would occur prior to January 1, 

2030: (a) January 1, 2020; (b) 40 years after initial commencement of operation; or (c) 20 years 

after commencement of operation of major pollution control retrofit, such as selective catalytic 

reduction, flue gas desulfurization, or baghouses at any EGU if installation occurred prior to 

issuance of the final 111(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).

Commenters 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 January 1, 2020. Commenters explained that provision (b) 

establishes the proposition that re-dispatch from a coal-fired EGU will, for goal-setting purposes 

only, be treated as occurring on the 40th year from initial operation, reflecting the book life and 

typical amortization schedule for these EGUs, as the Environmental Protection Agency (EPA) 

acknowledged in the NODA (79 FR 64549). Commenters added that, as a practical matter, most 

coal-fired EGUs are more than 40 years old, so provision 1.b affects only a few EGUs in total 

throughout the United States.

Commenters explained that provision (c) establishes the proposition that re-dispatch from a coalfired EGU will, for goal setting purposes only, be treated as occurring no earlier than the 20th 

year from initial operation post installation of a major air pollution control retrofit, including 

selective catalytic reduction, flue gas desulfurization or baghouses, for any coal-fired EGU, as 

long as installation occurred prior to issuance of the final 111(d) rule. Commenters stated that, 
266

for small utilities (defined under the Federal 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 

from 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 noncatalytic reduction or electrostatic precipitators for any coal-fired EGU, as long as installation 

occurred prior to 2020. Commenters added that, as EPA acknowledged in the NODA, 20 years is 

the typical amortization schedule for large pollution control equipment retrofits (79 FR 64549). 

Commenters stated this proposal provides 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 entities that are less able to bear the costs of pollution upgrades by including certain 

smaller projects that while not as significant for large entities, are significant for such smaller 

entities. 

Comment 13: Commenters stated that while RGGI is currently operating in three RTOs (New 

England Independent System Operator (ISO), New York ISO, and PJM), setting up a similar 

system in other parts of the country could be very complex and time consuming.

Response 13: The EPA disagrees that the final rule does not give states sufficient time develop 

their plans, and the EPA does not require any state to develop a system like that described. In 

response to additional analysis and many comments, we have modified the proposal and RIA. 

The 111(d) final rule requires that states develop plans that establish emission standards for 

affected EGUs. We are providing states with 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:

Commenters 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 redispatch as well as the final implementation deadline.
267

Response 14: The EPA disagrees the final rule does not provide states with time to develop their 

plans; the start of the performance period has been postponed until 2022. The EPA disagrees 

with postponing the final performance date. The 111(d) final rule requires that states develop 

plans that establish emission standards for 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, 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 the CPP Final Rule supporting the final CPP.

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

General

Commenters stated there are significant problems 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. Commenters

supported the concerns expressed in the joint comments of the Arkansas Department of 

Environmental Quality and Arkansas Public Service Commission, including 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. 

Commenters stated that all of these issues need to be fully reviewed and addressed by EPA in the 

final rule. 

Commenters stated the EPA has not sufficiently considered barriers, which include operating 

constraints, permit limitations, contractual commitments to out-of-state service, the need for 

NGCC availability to support RE, and infrastructure limitations and the EPA's failure to consider 

these factors renders its Building Block Two analysis insupportable. 

2020 is too aggressive

Commenters generally stated the Proposal's schedule for re-dispatch by 2020 is unreasonable.

Commenters stated that, while AEPCO could seek to 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. 

Commenters 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. Commenters stated the 

impacts associated with retiring 70,000 MW of generation as projected by EPA are significant 
268

and will severely affect the reliability of electric service in this country. Commenters stated that 

sufficient replacement capacity cannot be built in time to meet the 2020 interim targets.

Commenters stated that achieving such dramatic increases in NGCC utilization effectively would 

require a fundamental redesign of the entire electric grid. Commenters stated 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 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. Commenters stated that making 

the appropriate infrastructure and system changes 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 stated that a significant increase in generation from existing NGCCs is needed in 

each of the four states Southern Company maintains retail operations, which will likely need to 

occur by 2020 and in a seamless manner. Commenters maintained that achieving a 70 percent 

capacity factor from existing NGCCs in Alabama, Florida, Georgia and Mississippi will require 

an increase in natural gas consumption of approximately 600 billion cubic feet ("Bcf") by 2020. 

Commenters noted that the Southern Company was the third largest electric generation user of 

natural gas in the country in 2012, utilizing 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. Commenters said 

that the EPA has ignored the significant natural gas pipeline infrastructure expansion needed to 

support implementation of Building Block 2. Commenters indicated that Southern Company 

currently holds about 2.5 Bcf/day of firm natural gas transportation to manage its natural gasfired resources, and that to secure 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. Commenters stated that Alabama, Florida, Georgia and 

Mississippi will need approximately 2.5 Bcf/day of additional firm transportation to achieve 

EPA's 70 percent capacity factor goal, and that this additional pipeline infrastructure will be 

costly and cannot be constructed in the required timeframe. Commenters added that these 

expansions will be complicated by the increase in natural gas demand from LNG exports and the 

industrial and transportation sectors. Commenters asserted that the EPA did not acknowledge the 

fact that significant additional pipeline capacity would be needed, nor did it factor in the cost of 

the additional pipeline infrastructure.

Commenters discussed the amount of time required to complete new pipeline projects. 

Commenters referenced an ICF International effort which compiled a list of gas pipeline projects 

for the years 2005-2014. Commenters noted that since 2005 there were 331 expansion, lateral, or 

reversal (ELR) projects completed. Commenters noted that projects took a maximum of 10 years 

to complete with a mean of 1.37 years. Commenters 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.

Commenters 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 a 
269

few years. Commenters stated the infrastructure and supply issues cannot be corrected between 

now and 2020 or 2030. Commenters 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.

Commenters recommended that changes be made to the rate at which Building Block 2 is 

deployed as part of the goal-setting process. Commenters 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. Commenters

stated that procuring adequate natural gas supplies to sustain a high level of utilization year 

round could mean, in the case of some states, building new pipelines or increasing the capacity 

of existing ones. Commenters 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. Commenters stated that, in 

contrast, the two other building blocks, 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 their final target levels in 2020. Commenters stated that, by this approach, the 

EPA implicitly "front loads" emission rate reductions associated with Building Blocks 1 and 2 

under the proposed rule. Commenters stated that, on average, across all states, two-thirds of all 

proposed reductions are reflected in the calculated 2020 emission rate, with the remainder spread 

over the period 2020-2029. While commenters agreed with EPA's conclusion that, over time, 

existing fleets have the technical capability of reaching a 70 percent capacity factor, commenters

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.

Commenters 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 model projects natural gas demand increasing. Commenters stated inadequate 

pipeline infrastructure, coupled with the retirement of practically all coal-fired generation, also 

produces significant reliability concerns for Florida.

Commenters 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 

industrial sectors. Commenters 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 2020, further supporting the need for 

additional time to facilitate planning for an orderly transition.

Commenters 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.

Commenters stated the Clean Power Plan provides inadequate time to add required pipeline or 

related resource capacity by 2020. Commenters stated the EPA did not analyze the effect of 

increased use of natural gas nationally. Commenters stated that such national use for baseload 
270

electricity generation could lead to increased market dislocations, such as seen in the winter of 

2013-2014. Commenters referred to a NERC report which indicated that increased natural gas 

use will require pipeline expansion and that additional pipeline capacity will be needed in 

Arizona, Nevada and the New England states.

Commenters 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 to 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. Commenters 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.

Commenters 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. Commenters supported consideration of natural 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. 

Commenters 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. Commenters stated that, given the time frame for submittal of state compliance 

plans and EPA approval, new gas supply will not be able to be in place by 2020. Commenters

stated that several states also have a significant fraction of their existing NGCC fleet located in 

regions where there is not adequate transmission to move the electricity to where it will be 

needed to replace generation from the reduced utilization of the state's coal-fired units. 

Commenters stated that building out the transmission grid is a very lengthy, costly effort and the 

Proposed Rule imposes building block 2 at the start of the compliance program.

Commenters added that increasing generation from existing NGCC units also may require 

electric transmission upgrades and expansions but, as NERC has noted, a transmission project 

can take 10 or more years to complete, from project identification to final certification and 

energization (citing Initial Reliability Review at 20). Commenters indicated that it may take even 

longer if a project crosses federal or tribal lands. Commenters asserted that these infrastructure 

constraints will challenge states' ability to achieve significant changes in dispatch before - and 

even after - 2020. Commenters noted that recognizing infrastructure 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. 

Commenters stated that as more natural 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 is 
271

currently being built, Commenters pointed out that there is growing public opposition to new 

natural gas pipelines. As an example, Commenters stated that Spectra Energy has proposed a 

465-mile, $3.5 billion pipeline and compressor station (the Sabal Trail Pipeline) which is 

planned to run through parts of South Georgia, and Green Law, Flint River Keepers and the local 

community are opposed to the pipeline and have challenged Spectra Energy and FERC officials 

on the proposed route and site for the pipeline and pumping station, with scores of negative 

comments from standing room only public information meetings. Commenters concluded that 

growing public opposition and obstruction to new natural gas pipelines and pumping stations 

may prevent adequate natural gas infrastructure from being built within the time frame proposed 

in the CPP to meet a 70% dispatch rate for NGCC by 2020. 

Commenters disagreed with the Proposal regarding pipeline capacity expansion in South 

Carolina. Commenters referenced the GHG Abatement Measures 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. Commenters stated this expansion is not possible in South Carolina during the time 

frame given by the EPA for compliance. Commenters 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. Commenters

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, additional pipelines or 

expansion of existing pipelines would be necessary. Commenters 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 period as proposed by the EPA. Commenters

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. 

Commenters 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. Commenters stated 

the Proposal'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.

Commenters 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 assumes Building Block Two will be fully implemented. Commenters 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 many parts of the 

West. Commenters stated that these kinds of investments in transmission and pipeline 

infrastructure, which typically require numerous, significant federal and state permits, rights-ofway, and other regulatory approvals, will be costly and lengthy. Commenters cited a NERC 

estimate that it takes three to five years to plan, permit, and build additional pipeline capacity. 

Commenters added that environmental permits to address water and endangered species issues, 

in particular, could prove difficult to obtain in some parts of the West. 
272

Commenters stated the EPA needs to account for the timeframes to develop and permit the 

necessary infrastructure for new NGCC. Commenters expressed concern that the 70% utilization 

rate calls into question the costs 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. Commenters requested the EPA 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 70% assumption.

Commenters 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. 

Commenters 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 Proposed Rule. Commenters 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. 

Commenters 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 demand created by the 

Proposed Rule. 

Commenters 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 the customers. Commenters 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. Commenters stated this cost adds onto to the typical $1.5 

million to $2 million per mile investment in a transmission line.

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 baseload capacity is not 

feasible by 2020. Commenters stated that, in Nevada, the assumption that there is "unused gas 

capacity" available to replace the coal/fossil generation is inaccurate and is a direct result of 

EPA's utilization of an annual capacity factor, instead of a peak capacity factor. Commenters

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 full 

compliance period. Commenters stated that granting additional time to shift away from higher 

carbon intensity fuel sources on a less disruptive implementation schedule can still achieve the 

2030 target for emission reductions, yet serve to ensure reliability and minimize consumer 

impacts.

Commenters stated that infrastructure and supply issues cannot be corrected between now and 

2020 or even 2030.

Commenters 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 expected 
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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.

Commenters stated, 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. Commenters 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. Commenters stated the EPA has not adequately considered the impact of these 

infrastructure constraints on states' abilities to increase NGCC utilization to 70 percent.

Commenters 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. Commenters stated these constraints include plant-level infrastructure 

constraints, lack of transmission lines, and inadequate gas supply, transport, and storage. 

Commenters noted the EPA also must consider the costs of overcoming these infrastructure 

constraints and stated that new 345 KV transmission lines cost $2.3 million per mile, without 

substation costs. Commenters stated new natural gas pipelines cost nearly $4 million per mile 

(See Christopher E. Smith, US pipeline operators sink revenue growth into expansion, Oil & Gas 

Journal (Sept. 2, 2013), available at http://www.ogj.com/articles/print/volume-111/issue9/special-report-pipeline-economics/us-pipeline-operators-sink-revenue-growth-intoexpansion.html). Commenters stated that, despite the significance of these costs, EPA has not 

considered them in its BSER analysis. Commenters 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. Commenters 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. Commenters cited a NERC report stating that 

significant transmission 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 

planning-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 some 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 transmission 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. 

Commenters 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. Commenters stated that natural gas is susceptible to supply 

constraints and extreme weather conditions such as the 2014 polar vortex. Commenters stated a 

NERC reliability study found higher than usual forced electric outages during the vortex, with 

outages concentrated at natural gas-fired units. Commenters stated re-dispatch could exacerbate 

these grid disruptions. Commenters stated that a NERC study found that increased reliance on 

natural gas-fired generation (1) would require greater electric transmission from NGCC units to 
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distribution networks 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 

construct, depending on voltage class, location, and labor availability. Commenters stated these 

realities collide with the interim targets beginning in 2020.

Commenters suggested more time is needed than the proposal allows for necessary pipeline and 

transmission upgrades in Arizona. Commenters stated that, while the Proposed Rule would 

provide little time to add required pipeline or related resource capacity by 2020, the lead time to 

permit, design, and construct new transmission lines in Arizona is approximately 10 to 12 years 

based on recent APS experience. Commenters provided the following statements supporting their 

position. 

• Comments sent by the Southwest Power Pool to the 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 transmission line 

can range from five to fifteen years, depending on the voltage class, location, and 

availability of highly skilled construction crews. 

• NERC described how the current and planned natural gas pipeline infrastructure 

in Arizona is inadequate for handling the increased gas demand due to the 

Proposed Rule. 

• The assessment of the transmissions system's short falls was independently 

confirmed by the PACE Global study which concluded: The lack of transmission 

import capacity limits load serving entities from 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. 

Commenters stated that, because it generally takes three to five years to permit, finance and build 

additional pipeline capacity, the first interim emissions reduction goals in 2020 may be too 

ambitious. 

Commenters stated the EPA's presumption that building block 2 can be implemented by 2020 is 

unrealistic and suggested Building Block 2 be phased in over the compliance timeframe. 

Commenters stated that, without further evaluating the implications on reliability, it must be 

assumed that additional natural gas capacity will be needed to comply with the rule. Commenters

stated the need for new natural gas generation can be estimated by looking at the difference 
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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 capacity. Commenters

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 100 MW CTs operating at 20% capacity factor. 

Commenters 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 the state will have an approvable plan prior to 2019. Commenters 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.

Commenters 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.

Commenters stated the EPA's proposed schedule is too aggressive to allow the most optimal 

solutions to emerge. Commenters stated that the EPA failed to consider that the development of 

incremental infrastructure projects can have adverse socio-economic, environmental, and land 

use impacts. Commenters stated this development will take many years to complete. 

Commenters suggested the EPA work with states develop a measured and reasonable 

implementation schedule, and minimize overreliance on natural gas.

Commenters 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. Commenters

referenced the proposal (79 FR 34857, 34862-63) and the GHG Abatement Measures TSD (3-10 

to 3-19), and stated the EPA appears to rely primarily on historical experience with NGCC 

generation increases. Commenters stated the EPA is calculating that NGCC generation in 2020 

could increase by approximately 47 percent from today's levels. Commenters stated the 81 

percent historic ramp rate (2005-2012), however, should not be measured against today's levels. 

Commenters stated that, because State plans will not be approved until the middle of 2017, at the 

earliest, it is not reasonable to assume that the entities responsible for compliance with state 

plans will undertake the substantial investments required for compliance until those plans are 

finalized. Commenters stated that, if full implementation of Building Block 2 by 2020 is 

assumed, states will have at most 2.5 years to achieve re-dispatch. Commenters 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 percent over seven 

years amounts to a ramp rate of 10 percent per year, the 47 percent increase that would result 

from compliance with BB2 over at most 2.5 years amounts to a ramp rate of 18.8 percent per 

year. Commenters added that, in Arizona, where a 95 percent increase in NGCC generation is 

assumed under BB2, the ramp rate would be higher still: at least 38 percent per year. 

Commenters stated that, because the NGCC starting point is now higher than it was in 2005, the 

amount of the increase in NGCC generation corresponding to any particular percentage increase 

will be higher now than it was then. Commenters stated that the amount, rather than the 

percentage, of the increase provides a better point of comparison for purposes of determining the 

system's capacity for change based on historical experience: while the 2005-2012 NGCC 
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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.

Commenters 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). Commenters 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. Commenters 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. Commenters stated that the first shifts therefore would have occurred 

where the existing transmission and fuel delivery infrastructure was already adequate. 

Commenters 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, commenters 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). Commenters 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. 

Commenters expressed concern that new infrastructure will require up to 4 or more years (for 

generation) to 10 or more years (for transmission) to complete grid and utility system planning, 

engineering, permitting, environmental and public reviews, construction, and startup timelines. 

Commenters noted that Intermountain West and Great Plains have numerous large baseload coalfired power plants sited in remote locations served by dedicated mines as fuel sources and stated 

many facilities have limited or no access to natural gas infrastructure. Commenters stated this 

brings new infrastructure challenges in terms of greater need for access to natural gas pipelines 

and new or expanded transmission lines, as well as increasing amounts of renewable generation. 

Commenters asserted that there is far too little existing natural gas infrastructure in South Dakota 

to make the development of additional natural gas-fired power plants feasible in the time allowed 

under the Proposed Rule. Commenters 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.

Commenters requested that the EPA remove the 2020 interim target from any final standard 

because the necessary time for potential modifications and additions to the existing natural gas 

infrastructure is not present in the CPP proposal. Commenters encouraged the EPA to recognize 

that Michigan's infrastructure must support electric generation and still provide its citizens with 

natural gas for home heating purposes. Commenters 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 acquire new right of way 

access attract a great deal of public interest, and require significant time to develop prior to any 

construction activities, and stated the current proposed timeline simply does not allow for the 
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proper build out of the infrastructure to accommodate EPA's accelerated dispatch of NGCC 

plants. Commenters 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. 

Commenters state the "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 requirements. 

Commenters 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.

Commenters recommended that EPA extend the start of the compliance period (e.g., 5 years after 

EPA approval of a state's compliance plan) to mitigate the constraints of building block 2. 

Commenters 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. Commenters referred to the Pace Global 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. 

Commenters 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. Commenters stated this means 

that it may simply be infeasible to add the required capacity to compensate for derates and at-risk 

units by 2020. Commenters 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 emissions goal. 

Commenters stated that, in order for the City's two natural gas combined cycle (NGCC) units to 

achieve and maintain a 70 percent capacity factor under Building Block #2, the City would be 

required to sell a significant portion of their output off-system. Commenters stated that 

significant transmission investment on the City and adjacent systems would need to be made to 

allow for this level of export from the City's system and it is doubtful that this level of 

transmission could be constructed in time to support the interim CO2 targets.

Commenters 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. Commenters 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. Commenters 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 emissions goal. Commenters

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.
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Infrastructure--pipelines

Commenters stated the EPA's timeline does not take into account the time required to address 

infrastructure concerns. 

Commenters stated that, by requiring the transition from coal to NGCC, utilities will need to 

upgrade the existing pipeline infrastructure and construct new NGCC generation facilities. 

Commenters 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. Commenters stated that, while 

the CPP has modeled plant closures and the amount of natural gas generation that will be 

required by the rule, the EPA should take the next step and model the additional plants that will 

be constructed and pipeline improvements that will be required to meet existing plant capacity 

factors and determine the environmental and economic impact of the projects.

Commenters 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).

Commenters stated that building block 2 has not been adequately demonstrated because redispatch 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. 

Commenters indicated that this problem is not hypothetical; it is a reality, as evidenced by 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. Commenters

asserted that increasing the capacity factor of NGCC units to 70 percent will only exacerbate the 

problem. According to the commenters, 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). Commenters noted that states must begin to achieve 

emission decreases by 2020 to meet their respective interim goals, and opined that this does not 

allow for enough time to build the infrastructure needed to implement building block 2.

Commenters asserted that the EPA has not adequately addressed in the record these significant 

barriers that exist to ramping up the use of natural gas and renewables in the electricity 

generating sector by 2020 and 2030. Commenters 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. 

Commenters stated that the EPA has not demonstrated how the sector will be able to ramp up 

natural gas and renewable capacity in time to meet the deadlines in the Proposed Guidelines 

given the many years needed to plan, permit and 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 infrastructure 

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 emissions 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. 

Commenters 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 Computation TSD at 18 (noting that in calculating state goals, only 

"the RE and EE assumptions change for each year from 2020 through 2029")). Commenters

stated that delaying full implementation of Building Block 2 in order to allow for necessary 

infrastructure 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, the commenters believed

that most states will need to implement necessary infrastructure improvements to accommodate 

Building Block 2 by 2020 or very soon thereafter. According to the commenters, this timeline is 

likely infeasible, given that gas pipeline projects often require a decade to complete, in part 

because the timeline for environmental permitting can be lengthy.

Commenters stated that although significant gains have been made in the past several years in 

locating new sources of natural gas, little has been done to improve the infrastructure needed to 

connect this new gas to power plants. According to the commenters, INGAA predicts that the 

natural gas industry will need to construct 2,000 miles per year for the next 20 years of new gas 

transmission mainlines and laterals to meet demand (citing The INGAA Foundation, Inc., 

"Jobs& Economic Benefits of Midstream Infrastructure Development: US Economic Impacts 

Through 2035," at ES-1 (Feb. 15, 2012), available 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/Foundation-Reports/2035Report.aspx). Commenters 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, Association of Oil Pipe Lines, International Association of Geophysical 

Contractors, Interstate Natural Gas Association of America, Utility Air Regulatory Group, and 

Utility Water Act Group on Three Endangered Species Act Critical Habitat Proposals of the U.S. 

Fish and Wildlife Service and the National Marine Fisheries Service Published on May 12, 2014, 

at 5 (Oct. 9, 2014), available at http://www.ingaa.org/File.aspx?id=22680). For perspective, 

commenters added that there were about 306,000 miles of gas pipeline in use in the United States 

at the end of 2008 (citing EIA, "Estimated Natural Gas Pipeline Mileage in the Lower 48 States, 

Close of 2008," available at 

http://www.eia.gov/pub/oil_gas/natural_gas/analysis_publications/ngpipeline/mileage.html).

Commenters stated the pipeline and infrastructure availability assumptions by EPA are 

unrealistic and the time frames set forth in the Proposal will not allow for the development of 
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pipeline infrastructure needed to meet the high capacity demand necessary for baseload 

generation. 

Commenters 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. Commenters referenced the NERC Initial Reliability Review and stated 

that new natural gas pipeline construction takes, on average, three to five years.

Commenters stated the EPA has failed to adequately evaluate the redirection of power given the 

current grid availability and resource location, consequences of such a significant increase in 

natural gas consumption, and the timeframe that necessary infrastructure improvements will 

require. Commenters stated that increased transportation capacity also requires compression and 

pumping infrastructure and working gas storage capacity. Commenters 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. Commenters stated that, 

since the required natural gas buildout would occur in the same period, it is very likely that the 

United States suppliers would not be able to handle the numerous simultaneous projects. 

Commenters concluded that building this volume of new natural gas is not feasible by the 

Interim Goal, possibly not even before the Final Goal. 

Commenters 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. Commenters referenced a 

NERC report and stated that, for many existing NGCC units, there is insufficient pipeline 

infrastructure to support operating year-round at a 70 percent capacity factor. Commenters stated 

these infrastructure limitations are exacerbated by the fact that the proposed state goals are 

calculated assuming that states will fully 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. Commenters 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. Commenters noted that 

during past winters, pipelines were fully subscribed and experienced winter constraints.

Commenters 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. Commenters stated the EPA failed to consider the impact of the potential large increases in 

interruptible natural gas demand on the opportunity to build new natural gas infrastructure. 

Commenters stated the EPA failed to adequately consider the time it takes to build the additional 

natural gas infrastructure necessary to achieve the target capacity factors set in Building Block 2. 

Commenters stated that, according to the current schedule, EPA will be approving, or 

disapproving, state plans between 2017 and 2019 and compliance with the proposed guidelines 

begins in 2020. Commenters stated that, presuming a state plan is approved, there will be one to 

three years to come into compliance with the state plans. Commenters stated EIA estimates that 

an interstate natural gas pipeline takes approximately three years to complete between 

announcement and completion. Commenters noted there may be additional time necessary to 

identify the need for additional pipeline and other prior planning actions by the pipeline operator 
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and, in individual circumstances, due to localized sitting and permitting issues, construction may 

take even longer. 

Commenters stated there is not enough existing NGCC in this country to make up for the forced 

reductions in coal generation. Commenters stated the gas supply and infrastructure in this 

country are not available or reliable enough to serve all gas generation that will be needed. 

Commenters stated this leaves a significant gap between energy 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.

Commenters stated that, by the summer of 2017 pipelines will have the capacity to deliver into 

Peninsular Florida approximately 5.6 billion cubic feet per day, although not all this capacity is 

deliverable to all major load centers and generation locations. Commenters stated that the siting 

and construction of incremental pipeline capacity and delivery laterals will be necessary to 

accommodate dispatch of these resources. Commenters stated this development will take many 

years to complete, cost Floridians hundreds of millions of dollars, and place Florida in a dubious 

position with an overreliance on a single fuel which creates reliability deterioration and cost 

increases.

Commenters stated that the natural gas infrastructure is not adequate in Georgia to support 

current demand and a 70 percent dispatch rate for NGCC. Commenters indicated that although it 

has been demonstrated that a 70% dispatch rate can be achieved in peak hours, this scenario is 

based on base loads being achieved by other EGUs - if 70% dispatch of NGCC becomes part of 

the base load generation, it would reduce the available amount of standby, peak demand, and 

emergency based power. Commenters 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 time that natural gas demand for residential heating 

peaked. Commenters asserted that with the proposed 70% dispatch target, such future demands 

may have to be met with less efficient natural gas simple cycle turbines which would put 

additional stress on natural gas residential heating supplies.

Commenters stated that, without any certainty as to whether the necessary pipeline capacity 

exists or will exist, EPA should reconsider Building Block 2. Commenters stated that, not only is 

gas pipeline capacity already strained during peak demand periods, but it remains uncertain 

whether additional, sufficient gas pipeline infrastructure will be built, either in the near or longterm future, to allow the levels of re-dispatch projected by EPA. Commenters stated the EPA 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. Commenters referred to 

NRECA's comments that the EPA has failed to properly account 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. Commenters 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. Commenters concluded that the notion that 
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all of this new capacity can be planned, designed, permitted and installed by 2020 is arbitrary 

and capricious. 

Commenters stated the EPA failed to give adequate consideration to potential infrastructure 

challenges from significantly increasing NGCC utilization. Commenters stated natural gas 

pipelines have limited carrying capacity and in many parts of the country natural gas is utilized 

for both electricity generation and home heating. Commenters stated substantial, coincident 

increases in natural gas utilization in the power sector could strain limited pipeline capacity. 

Commenters 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 reach consumers. 

Commenters stated that during the 2014 Polar Vortex our nation's natural gas supply and existing 

infrastructure to transport gas to electric markets was strained to the breaking point. According to 

the commenters, assuming additional output as a 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. 

Commenters asserted that a more appropriate target would be in the low 40 percent range for CF 

of NGCC units.

Commenters stated the CPP requires significant projects not available in 2012 or before, and 

cannot be considered "adequately demonstrated". Commenters 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. Commenters stated the proposed rule is essentially requiring expansion 

projects which have not yet been proposed or permitted.

Commenters expressed concern that the EPA analysis does not address the length of the 

regulatory approval process for the siting of new pipelines. 

Commenters stated that, even if existing NGCC units are capable of running at 70 percent or 

greater capacity factors, gas pipeline capacity may not be sufficient to provide the gas volumes 

needed to operate at these high capacity factors, especially in the short term before additional 

infrastructure can be built. Commenters stated the lack of available natural gas infrastructure will 

limit the availability of natural gas for all consumers, including NGCC power plants and will 

make it difficult for NGCC power plants to achieve the capacity factors EPA assumes.

Commenters stated the proposed rule does not recognize the significantly long lead-time that 

permitting and building new natural gas pipeline capacity can take. Commenters stated that most 

interstate pipeline 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. Commenters stated 

that, in order for pipeline capacity constrained states such as Arizona to utilize more gas, new 

pipeline projects would need to be constructed. Commenters 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.
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Commenters stated that new pipeline infrastructure will take a significant amount of time and 

money to site and build, while States and utilities are up against EPA's compliance deadlines. 

Commenters stated there are many moving parts in this plan to assuring 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, commenters stated the 

EPA timelines are too tight to 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--transmission

Commenters suggested the EPA's timeline does not take into account the time required to 

address infrastructure concerns. 

Commenters 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 grid operator urges EPA to 

delay carbon plan implementation by 5 years.

Commenters stated the EPA should allow for time to study existing generation mixes and 

transmission constraints anticipated by the final rule in order to modify the transmission system 

to eliminate the need to operate higher emitting generation to maintain system stability. 

Commenters 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. Commenters stated that the emission rates of simple cycle natural gas generation are 

significantly higher than NGCC and rival that of base loaded coal. Commenters stated that 

frequent Transmission Load Reduction (TLR) events have required the reduction of generation 

from renewable generation sources, NGCC and coal to stabilize the system. Commenters stated 

the requirement of the CPP to generate electricity using NGCC and renewable sources without 

time to study the impacts to the transmission system will create even more reliability and system 

efficiency problems. 

Commenters stated the EPA should allow that, upon a demonstration that significant 

transmission upgrades are reasonably necessary for a state to operate its NGCC fleet at the 

average annual capacity utilization rate within the Final Rule, and that no reasonably sufficient 

alternative is available to gain the same carbon reductions, its goal or interim goal should be 

adjusted to account for the time needed for such upgrades. Commenters 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 cost 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. 

Commenters, quoting EPRI's comment letter, argued 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 across 
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many systems are need such that time lines for commissioning of new transmission facilities may 

be delayed.

Commenters stated that growth in demand for natural gas from electricity generation and other 

markets is expected and this increased demand will have an impact on the availability and price 

of natural gas supply and transportation. Commenters 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 suppliers and pipelines to meet this growing demand. 

Commenters stated the result will be an increase in natural gas price volatility and a decrease in 

availability, ultimately leading to substantially higher commodity costs and electric rates for 

Floridians. 

Commenters 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. Commenters 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. Commenters 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. Commenters noted a recent 

example on the Georgia Integrated 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. Commenters 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. Commenters stated the EPA has not adequately accounted for and 

addressed these considerations in its proposed 2020 start date for state interim goals. 

Commenters stated the EPA failed to account for 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. Commenters stated that each of these issues requires a substantial amount of time, 

making it questionable that transmission (and pipeline) capacities will be sufficient to meet the 

schedules set forth in the Proposal. Commenters stated that delays can be particularly acute for 

changes in cooperative-based distribution and transmission facilities, as the provisions of the 

National Environmental Policy Act are often triggered due to the enhanced Federal connections.

Commenters expressed concern that, even after a plant is constructed, there is no assurance that 

the natural gas transmission and distribution and electric transmission infrastructure required to 

properly distribute power from the plant would be available. Commenters stated that, in the past, 

independent power producers in Louisiana experienced unfavorable results when they sited 

generation prior to establishing necessary transmission, and it is unlikely that LUS or any other 

municipal entity could receive sufficient project financing if transmission was not guaranteed.

Commenters stated that the analysis the EPA conducted of the existing electric transmission 

networks is procedurally inadequate and significantly underestimates the time required to modify 

transmission systems and the complexities involved. Commenters stated the targets and timelines 
285

required in the Proposed Rule do not accommodate the timelines and regulatory realities 

involved in expanding electric transmission capacity. Commenters stated that modifying the 

electric transmission infrastructure is a complex, costly, and time consuming process that 

involves many state and federal agencies, electric utilities, and the public. Commenters stated 

that, due to cost, entities are unlikely to risk the expense of expanding electricity transmission 

capacity if the electricity is required to be displaced by energy efficiency in a few years.

Commenters stated that, once the EPA accepts state implementation plans under the proposed 

rule, it will take about two or more years for generation and transmission entities to analyze the 

potential requirements of their systems due to all the different possible combinations under the 

EPA's proposal and subsequently plans for additional electric transmission must be developed 

and analyzed in an open regional planning process that usually takes an additional two years. 

Commenters stated that every change requires new analysis, and the building resources market 

can change while the analysis is being conducted. 

Commenters stated that, in the best circumstances, a four- to five-year planning period will be 

necessary before an approved transmission plan can be achieved and the transmission 

construction process can begin; yet this optimistic timeframe may be inadequate for a State to 

meet EPA's proposed goals. Commenters stated some projects take 10 years to build, while 

others never get built, such as the Potomac-Appalachian Transmission Highline (PATH) project, 

which was proposed to address numerous electric reliability concerns forecast for the MidAtlantic region in the mid-2000s but was suspended in 2011. Commenters stated that large 

projects like the Alaska pipeline can take decades of discussion and planning, and can require a 

decade to permit and construct once a route is chosen while less controversial and smaller 

pipeline capacity can be built within a year or so if transportation costs justify construction and 

permits are obtained in a timely manner.

Permits

Commenters expressed concern that both transmission lines and natural gas pipelines require 

many layers of permitting and years of regulatory approvals, often at federal, state and local 

levels. Commenters believed that the Proposed Rule is unrealistic in assuming that this 

infrastructure will be in place by 2020 for states to begin implementing all four building blocks. 

Commenters noted that a large number of permits, 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 permitting 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.

Commenters stated that the EPA must allow for construction of new generation. Commenters

indicated that the CPP provides states with at most 2 years and at minimum 6 months before the 

beginning of the compliance period, which the commenters believed is wholly inadequate where 
286

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 

pipeline, 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 Section 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. Department 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 divert 

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 rightof-way lease agreement; and an air quality permit if disturbed 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-BD35-4BC8-83C8-

32BAE959BF/0/GenericTransmissionLinePermit.pdf.)

Commenters 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. 2013), 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 the siting of transmission lines and each may impose 

different permit or other authorization requirements and conditions.

Commenters stated the EPA does not address the time needed to complete critical project tasks 

before pipeline construction can begin, such as an extensive public involvement process, 

regulatory proceedings before local committees and commissions, obtaining rights-of-way, 

acquiring permit authorizations, conducting environmental assessments, and procuring bank 

financing. Commenters stated these activities are a necessary part of any major energy 

infrastructure project and must be accommodated in EPA's projected timelines for achievement 

of emissions reductions under at 111(d) program.

Commenters also stated that in order to take 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. Commenters noted that if the pipelines will 

cross federally-owned lands, approval of permanent rights-of-way from federal land managers 

must be obtained and, because there is no streamlined process for obtaining such federal 
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approvals, their approval can take years, which could impede the ability to expand the network 

of natural gas pipelines to deliver gas for power generation.

Commenters stated that it can take 3 to 6 years to permit and build new pipelines (citing Initial 

Reliability Review at 10). Commenters 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 agencies as well as tribal and local 

governments. 

Commenters 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.

Commenters 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 Studies so the necessary pipeline infrastructure can be built. Commenters stated that, 

without such an initiative, the Federal government is simply setting the states up to fail.

Commenters stated that planning, permitting, and 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 bringing natural gas 

pipelines online. Commenters asserted that the EPA failed to study existing natural gas 

transmission constraints, contractual arrangements, and other factors including unit design or age 

of equipment that could limit the feasibility, reliability, or sustainability of running individual 

units at such high capacity factors. Commenters 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 contemplated 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 commenters, the proposed rule assumes the entire re-dispatch is accomplished 

beginning in 2020, resulting in approximately 77% of Texas's final emissions reduction be 

achieved by 2020. Commenters 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. Commenters stated 

that the EPA offers no analysis on the possible impacts of requiring increased use of natural gas 

generation. Commenters indicated 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. Commenters 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." Commenters added that the GAO report did 
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not have data for the time frames required to obtain intrastate gas pipeline permits. Commenters

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, 

state, 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-dispatch. 

Commenters 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. 

Commenters stated that, even where systems are connected and integrated, 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.

Commenters 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 create significant 

electric reliability issues in many parts of the grid. Commenters 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 demands on their capacity that will 

accompany a large increase in NGCC generation. Commenters 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 emergencies 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 generating sources. Commenters 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. Commenters 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.

Commenters stated that cost allocation issues will need to be addressed, rights-of-way must be 

acquired from landowners, and permits must be obtained. Commenters stated that public 

opposition and lawsuits seeking to stop or move planned transmission are also common and can 

add substantial delay and expense to transmission projects. Commenters 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. Commenters stated that there are more problems with siting 
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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 disagrees 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 

comments, 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 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, 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 the CPP Final 

Rule supporting the final CPP. 

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

Commenters stated that significant amounts of new transmission infrastructure will be needed to 

accommodate Building Block 2, particularly in areas where load has been served by coal-fired 

EGUs and NGCC units are located a great distance away. Commenters 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. 

Commenters 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. Commenters 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 its proposed Building Block 2 

target is achievable. Commenters provided the following additional comments regarding TriState's transmission infrastructure experience.

• Siting and permitting transmission is a complex and controversial process that 

requires a large number of permits, consultations, and approvals from multiple 

federal, state, and local government bodies and private parties before construction 

even begins. The timeline for a transmission project depends on completion of 

planning studies and technical analysis, real estate availability (negotiating rightsof-way or exercising eminent domain authority), procurement of long lead time 
290

equipment, environmental permitting requirements, public opposition, regulatory 

approval, and opportunities for tie-in 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 that 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 the San Luis Valley 

Calumet-Comanche project. 

• Tri-State's 200,000 square mile service territory overlays federal, state, tribal, and 

private lands, and any transmission projects are 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 Environmental 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. 

• Locating 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 involved 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 process. 

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 utilizing 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 1997 and did not end until 

2006. Various New Mexico landowners refused Tri-State access to their land for 
291

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 federal 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 energy. 

• 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 unreasonable 

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. 

Commenters 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 the customers. Commenters stated that new NGCC units require 

additional electric transmission, which requires substantial time. Commenters described in some 

detail the Minnesota CapX 2020 project, the largest expansion of the high voltage transmission 

line in the region in over three decades, and stated that, while CapX initiated the Minnesota 

regulatory proceedings in 2007, it will have taken a total of eight (8) years to move from the 

initial regulatory process to energizing the lines, and this for a group of projects that were 

reliability and wind-generator outlet driven where all of the utilities in the region backed the 

project.

Commenters stated the Proposed Rule also fails to 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. Commenters referred to the CapX 

transmission upgrade and noted the project has taken over a decade from design through 

construction. Commenters stated the Proposed Rule overlooks this issue in calling for higher 

capacity factor output of natural gas EGU's into an electric grid not designed for those units to be 

baseload units. Commenters stated the Final Rule needs to take this into account to give 

Minnesota the flexibility to ramp up its required carbon reductions. Commenters stated that, with 
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the Final Rule being issued in mid-2015, history shows transmission facilities will not be online 

until 2026 or later.

Commenters stated the EPA has not considered the time involved in the normal FERC regulatory 

siting process. Commenters stated the transition to gas-fired generation envisioned in BB2 is 

intrinsically tied to an increase in construction of pipelines to transport that gas. Commenters

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. Commenters stated this two-year period is in addition to 

the time spent developing a proposal and preparing an application as well as the time for the 

actual construction of the pipelines themselves. Commenters urged the EPA to take pipeline 

construction timelines into consideration in designing BB2 goals. Commenters provided the 

following related information.

• 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 transportation 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 certificate 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 

publishes, 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 participates 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 plans, 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 applicant did not pre-file, FERC 

then begins the environmental review process that includes many of the same 
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steps of the pre-filing process. In either case, an environmental assessment is 

typically prepared and a more extensive environmental impact statement is also 

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 projects 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 review 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 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 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 the 
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SIP development schedule imposed by EPA, it could be as late as July 2018 (with allowed 

extensions) before it is clear what a regional SIP might require. Commenters asserted a state SIP 

could be expected to be in place not earlier than 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 and a half years would remain to plan, permit, procure, and construct a 

generating unit. Commenters stated that a schedule this tight would be difficult for any entity to 

achieve. Commenters stated it is particularly impractical for electric cooperatives, which 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 still 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 expended 

during this period will be of no value if the Rule is found not to have any legal 

basis. 

• July 1, 2017- Final SIPs issued and compliance requirements are defined. Begin 

preliminary design process required for permitting. 

• January 1, 2018- Begin permit application process. Expect application approval 

process to take 12-18 months (or longer if the 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 could 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 operation 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 compliance requirements and forced unit 

retirements regionally and nationwide. Commenters stated the information provided above 

clearly demonstrates that the retirement of RPS-2 by 2020 is impractical for LUS.

Commenters recommended that EPA extend the start of the compliance period (e.g., five years 

after EPA approval of a state's compliance plan) to mitigate the constraints of building block 2. 

Commenters stated this major shift in generation to NGCC over the next five years is infeasible 

for many existing units because of technical limitations, gas pipeline and electric transmission 
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infrastructure constraints, and/or regulatory limits. Commenters stated that, even if existing 

NGCC units are capable of running at 70% or greater capacity, gas pipeline capacity or 

transmission infrastructure may not be sufficient to provide the gas volumes needed to operate at 

these high capacity factors, especially in the short term before additional infrastructure can be 

built. Commenters stated that gas supply infrastructure constraints 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.

Commenters 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. Commenters 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 

secure and put in place. Commenters 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. Commenters 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 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 disagrees we have not 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 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 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. 
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The following are summaries of the specific public comments under this comment:

Area-specific issues

Commenters disagreed with the EPA's statement that "Re-dispatch for GHG abatement purposes 

would require one net MWh of a lower emitting technology displacing one net MWh of 

generation from higher emitting technology" (GHG Abatement Measures TSD at 3-6). 

Commenters 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. 

Commenters stated the location of the generation is important in replacing net megawatts due to 

transmission system constraints and grid losses. Commenters stated the EPA inappropriately 

assumes that an NGCC with excess capacity exists in a location identical to the coal generation it 

replaces. Commenters stated that, because the City of Tallahassee has limited transmission 

import and export capability, the City cannot re-dispatch its excess NGCC capacity, when it is 

available, to provide replacement power for coal fired generation at other locations within 

Florida. Commenters suggested the EPA 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. Commenters 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 electricity units located in different 

parts of the state. Commenters 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 construct 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.). 

Commenters stated the dispatch decisions required by Building Block 2 are precisely the sorts of 

planning changes that will make efficient seam coordination increasingly difficult. Commenters

stated that, in the case of Indiana, there are multiple RTOs that manage the dispatch of electricity 

generated within the state. Commenters stated a PJM report on capacity imports and exports to 

and from the MISO explains that "reliability requires the capacity construct and system planning 

to be consistent with actual grid operations." Commenters stated the dispatch decisions required 

by Building Block 2 are precisely the sorts of planning changes that will make efficient seam 

coordination increasingly difficult. 

Commenters stated the EPA does not take into account the methods utilized to dispatch EGUs 

under the FERC-approved SPP integrated market system. Commenters stated the EPA 

incorrectly assumes that the absence of existing NGCC EGUs in Kansas will not impact the 

energy produced by affected Kansas EGUs. Commenters stated that, for the states in which SPP 

members are located it will be necessary to 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 those states. Commenters 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-owners. Commenters stated that Sunflower has modeled the net effect of this re-
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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. Commenters stated the ultimate utilization 

of Holcomb 1 may approach a 35% capacity factor minimum load for the technology. 

Commenters 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 purchased from the pool3. 

Commenters noted that these effects on Sunflower member-owners and their consumer-owners 

occur all the while there are no NGCC facilities located in Kansas. Commenters stated that, 

because EPA has done a separate analysis of each of its building blocks in each individual state it 

effectively ignores these kinds of real integrated market impacts on Kansas ratepayers.

Evaluate as an integrated whole

Commenters stated that the EPA's expectation of 70% re-dispatch of natural gas capacity for the 

purposes of determining state goals is unreasonable because the dispatch of power is controlled 

by various RTOs. Commenters stated RTO dispatch is done with the express purpose of 

maintaining grid reliability in the most economical manner possible, and that artificial and 

inflexible dispatch goals are not a reasonable variable to introduce to these systems. Commenters

suggested that the EPA has not adequately accounted for how market rules in a market based 

system may complicate re-dispatch and that the EPA should not assume that limiting operation 

of coal-fired EGUs will force re-dispatch considering the complicated economics that will 

inevitably develop when the four building blocks are combined. Commenters stated the EPA 

should direct states in RTO 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.

Commenters 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, existing energy and 

fuel supply contracts, transmission rights or transmission service reservations. 

Commenters 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. Commenters added that while the 

NODA points to discrepancies and limitations of the proposed guidelines, none of the new 

proposals provide credible solutions. Commenters 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.

Commenters 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. 

Commenters stated that many different types of system constraints may make it impossible or 

unreasonable for state NGCC fleets to dramatically increase their utilization rate. Commenters
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referred to a 2010 CRS report (Stan Mark Kaplan, Displacing Coal with Generation from 

Existing Natural Gas-Fired Power Plants, CRS, Jan. 2010) which concluded that the ability of 

existing natural gas plants to displace coal generation depends on many factors, including: the 

amount of excess capacity in the natural gas fleet; the operating patterns of coal and gas plants 

and the system's degree of flexibility to change 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 natural gas where it is needed. 

Commenters stated the CRS report demonstrates the importance of evaluating the electric power 

system as an integrated whole that comes with various locational constraints. Commenters stated 

that an assessment of the "excess" natural 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. Commenters stated that each portion of the system, while to 

some extent interrelated, is unique, with specific resources designed to fill specific needs; thus, 

the tailored nature of the system makes one-size-fits-all solutions problematic. 

Commenters stated that the current methods of load dispatching and future reserve margins and 

transmission loading need to be assessed for this 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. Commenters

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. 

Commenters stated that it is not clear that EPA factored these situations, or the impacts of 

increased NGCC utilization on "must run" resources, into its re-dispatch analyses. Commenters

stated EGU and electric system constraints may make increased NGCC utilization unachievable 

in the timeframe stipulated by the EPA. Commenters cited a 2010 Congressional Research 

Service (CRS) report as concluding that the ability of existing natural gas plants to displace coal 

generation depends on many factors, including: 

• The amount of excess capacity in the natural gas 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 ability of the natural gas supply industry to deliver larger amounts of natural 

gas where it is needed. 

According to commenters, 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. Commenters stated that 

physical (infrastructure) and operational limitations, as well as the location of each plant in 

relation to other generation facilities and load, must be considered. Commenters indicated that 

these locational limitations matter as much as unit size or technical capabilities, and gave the 

example that some NGCC units that theoretically could run at higher capacity factors will 
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necessarily be hindered by transmission constraints. Commenters 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 commenters, 

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 be factored into any plans to replace coal with natural gas (CRS Report at 17). 

Commenters stated that equally important is whether the two units are dispatched by the same 

transmission operator. According to the commenters, this concern was raised by Montana Public 

Service Commissioner Kavulla when he noted that two plants in the same state can be dispatched 

by different entities, which means that the two 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." 

Commenters stated that there are other system constraints that can make it difficult to displace 

coal with existing natural gas-based generation. Commenters noted that it is possible that 

increasing the capacity factor of existing NGCC units would involve the closure of coal-based 

"must run" resources that could put reliability at risk. Commenters also indicated there may not 

be enough actual NGCC spare capacity to achieve the necessary levels of fuel switching that are 

included in the proposed guidelines. Commenters 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 difficult to comply with the interim targets. According to the 

commenters, 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 demands experienced in the middle of the summer." Commenters 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 - while such capacity 

may be available to displace some coal generation during winter months, this "excess" capacity 

will be needed to meet summer peak demand. Commenters added that increasing existing NGCC 

generating capacity may also not be possible due to conflict with ozone attainment plans and 

unit-specific run-time limitations in NGCC permits in areas such as Southern California that are 

non-attainment for some criteria air pollutants. 

Commenters added that the EPA has not addressed the effect that increased existing NGCC 

capacity factor will have on the other Building 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.

Commenters stated an assessment of the excess natural gas generating capacity is not enough. 

Commenters stated that physical constraints are not uncommon in the delivery of natural gas 

during very cold months as the transmission to Empire's natural gas generation facilities has been 

interrupted by frozen compressor stations. Commenters stated that, even when all natural gas 

pipeline infrastructure is operating properly there are numerous instances where even firm 

transport contracts get curtailed during extreme weather events. Commenters stated that while 

Empire experienced recent curtailments on the natural gas pipeline to its generators and had to 
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burn oil as an emergency backup, not all NGCC's are equipped with the ability to use oil backup. Commenters stated new infrastructure and long-term firm transportation contracts will be 

needed to meet the 70 percent CF computation for the states. Commenters stated that natural 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. Commenters stated the ability of 

existing natural gas plants to displace coal generation depends on many factors, and 

demonstrates the importance of evaluating the electric power system as an integrated whole that 

comes with various locational constraints. Commenters supported the four recommendations 

submitted by the SPP in their comments to the Proposed 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 reliability 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. 

Commenters stated the EPA needs to more fully analyze the interaction between and among 

electric generation, wholesale electricity markets and the natural gas and Commenters stated the 

EPA did not take into consideration time constraints required to physically realign the natural gas 

supplies and transmission and distribution infrastructure needed to accommodate the 2030 

requirements when assessing the 70 percent capacity ability of the NGCC fleet. Commenters

stated the EPA did not take into consideration the time required to finance, permit, and construct 

adequate generation and transmission infrastructure and new NGCC EGUs and should allow 

additional time needed to meet compliance. Commenters stated the EPA should take into 

consideration the planning and construction of electric transmission upgrades which will be 

required as part of the solution to comply with the Proposed Rule. Commenters stated the SPP 

indicates these upgrades could take up to eight and one half years and cost up to approximately 

$2.3 million per mile for new 345 kV transmission lines, excluding substation costs.

Work with power regulators

Commenters 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. 

Commenters agreed with the EPA that natural gas pipeline capacity, with feasible amounts of 

expansion, can meet the needs of increased natural gas use to reduce carbon pollution. 

Commenters noted that the EPA has found average monthly fleet-wide NGCC utilization rates 

have reached 65%, showing that the pipeline system can currently support these rates consistent 

with the increased use of natural gas as BSER for an extended period (79 FR 34863). 

Commenters 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). Commenters 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. Commenters 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.

Commenters encouraged the EPA, before it proceeds with a final rule, to consult with federal 

and state agencies with greater expertise in operation of the country's natural gas transmission 
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system (e.g., FERC and the United States Department of Transportation Office of Pipeline 

Safety) to gain a greater 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. Commenters stated this

understanding is fundamental to establishing the technical feasibility of Building Block 2. 

Commenters expressed concern that the high proportion of federal, state, and tribal lands in the 

Western U.S. represent unique challenges to timely completion of new energy-related projects.

Commenters stated that, given the warranted 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 related to the dispatch of electricity. Commenters

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. 

Commenters stated that, according to the Independent System Operator for New England (ISONE), the factors contributing to natural gas fuel availability issues are inadequate infrastructure, 

unreliable fuel arrangements, limited storage, and out of sync markets. Commenters stated that, 

under the EPA's model, New England as a whole is projected to have no remaining oil or coal 

resources, which would be highly detrimental to the region's reliability as well as customer rates. 

Commenters requested the EPA to work with reliability experts, states, and industry stakeholders 

to undertake a detailed, comprehensive analysis of potential reliability impacts of the CPP before 

it is finalized. 

Commenters stated the EPA's final guidelines must consider the role that FERC, NERC, 

RTOs/ISOs have in assessing technical feasibility and reliability implications of Building Block 

2. Commenters 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.

Commenters stated that NREA members feel it is imperative that EPA consult with Federal 

Energy Regulatory Commission (FERC), North American Electric Reliability Corporation 

(NERC) and Regional Transmission Organizations to determine the impacts on reliability, cost 

stabilization and national security issues. Commenters 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. Commenters stated a major 

concern in Nebraska regarding reliability is the need to meet consumer loads primarily with 

natural gas and renewable generation. Commenters 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 EPA 

Proposal.

Regional feasibility studies

Commenters stated the EPA should conduct a state-by-state study to determine the time required 

to finance, permit, construct and commission new NGCC EGUs taking into account what NGCC 

units can burn oil in order to reach the 70 percent capacity goal in Building Block #2. 

Commenters stated that the CPP will result in increased costs. Commenters stated each state in 
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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 associated costs. Commenters stated the EPA 

should take other environmental concerns into consideration when establishing NGCC capacity 

factors and the economic analysis for the Proposed Rule. Commenters stated the EPA did not, 

but should, take into consideration the costs and 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. Commenters stated commodity costs associated 

with supply and demand economics will escalate due to more than doubling the amount of 

natural gas used for electricity production. 

Commenters referenced a reliability impact 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. Commenters 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. Commenters stated the conclusion of 

the report indicates that, if the compliance period begins before adequate generation and 

infrastructure can be added, the SPP region will face a significant loss of load and violations of 

regulatory reliability standards. Commenters stated that, according to the impact assessment, 

SPP's transmission system could face severe overloads that will lead to cascading outages. 

Commenters 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

Commenters stated that, although the EPA indicates consideration is given in the flexibility of 

state plans to accommodate emergencies, the stringency of the interim and final goals for this 

building block creates a shift in a direction that cannot be reclaimed during emergencies. 

Commenters stated that, during the extremely cold weather experienced earlier this year the SPP 

determined 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. 

Commenters 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. Commenters stated the 

delivery of electricity is extremely complex and the system must be built to withstand extreme 

weather. 

Commenters 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. 

Commenters stated that overdependence on any one energy source such as natural gas will not 

allow adequate response capabilities in emergencies. Commenters stated the electric generation 

system has become increasingly dependent on the operation of the natural gas system and the 

natural gas system is also dependent on electricity for its ability to deliver natural gas from the 

well-head to the consumer. Commenters stated that, in the event of grid failure, both systems 

could be disrupted. Commenters asserted that each state, along with the RTOs in that state, must 
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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. 

Commenters 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. 

Commenters stated that natural gas supply deficiencies and historical price volatility experienced 

by Empire continue to drive the decision to maintain fuel diversity in our generation mix. 

Commenters 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. Commenters

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. Commenters stated that, during a recent 

natural gas supply shortage issue, fuel oil, which is traditionally a significantly higher priced 

fuel, became a better economic decision than the 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 disagrees that we have not considered system constraints and demand in 

the development of the 111(d) final rule. Additional 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 pipelines need to be analyzed

Commenters stated the EPA must consider the hazards posed by aging pipeline infrastructure. 

Commenters cited a US DOT report showing the age 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 described the impacts from 

a pipeline rupture that occurred on December 11, 2012. Commenters stated that, for these 

reasons, they have very serious questions about whether the state's and nation's aged pipeline 
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infrastructure can support a 70 percent capacity factor for new NGCC units, or even the 65 

percent alternative proposed by EPA. Commenters 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

Commenters also stated that the EPA's inclusion of re-dispatch to NGCC units at 70 percent in 

the proposed BSER may also eliminate needed flexible generation to balance intermittent 

generation resources that are low-carbon emitting, causing additional impacts to the system as 

whole. According to the commenters, both FERC and 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. 

Commenters 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 requiring their 

conversion to use as base load sources should be analyzed further. Commenters 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 stringency proposed in this block might 

cause reliability issues. Commenters 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 technically feasible and can be achieved at a reasonable cost 

without negative reliability impacts.

Commenters stated the EPA must consider the need for added load-following capacity due to the 

installation of additional renewable energy under building block 3.

Analyze local needs

Commenters expressed concern that, although the EPA states that it is not concerned with 

infrastructure adequacy on the whole, the Agency failed to analyze whether local changes in the 

generation mix will require pipeline installation or capacity expansion. Commenters stated that, 

while coal deliveries are quite flexible in timing and transportation options, natural gas depends 

on available pipeline capacity in the distribution system and at each facility in real time. 

Commenters stated regional infrastructure limitations will complicate and can delay increased 

reliance on natural gas. Commenters stated planning, permitting, contracting, financing, and 

building this infrastructure if needed will delay full implementation of the CPP.

Commenters 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 reach consumers. 

Commenters stated the EPA has not accounted for these challenges in making its blanket 

assumption in building block two.

Analyze operational constraints
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Commenters stated that uncertainty exists regarding the EPA's proposal to operate these NGCC 

units as a base load resource and how loss of this flexibility could affect other aspects of system 

operations. Commenters stated that a significant impact on pipeline infrastructure could occur if 

the proposed Clean Power Plan results in the increased need for simple cycle combustion 

turbines to support flexible operations that can no longer be supported by NGCCs. Commenters

stated that, if simple cycle combustion turbines 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.

Commenters 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 which have the 

potential to make the targeted increased utilization of natural gas plants less likely in the near 

term. 

Commenters 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 

capacity that may be needed in any one hour to maintain electric reliability. 

Commenters 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. Commenters

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 operation, which would make 

such units unavailable for managing generation from renewable resources (particularly wind) as 

they are often utilized today. Regarding the EPA's analysis, commenters supported several 

comments by EPRI on the rule: (1) cautioned about 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 operate 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; natural gas prices are 

currently forecasted to be relatively low, history has demonstrated the price of natural gas to be 

highly volatile, and multi-year forecasts have consistently been inaccurate; establishing a 

mitigation goal based on an assumption of persistent 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 electric system reliability in future instances.

Commenters stated that there are a number of challenges to the natural gas industry in meeting 

the electric gas loads. Commenters stated that Building Block 2 poses major regional challenges 
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that the Proposed Rule fails to recognize and address. Commenters 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 units. 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. More problematic for the gas industry than 

seasonal electric gas load variation are daily and weekly variations (i.e., nonratable-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 nuclear-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 intermittent 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 single 

point, whereas almost all the LDC loads are served over multiple city gates. 

Natural gas suppliers are significantly limited or simply not present in many of 

the rural areas where electric cooperative baseload facilities are located. Natural 

gas supply pipelines may be hundreds of miles away from where additional 

electric generation may be required to serve cooperative rural service areas. Even 

where pipelines are available, the availability of firm gas supplies at a reasonable 

price is an ongoing uncertainty. 

Infrastructure needs analysis

Commenters questioned whether it is feasible for 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.

Commenters stated that the EPA also must provide a legitimate justification for its assumption 

that supplemental electricity transmission and gas pipeline construction "can reasonably be 

expected" because the Proposed Rule relies on new 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 the 
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Proposed Rule (IPM Documentation at 2-10 to 2-11, 10-37 to 10-38). Commenters indicated that 

such an analysis should consider the time required for the transmission and pipeline permitting 

and construction necessary for compliance - electricity transmission planning and construction 

can take 5 to 15 years (NERC Report at 20) and permitting 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. Commenters 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 across multiple states in a region or if interregional planning is required. 

Commenters stated the EPA has not fully analyzed and supported the feasibility of the level of 

re-dispatch required. Commenters stated that addressing reliability problems either through 

modification of the bulk transmission system or construction of new generating units requires 

that transmission studies be performed. Commenters stated these studies - and any identified 

upgrades - optimistically take approximately two years to complete. Commenters stated that, for 

larger transmission projects that may be necessary to accommodate large additions of renewable 

generation are more difficult and time consuming to evaluate, permit and construct, seven to ten 

years is a more likely time frame for such projects, putting aside any consideration of the 

potential need to study and build many transmission projects simultaneously as all states and 

RTOs attempt to meet infrastructure needs under Clean Power Plan compliance.

Commenters expressed concern that by selecting only a narrow range of available data, the 

EPA's derived estimate of growth in the natural gas pipeline (GHG Abatement Measures 

TSD, page 3-18, Table 3.5) is not "extremely conservative", but rather overly ambitious. 

Commenters stated the EPA is picking select years (2005-2010) to justify its conclusion. 

Commenters referred to their own analysis which 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). Commenters 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. Commenters

concluded the 21% growth in this period is not fully representative and is certainly not 

conservative. Commenters 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. Commenters 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. Commenters 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. Commenters stated the EPA is treading into a domain, control of the 

electricity generating market, in which it has neither expertise nor authority to regulate in this 

manner.

Commenters stated that, in its Proposed Rule, the EPA failed to account for increases in NGCC 

consumption just from existing generation sources. Commenters stated this additional gas 

transportation capacity needs to be established before NGCC can meet its current demands and 

future proposed 70% capacity target. Commenters stated that, currently, the United State and 

Canada are already in need of additional natural gas pipelines to provide adequate transportation 
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for existing generation sources. Commenters 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 before considering any necessary increase in transportation needs from the Proposed Rule.

Commenters stated additional evaluation is needed to ensure this increased demand can be 

accommodated. Commenters stated, given the length of time it takes for new permitting 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.

Commenters 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. Commenters stated that, to perform a comprehensive study of the natural 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. Commenters stated the comment period of 120 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).

Commenters stated that assumptions of high dispatch rates should be removed until the EPA 

(working as a supporting player with entities such as FERC, NERC, MISO or other Regional 

Transmission Organizations and individual states that have primacy regulating reliability and 

system stability) sufficiently evaluates the impact on existing infrastructure from proposed 

Building Block #2. Commenters stated the assumption that high NGCC capacity factors are 

possible on an annual basis is problematic from a reliability and system stability perspective.

Commenters stated 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, each of which may limit 

the feasibility, reliability, and sustainability of units collectively operating at such high capacity 

factors. Commenters 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. Commenters 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 

conclusions that EPA made in the proposed rule. Commenters 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 units collectively 

operating at higher capacity factors, instead providing minimal qualitative justification. 

Commenters 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. Commenters stated that the EPA should 

thoroughly review the current state of the existing natural gas supply network and related 

contractual arrangements to determine if the system can readily support an increased utilization 

of the entire NGCC fleet and/or what infrastructure challenges must be addressed, by 

investigating the following issues:
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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 infrastructure. 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 subscribed. 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 

regulatory 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 the 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 capacity 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 

pipeline infrastructure may be needed to support a 70% capacity factor. The siting of new gasfired electric generation will need to balance the cost and timing of both natural gas pipeline and 

electric transmission system expansion. Incremental costs for Firm Transportation and balancing 

services unique to electric generation loads may 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 associated 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 necessary, 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 flexibility 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 country 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 these resources could increase costs and 

delay completion of projects by the required to support compliance with the final rule.

Commenters 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 modifications that can be 

reasonably expected in the time frame for compliance with this rule. Commenters stated NERC 

must consider reliability but complete reliance on a single baseloaded fuel is not practical. 

Commenters stated that oil backup would be necessary at a minimum. Commenters stated that 
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oil firing is higher CO2 and higher wear and tear on NGCC units, meaning less availability. 

Commenters suggested that the EPA further evaluate and understand the dynamics of natural gas 

transmission in enough detail to confidently claim that there are no pipeline constraints anywhere 

in the nation.

Commenters stated the EPA failed to take into 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. Commenters 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. Commenters 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. Commenters stated that the EPA relies 

on data during peak hours when constraints on pipelines or electricity transmission networks are 

most likely. Commenters 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 consumption 

occurs in the winter when there is a large building heating load. Commenters stated Iowa will 

prove a good test case for the building of a natural gas pipeline as the necessary franchise 

requirements are negotiated through the IUB during the next few months. Commenters stated 

that, during the 2014 legislative session, much 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 session in regard to the proposed crude oil pipeline. Commenters

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 forecast

Commenters 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. Commenters stated that, if 

finalized, the proposed rule would increase natural gas demand by approximately 22% by year 

2020, with occasional short-term spikes higher than this amount. Commenters referred to a 

report prepared for Dow by Charles River Associates which predicts that the increase in natural 

gas demand for the electric utility sector will be an additional 1.8 trillion cubic feet by 2020 (a 

22% increase), and an additional 3.8 trillion cubic feet by 2030. Commenters stated the same 

report predicts that natural gas demand within the industrial sector could increase by an 

additional 1.8 trillion cubic feet per year over the next decade and stated the EPA has 

underestimated this increase in the industrial sector.

Plant level analysis

Commenters stated that the EPA's analysis of the electricity and gas infrastructure required to 

support massively increased NGCC generation must be robust. Commenters asserted that a 

robust analysis would consider plant-level infrastructure constraints, justify assumed 

infrastructure improvements and analyze gas supply and storage requirements. Commenters

stated that EPA's re-dispatch analysis should consider plant-level electricity transmission and gas 

pipeline constraints. Commenters noted that the EPA acknowledges that re-dispatch may be 

limited by plant-level infrastructure constraints, but presumes that existing transmission and 

pipeline infrastructure will be sufficient and that any necessary supplemental infrastructure 
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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 projects' 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. Commenters asserted that these national and regional analyses do 

not consider plant-level infrastructure constraints and that the EPA's assertions suffer from 

substantial analytical deficiencies. 

Commenters stated that the EPA's assertions assume future growth based on past actions, but the 

EPA has provided no support for such a projection 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. Commenters further 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 commenters, 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). 

Commenters asserted that the EPA should explain how a 21 percent increase is representative for 

all 4 regions.

Commenters stated that the EPA's failure to consider plant-level infrastructure constraints led the 

Agency to overestimate available NGCC capacity. As an example, commenters offered that the 

Proposed Rule determined Arkansas' available NGCC 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. Commenters added that the EPA similarly presumes redispatch can occur in the New England, Arizona, and Nevada while according to NERC "current 

and planned pipeline infrastructures in [these areas] are inadequate for handling increased natural 

gas demand due to the CPP". Commenters concluded 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 decreased.

Commenters 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, Commenters

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. Commenters added that the 

EPA's argument that plant-level infrastructure constraints at peak times can be overcome through 

emissions averaging is also unavailing because coal plants, the generation source to which EPA's 

averaging suggestion likely refers, cannot serve as peaking plants, and many states are prohibited 

from operating coal plants during the peak summer season because doing so would make 

compliance impossible with averaging. 

Regional analysis
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Commenters stated the EPA's IPM analysis does not take into account region-specific technical 

issues. Commenters 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. Commenters stated that, in the absence of a detailed transmission analysis, 

given Arizona's demonstrated lack of flexibility, EPA would be unable to assess what units are 

necessary for the reliability of the electric grid.

Commenters stated the EPA failed to recognize and analyze unique circumstances the natural gas 

supply infrastructure. Commenters stated that, although the infrastructure has previously been 

adequate to support peaks demands and for extended periods of time, the system is not adequate 

to continue to do so into the future. Commenters stated the EPA failed to consider the differences 

in the gas supply infrastructure across the county and noted that the natural gas infrastructure is 

vastly different in the West compared to the 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.

Commenters 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. Commenters stated the EPA has not demonstrated 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. Commenters stated 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

Commenters 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 analysis, 

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

Commenters 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. Commenters alleged that the EPA has not analyzed the consequences of redispatch on storage capacity. According to the commenters, the IPM model does consider 

storage capacity, but the EPA's reliance on the IPM is restricted to the IPM's cost impact 

analyses (79 Fed. Reg. 34,864-65). Commenters concluded that EPA cannot therefore rely on the 

IPM to support its re-dispatch feasibility analysis. 

Commenters recommended that, in the final rule, the EPA analysis fully consider the availability 

of storage and associated interstate delivery capacity and include additional stakeholder 
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perspectives and concerns related to operation of the bulk power system with increased reliance 

on natural gas. Commenters stated, MISO has 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. Commenters also noted that the ability of the nation's 

natural gas infrastructure (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.

Commenters stated that, 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. Commenters stated this vulnerability makes the undemonstrated 

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 agencies. 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, 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 Regulatory Impact Analysis of the final CPP. 

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

State-by-state analyses

Commenters suggested the EPA should analyze what individual pipeline systems are prepared to 

support in order for each state to meet a 70% utilization goal. Commenters suggested the EPA 

should 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.

Commenters cautioned the EPA regarding the limits of relying on nationwide summary statistics 

and past performance to draw conclusions about the ability to support the increased utilization of 

NGCCs with underutilized pipeline capacity. Commenters stated that a more intensive 
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examination of regional natural gas markets and anticipated 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. Commenters stated 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. 

Commenters stated the Energy Information Administration regularly examines changes in interregional pipeline capacity (i.e., the ability to transport natural gas between regions), although this 

does not include an examination of the availability of capacity within a region to serve a 

particular pipeline delivery point.

Commenters stated the EPA should develop building 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. 

Commenters 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. 

Commenters stated this would allow the building block to accurately reflect both what a state has 

accomplished to date and what it can actually achieve in the future. Commenters 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. 

Commenters 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. Commenters 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

Commenters expressed concern that, while Arkansas receives almost zero credit for nuclear and 

hydroelectric power plants that produce no greenhouse gas emissions, the proposal assumes 

Arkansas's natural gas-fired power plants can operate at 70 percent capacity. Commenters stated 

this significant increase in electricity generation from natural gas-fired power plants is 

unprecedented in Arkansas, and noted serious reservations whether it can be accomplished 

without expensive upgrades to pipeline and electricity transmission infrastructure.

Commenters stated the EPA should re-formulate its analysis of natural gas availability to account 

for potential supply constraints 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. Commenters stated the EPA assumes that necessary gas pipeline infrastructure 

can be added in time to support reliable operation of gas units at higher capacity factors, but did 

no analysis of the current supply constraints for existing NGCC units. Commenters stated the 

EPA made allowances in the computation of state goals 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. Commenters 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. 
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Commenters noted that Indiana produced 826.8 trillion Btus of coal in 2012, but only 8.9 trillion 

Btus of natural gas that year. 

Commenters 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). Commenters stated that the 

Columbia Pipeline Group 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. Commenters 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.

Commenters stated the magnitude of increased utilization of NGCC in 2020 is based on 2012 

generation, which is in turn based on 2012 demand; however, the actual amount of NGCC 

capacity available in 2020 will depend on 2020 demand and EPA's current approach does not 

account for any load changes that will occur between 2012 and 2020. Commenters stated NV 

Energy is projecting more than a 10% increase in load between 2012 and 2020 on its system. 

Commenters stated EPA's failure to take this growth into account underestimates the demand 

conditions that the utility will experience in 2020.

Commenters stated that, while the EPA projects the NGCC units to operate at levels very similar 

to those observed in 2012 under both the regional and state compliance options that is unlikely, 

given the historically low price of natural gas in 2012. Commenters stated that, while IPM 

projects 6 of Ohio's 26 existing NGCC units 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 factor that is considered by the IPM 

model.

Commenters stated that, given the increased demand upon natural gas supplies that will result 

from this proposed rule, there is uncertainty as to whether sufficient pipeline capacity and 

infrastructure to ensure an uninterrupted supply of electricity will be available. Commenters

stated that more evaluation of actual resource capacity and resource adequacy in the Western 

Interconnection is needed to understand what effects the proposed rule will have on natural gas 

supply and delivery.

Commenters recommended that EPA allow a reasonable time period for entities such as WECC 

and NERC to ascertain how the proposal impacts resource adequacy and reliability in California 

and other western states to determine if the assumptions in Building Block 2 should be adjusted. 

Commenters 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 EGUs in Nevada or, in part, as replacement energy for LADWP's share of 

Navajo Generating Station, which is located in Arizona. Commenters 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. Commenters stated that preliminary WECC results indicate that a state's 

decisions made regarding Clean Power Plan compliance can "drastically impact grid operations, 

system resiliency, and potentially, compliance opportunities for a neighboring state" (EPA Clean 

Power Plan Phase 1 - Preliminary Technical Report, WECC Staff, September 19, 
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2014). Commenters stated NERC has begun a similar phased study process and came to a 

similar conclusion that more studies would be needed to understand the full ramifications of the 

proposal on electric reliability. Commenters urged EPA to work with NERC, WECC, states and 

regional transmission organizations to adopt a more realistic view of the potential for re-dispatch 

that considers stranded costs and the reliability 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 undue stranded costs on states' electric ratepayers. Commenters stated this review would 

determine whether adjustments to a state's goal are appropriate.

Commenters requested the EPA examine the impacts of these transmission systems constraints 

and address how they impact the prospect of achieving 70% utilization within the time required. 

Commenters stated that, with respect to the transmission systems that deliver the electricity from 

the EGUs, the RTOs have operational control over all federal-jurisdictional transmission 

facilities. Commenters stated that, if there are constraints on the transmission system controlled 

by PJM that would be exacerbated if AMP's AFEC NGCC were dispatched, PJM will not 

dispatch or will curtail the output of AFEC. Commenters 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 constraints that are beyond either the EGU or the state's control. 

Commenters 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. 

Commenters stated that individual NGCC units may not be able to achieve higher utilization 

rates due to the particular configuration of the unit. Commenters explained, for example, that 

South Carolina'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 required to run at a 70% 

capacity factor. Commenters stated this facility is managed as a merchant facility that, in part, 

sells power out of state; consequently, it is very possible that even if these units are able to obtain 

enough gas to increase their capacity 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. 

Commenters stated it is not clear whether or not the infrastructure will be in place for South 

Carolina to increase the use of natural gas to meet the entire emission reduction goal. 

Commenters stated that it appears the EPA measured natural gas availability by only factoring in 

natural gas units available at the time of the baseline.

Commenters stated that, 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. Commenters 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 contracts, contractual relationships 

between NGCC units and steam units including units owned by multiple parties, gas and electric 

transmission capacity, electric transmission rights, gas and electric transmission equipment 

upgrades and/or changes, natural gas availability, natural gas supply contracts, dependable unit 

capacity, and units dispatched by different RTOs. Commenters recommended the EPA re-
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analyze Building Block 2 by involving plant owners, RTOs, Balancing Authorities, FERC, 

NERC, WECC, states and other stakeholders to determine the feasibility and limitations of 

Building Block 2 for each state including consideration of the interstate relationships between 

generation and loads. Commenters stated the basis of EPA's analysis regarding the feasibility of

implementing Building Block 2 is not detailed, accurate or reasonable.

Commenters suggested that additional analysis is needed. Commenters stated that although 

NGCC units are designed to be dispatchable and may be able to operate as priority base load 

generation, these units are most often used to serve peak and intermediate load, due to their 

ability to ramp up and down quickly to meet dynamic demand changes over time. Commenters

described the two TVA NGCC facilities located in Tennessee, and noted that in 2012 the two 

operated at an average of 47 percent capacity according to the EPA's data. Commenters indicated 

that like most NGCC plants across the nation, NGCC plants in Tennessee fulfill a load-following 

role, but the proposed BSER would require a fundamental shift to base load generation for these 

units. According to the commenters, it is unclear whether, and to what extent, this is feasible. 

Commenters cited the TVA's comments as stating that most of its NGCC facilities appear 

capable of running at a 70 percent capacity factor with sufficient maintenance; however, the 

existing affected coal-fired EGUs may not be able to provide the flexible operational capabilities 

that NGCC units are currently providing. Commenters stated that in other words, while the

NGCC units may, theoretically, be able to do the 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. Commenters 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.

Commenters 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. Commenters

asserted that, for states in which the emissions rate goal is so strongly tied 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. Commenters 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 CO2 goal." Commenters stated the EPA's rigid application of the BSER 

building blocks across the nation is inappropriate given the unique unit fuel mix/resource 

availability in each state. Commenters noted that, for the state of Texas, BSER Block 2 accounts 

for approximately 45% of the EPA-assessed emissions reduction requirements and stated that, in 

this circumstance, if no solution could be obtained by FERC for achieving the Building Block 2 

NGCC utilization goal while maintaining electricity reliability and affordability, Texas would be 

placed in the difficult position of finding emissions rate improvements that would account for a 

significant portion of the required emissions reduction.

Commenters stated the EPA must adequately account for potential losses of current generation 

sources. Commenters stated this includes the retirement of nuclear generation. Currently, 

commenters stated, significant nuclear generation will be retired in 2030 and 2033 in Wisconsin. 

Commenters 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 demand 
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changes caused by electric arc metal furnaces in the area. Commenters stated it is important facts 

and nuances about the EGU fleet, such as this one, that EPA's proposal fails to recognize and 

calls into question the thoroughness and basis of EPA's rule.

Commenters stated the EPA did not adequately assess natural gas pipeline capacity and storage. 

Commenters noted that natural gas storage capacity became overextended in Wisconsin in 2012 

and 2013, with resulting price increases and supply shortages, and stated that dispatch of NGCC 

to a 70% capacity factor is estimated to increase Wisconsin's natural gas consumption by 12.6%. 

Commenters 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. Commenters provided the 

following additional points.

• First, prior to the release of EPA's proposal, the Midwest Independent System 

Operator (MISO) identified constraints that need to be addressed in order to 

maintain natural gas supply for electric generation in the region; these constraints 

do not appear to have been considered by EPA (November 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 with 

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 peaking 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 are 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 appropriate 

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. EPA 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 

impact. 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 approximately $2-3 million dollars and the lateral feed 

$2.5 million per mile.
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Comment 20: Commenters suggested additional analysis is needed, such as consideration 

of sustainability and maintenance.

Response 20: The EPA disagrees that we inadequately considered system issues in development 

of the 111(d) final rule. Additional analysis may be considered by implementing authorities. In 

response to additional analysis and many comments, we have modified the proposal and RIA;

the establishment of 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, 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 suggested a longer term analysis is needed, including consideration of sustainability 

and maintenance concerns. Commenters recommended the EPA reconsider the level included 

within proposed BSER from building 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. Commenters stated the EPA's 

conclusions 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 uses in its 

analysis. Commenters 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 capacity factor over shorter periods of 

time (annually and/or monthly), whether that level can be achieved and maintained consistently 

by a large percentage of the fleet over the longer term is not demonstrated through the 

information EPA includes to support the proposed guidelines.

Commenters stated the assumption that an NGCC unit can sustain a 65 percent, 70 percent, or 75 

percent utilization rate over a decade based on data that otherwise suggests highly variable 

monthly averages, and without consideration of maintenance and down-time for operational 

constraints, is not reasonable. Commenters 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. Commenters referenced a September 2014 EIA report 

and noted that, during the period of the 2014 Polar Vortex, a time when natural gas supplies had 

to be curtailed and/or redirected from many sources, the capacity factor reported across the 

national fleet during that period was much lower than 64.5 percent at 44.8 percent in January 

2014 and 41.2 percent the following month.
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Commenters stated that if, as EPA assumes, the increased utilization of NGCCs needed for the 

states to achieve the 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. Commenters 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. Commenters 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. Commenters stated that, 

while pipeline operators are careful not to affect the ability to meet the needs of firm shippers 

when maintenance is being performed, the capacity available for interruptible shippers may be 

limited.

Commenters stated that the shift in natural gas pipeline flows attributable to the shale gas 

revolution may create additional underutilized pipeline capacity that could be used to serve gasfired generators operating at increased capacity factors. Commenters stated that, in some cases, 

the abundance of natural gas and the shift in the location of natural gas relative to consuming 

markets has resulted in diminished capacity utilization along some pipeline corridors. 

Commenters added that, because the flow of natural gas has increased along other pipeline 

corridors, there will be less underutilized pipeline capacity available along those corridors to 

support the increased utilization of NGCCs. Commenters noted that the initiation of liquefied 

natural gas exports and the demand for natural gas to supply new and re-opened petrochemical 

facilities along the Gulf of Mexico will result in greater year-round utilization of existing 

pipeline capacity in that region. Commenters stated that, since many pipelines were designed to 

deliver sufficient natural gas to meet the LDCs' peak day winter heating loads, for much of the 

year some portion of the LDCs' entitlement to firm service3 is underutilized and this pipeline 

capacity can be re-sold by the LDC in a secondary market for pipeline capacity. Commenters

stated that during off-peak months it is likely that pipeline capacity will be available in the 

secondary market to deliver the natural gas that will be needed to increase the utilization of 

NGCCs.

Commenters stated that it is important to note that under the open access requirements prescribed 

by the Federal Energy Regulatory Commission (FERC), interstate natural gas pipeline capacity 

must be available on a not unduly discriminatory basis. Commenters 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). Commenters stated that, as a result, 

the fact that a shipper wishes to transport natural gas to an NGCC for purposes of compliance 

with the Clean Power Plan would not cause its transportation 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: Commenters stated the EPA should use modeling to determine how NGCC 

generation offsets other generation throughout the electric supply system.
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Response 21: The EPA disagrees that our modeling is inadequate. We believe the modeling we 

performed for the 111(d) final rule appropriate. In response to additional analysis and many 

comments, we have modified the proposal and RIA;the establishment of CO2 emission reduction 

standards is regionally based. The 111(d) final 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, 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:

Commenters stated this modeling will likely show that increasing NGCC generation will offset 

existing and new renewable energy, indicating that the proposed RE requirement is neither 

practical nor cost-effective in operating the grid. Commenters stated that, at a minimum, EPA 

should assume that additional NGCC generation will offset renewable energy capacity before 

existing coal-fired generation and solid fuel biomass-fired generation. Commenters stated the 

EPA cannot assume that NGCC generation will offset coal-fired generation, as this is not how 

the electric supply grid functions in reality; 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. Commenters stated that, as a part of this modeling, the EPA must 

establish a floor for operation of existing coal-fired EGUs that prevents degradation of their heat 

rates.

Comment 22: Some commenters raised issues regarding natural gas-electric coordination.

Response 22: The EPA disagrees that we have inadequately considered natural 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 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, extreme weather, fuel 
322

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 March 20, 2014 FERC Scheduling Coordination Order and) stated that 

stated the FERC has recognized that, as our Nation's dependence on natural gas generation 

continues to rise, the differences between regionally coordinated electricity market scheduling 

timelines 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 confirmation 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 natural 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 state 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 

electric-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 NGCC units. Commenters stated 

that, in setting the 70 percent re-dispatch element of Building Block 2 EPA failed to adequately 

consider the potential impact to the gas pipeline infrastructure and electric transmission systems 

of dramatically increasing the dispatch of electricity produced at the NGCC plant, particularly on 

the short timeframes required in the proposed Guidelines. Commenters stated that, for the most 
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part, coal-fired and NGCC plants are not co-located in Indiana, thus there is no guarantee that 

adequate transmission currently exists to send the same electric load from an NGCC plant as that 

being serviced by baseload coal-fired units. 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 

dispatch 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 also 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 infrastructure, and that these 

differences are more acutely seen in areas with RTO/ISO markets. Commenters pointed out that 

these issues are being discussed at both FERC and at the regional level.

Commenters supported a comprehensive and independent analysis of the impacts 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 the dispatch of generating units by 
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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 interruptible pipeline 

capacity are exposed to supply cuts during times of peak demand, not because of inadequate 

supply but because all firm customers are utilizing their capacity rather than releasing it for use 

by non-firm shippers. Commenters noted that local distribution 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 constraints 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 

electricity 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 interaction 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 DOEfunded 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 implementing 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 stated 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 issue 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 interindustry issues. Commenters stated the EPA should consider whether it is prudent to be placing 

the burden on states to implement BB2 while the gas and electric generation industries are 

grappling with the need to improve market design issues between the two industries.

Commenters suggested the EPA consult with FERC before 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 incorporating FERC into the rule development process, Commenters stated the EPA 
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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 EPA 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 construction of 

building block 2. Commenters stated that there are concerns surrounding the synchronization of 

electricity and natural gas markets as supplies of power and natural gas are secured on a different 

time basis. Commenters indicated that this disconnect 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 interdependent 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 capability 

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 during 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 and 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 nonpublic 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 whets the appetite 

for more gas-fired power. Commenters noted that In March 2014, FERC issued a Notice of 

Proposed Rulemaking (NOPR) which has spawned an extraordinary effort by the North 

American Energy Standards Board (NAESB) and natural gas and electric industry 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 remaining 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 proposed Rule. Commenters provided detailed information 
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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%), the 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 natural 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 ability 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 that 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 consumers 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 generation 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 reliability 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 impacts 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 2013-14. 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 transportation 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 been 
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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 especially 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 scheduling 

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 stated 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. 

Commenters (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 require 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 Scheduling 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 their 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 Clean Power Plan and) stated as gas-electric dependency significantly increases, 

unforeseen events like the 2014 polar vortex could disrupt natural gas supply and delivery for the 

power sector in high-congestion regions, increasing the risk for potential blackouts.
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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 gas 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: 

“Reproduction 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 components 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 issues, and line losses

Response 24: The EPA disagrees that transmission issues, market issues, and line losses prevent 

achievement of the goals. Additional analysis may be considered by implementing 

authorities. In response to additional analysis and many comments, we have modified the 

proposal and RIA; the establishment of CO2 emission reduction standards is regionally based. 

The 111(d) final rule requires that states develop plans that establish emission standards for 

affected EGUs. We are providing states with 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 
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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 EPA needs to address how the CPP will result in increased transmission 

congestion and higher energy costs across the state and adjust the Building Block calculations for 

Florida accordingly.

Commenters stated that, to comply with a 70 percent utilization target for NGCC, good faith 

efforts could be considered market manipulating 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 comply 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, MISO market rules would need to change to 

allow a NGCC generator to bid artificially for a 70 percent dispatch, while also allowing the 

IMM to monitor the way the bid was executed to ensure it was not done in a way that allowed 

the "complying" generator to manipulate the broader market. Commenters stated that nothing in 

EPA's proposed Building Block recognizes either of these basic market constraints or offers 

solutions to resolve them. Commenters stated that, because it is unclear how to dispatch 

environmentally in a market that is reliability and economically driven, as a result, the EPA 

inappropriately applied BSER because the associated benefits with this Building Block are not 

shown to be achievable.

Commenters stated there is no guarantee NGCC units could send their power to the same loads 

currently being serviced by coal-fired EGUs. 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. Commenters 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 

applied in setting state targets. Commenters stated that, as a result, the EPA failed to 

appropriately apply BSER. Commenters stated the EPA should recalculate its estimates for line 

loss using state-specific data. 

Commenters stated congestion is also a major 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 

between 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.
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Comment 25: Commenters stated that the proposed rule does not examine whether sufficient 

natural gas storage exists to support large-scale fuel switching.

Response 25: 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 

exists 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, according 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 stockpile 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 redundancy 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 

were 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, while natural gas pipelines can typically be permitted, financed and 

constructed in four to eight years, construction of natural gas storage facilities is far more 

difficult because of the limited geology for 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 the question of sufficient storage is often 
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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 industrialmanufacturing sectors 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 locations 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 need 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. "Storage is very useful in providing flexibility to support gas burns by electric 

generators. Natural gas storage lets a power plant operator: ramp up or ramp down operations 

quickly (especially for intermittent renewables); manage its imbalances; potentially hold less 

firm pipeline capacity; and maintain reliability." 

Commenters stated that EIA reported that as of 2013, roughly 4.6 Tcf of underground storage 

working gas capacity, representing roughly 410 underground gas storage fields, were in 

operation, but these underground storage fields are not equal in that most are not configured to 

provide rapid withdrawals for power plants, and many are not located close enough to power 

plants to support the rapid change in linepack needed when a power plant fires or otherwise 

accommodates multiple turns often needed to support power plant operations (commenters 

provided a table showing the location of natural 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 percent 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 

"producing 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 close 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 only 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 and 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 York, 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 storage. Commenters 

indicated that the EPA needs to examine these issues and revise its assumptions regarding the 
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timetable by which electric utilities could convert from coal-fired generation to natural gas-fired 

generation to reduce their CO2 emissions. Commenters 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 26: Commenters stated that energy storage technology is able to not only enhance the 

capacity factor and efficiency of fossil generation, but by storing and releasing energy when the 

grid needs it most, it can replace most inefficient peaking capacity all together. 

Response 26: The EPA agrees that many studies demonstrate the 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 gas 

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 turbine 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 stated 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 

entire 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 the 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 distribution. Commenters noted that, in 

Arizona, the utility Arizona Public Service agreed on a settlement to include energy storage in 

the planning and procurement process as a replacement for additional peak capacity, recognizing 

the ability of storage to provide peaking services comparable to natural gas. Commenters stated 

that, in another case, Southern California Edison 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 the 
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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 procurement 

process.

Comment 27: Commenters expressed concern regarding the adequacy of pipeline infrastructure.

Response 27: The EPA disagrees that gas market issues prevent achievement of the goals. 

Additional studies may be considered by implementing authorities. In response to additional 

analysis and many comments, we have modified the proposal and RIA; the performance period

has been postponed. The 111(d) final rule requires that states develop plans that establish 

emission standards for affected EGUs. We are 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:

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 prices were the lowest they've ever been, and dispatch 

did not even approach 70 percent; it was closer to 57 percent. Commenters noted that the EPA 

expected a 12 percent increase in natural gas stock prices by the end of the decade. Commenters 

stated that it is difficult to foresee achieving 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 infrastructure and stated that 

NERC found that EPA's assumption in Building Block 2 that the "power industry in aggregate 

can support higher gas consumption without the need for any major investments in pipeline 

infrastructure" is unrealistic, and there are "critical areas," including Arizona, Nevada, and New 

England that already face pipeline constraints and will need even more pipeline capacity to the 

extent that coal generation is replaced by natural gas generation. 

Commenters stated that, in analyzing the adequacy 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; 
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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 as 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 infrastructure 

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 years 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 

infrastructure, 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 cases 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 

permitting, "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 the U.S. create obstacles to the construction of new pipelines needed to supply sufficient gas 

to electric utilities (as well as obstacles to the construction of renewable generation), and this has 

been particularly problematic in New England, which generates over half of its electricity from 

natural gas and where the lack of sufficient 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 December 2013, the Governors of the New England states issued a joint statement 

expressing their commitment to "continue to work together, in coordination with ISONE, and through the New England States Committee on Electricity (NESCOE), to 

advance a regional energy infrastructure initiative that diversifies [its] energy supply 

portfolio while ensuring that the benefits and costs of transmission and pipeline 

investments are shared appropriately among the New England States." To further the 
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Governors' stated goals, 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 nocarbon 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 generators operate in a shortterm 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 transportation. 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 the Massachusetts 

legislature's adjournment without passage of a bill to provide for state long-term contracting for 

electricity from resources with zero or low carbon dioxide emissions. Although this development 

primarily affected the electric transmission 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 time 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 fast 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 pipeline 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 extend 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 expansions. 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 

findings. Commenters stated Pace Global projects power sector natural gas demand in Arizona in 
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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 the 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 facilities. 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. 

Commenters 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 and 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 use 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 firm 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. 

Commenters 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 concerns 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 transmission lines from the 

coal plants, which tend to be in the northeastern part of the state, and by transmissions lines from 
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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 

currently 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 peak 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, the 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 

magnitude 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 Arizona 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-dispatching 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 already 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-heavy 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.
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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 

consumption 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. Commenters 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 interruptible gas supplies for ensuring operation 

of all NGCC units within the State at an annual 70% capacity factor. 

Commenters stated that additional pipeline capacity would need to be added to South Carolina 

for its existing NGCC units to operate at an annual 70% capacity factor. Commenters stated this 

expansion will take significant time for financing, permitting, and construction-a minimum of 

three to five years is estimated (NERC Initial Reliability Review at 10) and then only if the 

expansion experiences minimal delays or opposition. Commenters stated it will also be 

expensive: rate estimates given to Santee Cooper by Carolina Gas Transmission are 3.5 to 7 

times the rate for existing capacity. 

Comment 28: Commenters included a description of NERA's whole-economy model, NewERA, 

and findings from their analysis of the extent to which they 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 28: 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 significant changes from 
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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, commenters 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 

efficiency, 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 relative 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 projected 

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 gas 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 concerns that 

have not been addressed in traditional power system reliability analysis.) We also consider the 

institutional arrangements in each state, as market considerations alone are not sufficient to 

understand the deliverability problems that may result from 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 natural 

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 supply 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.
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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 heavily 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 environmental 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 through 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 scenario 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 

consumption 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 rankings 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 statespecific results were estimated from that model's outputs; rather, 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 CPP) is available for compliance determinations and/or cost-effective relative to the other 

alternatives. In this scenario, each state achieves the proposed Section 111(d) targets without any 
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demand-side energy efficiency programs. Commenters noted that both scenarios assumed 

proposed state rate limits under Option 1 would be met by each state independently seeking its 

least-cost opportunities, without any multi-state coordination and that States would use the 

flexibility mechanisms to the extent possible, but they differ in how much cost-effective demandside energy efficiency would be feasible. 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. Commenters 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 Pipelines." 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 upper 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 demand increases alone, as those where the projected total natural gas demand 

significantly exceeds 2012 natural gas consumption. These are states where even an 

occasional difficulty in obtaining natural gas 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 generation 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 baseload 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.
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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 analysis 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 incorporating 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 supplydemand circumstances (such as the polar vortex). These are states where gas 

pipeline deliveries have not typically 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 criteria, 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, particularly 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. Commenters 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 risk, 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 generators 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. Commenters stated there are two deregulated 

states that are projected to have at least 10 percent demand increase in both model cases and 
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should perhaps be given further scrutiny in a more detailed evaluation of natural gas supply 

concerns: Oregon and Illinois.

Commenters provided a table in Figure 2, which 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 dense gas infrastructure face 

pipeline constraints in the future, but also those states at the terminal end of major pipelines, 

especially during summer and winter peaks (i.e., 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 Table 4 shown in plain text format is as below:

Risk Level: Relatively 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 upstream 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.
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• 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 infrastructure 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 increase in demand for 

interruptible within state supply.

• Oklahoma, Alabama: Relies on natural gas for more than 35% of baseload 

generation under the base case and will increase to more than 50% reliance under 

proposed CPP.

• Texas: Relies on natural gas for more than 35% of baseload generation under the 

base case and will increase to more than 50% 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 Level: 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 gas 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 increases 
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among 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 does 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 heating gas demand and electric generation natural gas demand 

suggest heightened risks associated with such events in the future.

Comment 29: Commenters suggested the EPA's modeling with the IPM is inadequate with 

respect to reliability margins, transmission and operational constraints, and prices.

Response 29: EPA disagrees that our modeling is inadequate. The IPM model is well described

noted in published documentation, and EPA used other analyses in addition to the IPM model. 

Moreover, EPA believes that the CPP provides states with the flexibility, including trading, to 

develop plans that consider reliability and local circumstances, such as transmission constraints, 

extreme events, and system balancing. See sections V.D, VIII.A, VIII.C and VIII.G of the final 

rule preamble of the CPP and Chapter 3 of the GHG 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 consideration 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 peak 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 under 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 state 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 

documentation 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 capacity 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 generating 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 generating 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 production 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 the 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 does not represent unit commitment and 

dispatch in a detailed manner. Dispatch within the model is based on variable 

generation costs alone and does not include 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 a 
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portfolio of fixed capacity and investment decisions related to capacity expansion. 

Consequently, the resource adequacy and reliability analysis TSD does 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 reliability...," 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 flexibility requirements induced by the 

proposed rule. 

Commenters stated there is no evidence that the EPA's modeling has taken into account the 

following factors: (1) continued access at today's historically low prices is questionable in the 

face of special-interest opposition to drilling and the specter of additional federal regulations and 

(2) the EPA's proposal admits that 70% utilization rates have been exceptionally rare, 12 

consequently, assertions of technical feasibility require detailed modeling, contingency 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, increases 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 incompatible 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: Commenters stated that, based on modeling analysis, Florida cannot meet the 

EPA's proposed rule with current generation plants, no matter how they are run. 

Response 30: EPA disagrees that the commenter’s modeled results of the proposal would reflect 

a similar analysis of the 111(d) final rule. EPA 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 rates, and it provides flexibility, 

including trading, for states to develop plans that consider reliability. States may choose any of a 

variety of approaches to develop a plan. See 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.
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 the 

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 consideration 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 switching, 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 around 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-net 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 fuelswitching and (2) Change Case, in accordance with Building Block 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) fuel price projections. Since increasing natural gas demand puts upward 
349

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 bridge 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 

evaluated. 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 coalfired 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 increases 

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 additional 

improvements can be made in Florida is unreasonable and unproven.

Comment 31: 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.

Response 31: 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 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, 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 interruptible 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 operational 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 hour period, 

which reduces the operational flexibility of a gas unit, and that gas market timing is not in-sync 

with PJM market timing, meaning this mismatch can 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 connected 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 the 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 historically 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 additional 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. Commenters 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 and nonfirm 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 volatility 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 increase
351

Commenters stated that natural gas availability 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 gas 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-mybackyard (NIMBY) opponents to locating 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 

contracts 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. Commenters stated a unit may not 

be able to contract for firm gas capacity for only part of a year. 

Commenters included a figure illustrating the 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 

priority 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 indicated 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 

traditionally 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 occurs in the summer. Commenters 

believed 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 increasing 

NGCC generation simultaneously. Commenters stated that, in that situation, demand for natural 
352

gas to serve NGCC generation would reasonably be expected to increase significantly, which, in 

turn, would require additional pipeline, compression, and storage 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 needs 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 to 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 fluctuate. 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 to meet the needs of all consumers in the 

market, and capacity constraints could be a more frequent and prolonged occurrence.

Comment 32: Commenters stated the EPA must account for natural gas needed by other sectors, 

including residential heating, and should not apply building block 2 during the heating season. 

Response 32: The EPA disagrees. We believe our modeling 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 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 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, 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 natural gas. Commenters stated that, 

regardless of the growth in other sectors, the EPA must also ensure the availability of natural gas 

for residential heating purposes. Commenters stated that building block 2 should not be applied 

(in full or in part) during the winter heating season in order to safeguard home heating supplies.

Comment 33: Commenters 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 

that constraint.

Response 33: 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 develop plans that consider reliability and 

local 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 34: Commenters expressed concerns regarding the economics of the redispatch 

proposal.

Response 34: 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 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.
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 rule reinforces that approach by making clear that the concept of emissions rate trading 

is part of the BSER process and can be implemented consistently with the building blocks on 

which it is based. See section V of the final rule preamble of the CPP.

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

Lack of economics in the EPA's re-dispatch proposal

Commenters stated that the environmental dispatch in the proposed rule used to calculate final 

CO2 reductions for each state was done randomly by increasing natural gas combined cycle 

capacity factors to 70 percent regardless of 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 dispatch, 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 purchase 

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 Commissioner 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 significant costs 

to businesses and rate payers. Commenters concluded by saying that the EPA has not authority to 

fundamentally transform the electricity market.

Commenters stated that, by setting the goals at 6% heat rate improvement and 70% NGCC 

capacity, the states' options may be limited 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 region (which 

includes Virginia) may have to shift to an environmental basis rather than the current economic 
355

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 

accommodate 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 costs, 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 operated 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 exceed 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

Commenters 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-cost 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 market 

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 utilities 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 suggests 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 carbonemitting EGUs to ensure that these units dispatch less frequently, or not at all, while at the same 

time pre-serving the economic market maintained by PJM. Commenters stated this contemplated 

construct completely ignores the fundamental principles upon which SCED was developed: costs 

for these units would be artificial in nature; unit efficiency would be ignored as no consideration 

would be given to the technical difficulties 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 economic marketplace is to 

ensure the delivery of reliable electricity to its consumers at affordable rates. Commenters stated 

that a carbon penalty would drastically increase 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 the 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." Commenters 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 stated 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 

stated 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 implementation 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 and 
357

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 ability 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 competitive electricity 

markets like Pennsylvania. Commenters stated Homer City needs an alternative compliance 

mechanism to recoup its capital investments. Commenters referred to EPA modeling55 and stated 

that, (1) due to rising natural gas prices the capacity factor 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 rises 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 

stated 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 referenced 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 

approaches 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 facilities, 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 relatively 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 35: Commenters supported an environmental dispatch approach.

Response 35: 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 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 
358

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:

Commenters 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 proportionate redispatch protocol described in EPA's rule, and the agency has not explained (nor provided record 

support for) its decision. Commenters stated that, if the Clean Power Plan is to reflect the best 

system of emission reduction, as the Clean Air Act requires, EPA must adopt the environmental 

dispatch limitation approach described by the 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 generally 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 state 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 onesixth of the reduction that will be through Block 1's heat rate improvements across the nation's 

coal-fleet. Commenters stated that an environmental approach to dispatch limitation could expect 

simple cycle gas-fired combustion turbines that operate at capacity factors more suited for loweremitting NGCCs (i.e., load-following and base load uses above a 10 percent capacity factor) to 

reduce dispatch in favor of available NGCC capacity, which would reduce the use of natural gas 

and would cut emissions even further. 
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Commenters recommended that Block 2 dispatch should 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 gas 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 twoblock 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 of 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 the very end, these newly constructed NGCC plants similarly will seek to extend their 

lives as long as possible and will continue to emit CO2 for many decades to come. Accordingly, 

EPA must, at a minimum, model the impact of the Proposed Rule through 2050 and 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. Commenters 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 fourblock BSER approach, EPA's emissions target will change, 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 demonstrated. Commenters stated it would also incentivize Block 1 heat rate 

improvement measures within the existing power plant fleet. Commenters stated that a least-
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emissions dispatch system is not a novel concept, rather, it is adequately demonstrated, as a 

similar 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 stated 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 

efficiency 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 fuelgenerated power. Commenters stated that, similarly, the states participating 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 supply 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 requirement 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. Commenters 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. EPA 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 

median 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, 

least-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, 
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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 renewable energy in this manner would also support an 

expansion of emissions reductions that come from Block 3. 

Comment 36: Commenters stated the EPA should abandon its proportionate redispatch 

approach in favor of environmental redispatch.

Response 36: For the EPA’s response to this comment, please see the response to Comment 34 

in 3.2.4.

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

In comments on the Tribal & Territorial 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 classes 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 37: Commenters stated the EPA's BSER ignores the fact that NGCCs tend to be more 

prone to catastrophic failure during operation than coal-fired units.

Response 37: The EPA disagrees that we have inadequately analyzed this issue. Our analysis 

and modeling uses current data on NGCC availability, which reflects historical differences in 

failure rates. See model documentation as 

http://www.epa.gov/airmarkets/powersectormodeling.html.

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 its NGCCs, PowerSouth's available capacity would be significantly diminished 

and fall short of the expected 70 percent capacity factor.
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Comment 38: 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 38: 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 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:

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 generally 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 stated 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 customers use their full capability, then 

there will be little or no excess pipeline capacity to support NGCC units' efforts to achieve the 

70% capacity factor target.

Commenters stated that other federal statutes that affect the construction of interstate natural gas 

pipelines include the Clean Air Act, Clean Water 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 Federal 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 decisions 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 existing 
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pipelines difficult to implement and noted that projects often are opposed by multiple 

stakeholders, including landowners, environmentalists, and others with competing interests. 

Commenters suggested 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 pipelines 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 assume 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 39: Commenters stated that the EPA's analysis 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 39: 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 (using 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 from 2020-2030. 

Commenters stated that, for NGCC to be 35 percent of the country's total energy in 2020, 39 
364

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: Commenters asked for clarification regarding units under used in 2012 and the 

70% capacity factor.

Response 40: For the EPA’s response to this comment, see section V.D of the final rule 

preamble of the CPP.

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

In integrating BB 2 into state goals, why did the EPA treat units that 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 an 8.3% (i.e., 1/12) annual capacity factor?

Why did the EPA determine that the top 10% of NGCC units, operating at a 70% capacity factor, 

was technically feasible for the entire fleet? What were the characteristics of this top 10%? How 

did EPA determine that the top 10% is 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 41: Commenters requested clarification of the items in the GHG Abatement Measures 

TSD, page 3-14:

Response 41: The EPA thanks the commenters for these comments. The TSD has been revised 

for the final rule. See the GHG Mitigation 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 

discussion.

Commenters recommended the EPA clarify or correct a discrepancy in two sets of numbers cited 

as coming from the same data file regarding the CO2 emission rate. Commenters referred to page 

3-5 under the heading "Historical Context" where the CO2 emission rate of U.S. coal power 
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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 base 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% between 2012 and 2020, 

suggested that it is important to evaluate what is expected to be consumed by the LNG export 

facilities which have recently been approved, and noted that EPRI estimates 3.6 trillion cubic 

feet (TCF) per year have already been approved and another 3.6 TCF is under review by DOE.

Commenters stated there is a mismatch between numbers in the reference document and the costbenefit 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 costbenefit 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 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. 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 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 the 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.

Commenters recommended the EPA clarify the discussion on page 3-14, stating the discussion is 

confusing and seems to suggest that the 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. Commenters referred 
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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 goals 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 42: Commenters stated there is nothing in the language of CAA 111(d) that even 

remotely suggests that the EPA has the authority to set limits or require emission reductions for 

existing sources premised on the construction of 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 precluded from 

applying this approach in the final rule.

Response 42: 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-effectiveness 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: Commenters stated that the cost-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 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 
367

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:

Commenters stated that the potential cost-effective role of additional use of natural gas in the 

redispatch of existing and new NGCC units, as well as through gas co-firing in coal units, is 

constrained by the high gas prices and gas price response assumptions (i.e., gas price elasticity) 

in the EPA's IPM modeling analysis. The commenters noted that the gas price forecast in the 

June 2014 IPM base case (adjusted to nominal 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 commenters 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 commenters 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 commenters added that 

since current NYMEX prices are well within the range of NYMEX 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 commenters 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 Henry Hub Natural Gas Futures" available at: 

http://www.ventyx.com/en/solutions/businessoperations/business-products/velocity-suite

Comment 2: Commenters stated that the 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 rule 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 VI.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:
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Commenters stated that, contrary to EPA's analysis in the GHG Abatement Measures TSD in 

which the EPA notes that advances in the production of natural gas have helped to reduce natural 

gas prices - using 2011/2012 in the analysis 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 commenters recommended the EPA either select an earlier year where prices were 

higher or use an average of multiple years to capture the variability 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 the 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 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.1 and VIII.G.2 of the final rule preamble of 

the CPP and Chapter 3 of the GHG Mitigation Measures TSD for the CPP Final Rule supporting 

the final CPP. 

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

Commenters stated that the 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 allows states 

to comply with the proposed rule. Specifically, the commenters stated that the EPA's 

assumptions about increased natural gas use ignore the firm capacity contracts used in the 

industry. The commenters noted that natural gas pipelines have traditionally 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 translated directly into these contracts. 

Commenters 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 non-firm or interruptible contracts. The commenters stated that 

changing this practice of not using long term, firm capacity contracts may require institutional 

and regulatory changes that take time, particularly in areas with organized markets where 

generators cannot pay the premium required to purchase firm pipeline service and remain 

competitive in wholesale electric markets. The commenters referenced an example in the 
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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 reduced 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 commenters 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 consider 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:

Commenters stated that the EPA must consider the competing demands on natural gas 

infrastructure when calculating achievable NGCC utilization rates. The commenters asserted the 

electric power sector competes for pipeline services with two other major natural gas consumers: 

gas LDCs serving residential/commercial sectors and industrial consumers. The commenters

added that consumption by the electric generators does not necessarily coincide with 

consumption in the natural gas transmission system. The commenters stated that a pipeline 

network supporting high levels of natural gas-based generation during electric peak hours is only 

part of the picture as, on an annual basis, natural gas and electricity consumers traditionally 

demonstrate counter-cyclical consumption patterns, helping facilitate greater sharing and 

efficiency in the use of pipeline capacity. The commenters added that gas peak tends to coincide 

with the winter heating season, whereas electric peak usually happens in summer. Increased 

utilization of NGCC units to 70% as sought by the EPA, according to the commenters, will likely 

result in competition between the electric utility and the LDC for the same gas infrastructure, 

thus the EPA needs to further analyze this integrated supply issue.

The commenters 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 commenters stated, they may have excess capacity that they will release or contract to others 

(using interruptible or secondary firm contracts). The commenters stated that because the electric 

and natural gas systems historically have peaked at different times, this "released" capacity was 

available for use by EGUs without firm contracts. According to the commenters, the increased 

use of natural gas by EGUs, industrial customers and distribution companies will increase 

additional competition for this finite existing capacity.

The commenters asserted there are natural gas transmission constraints that will limit increases 

in natural gas-fired generation in Missouri. For example, the commenters stated Southern Star 

Central Gas Pipeline's Line Segment 235 serves KCP&L's Hawthorn, South Harper, Greenwood 

and Ralph Green 3, and Kelson Energy's Dogwood Energy Center. Assuming there is no other 
370

demand on Line Segment 235, asserted the commenters, it does not have sufficient capacity to 

serve the simultaneous maximum hourly flows for all of these units; even though Dogwood and 

South Harper also have access to Panhandle Eastern Pipeline, only recently has a small amount 

of forward haul capacity become available.

The commenters 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 coalfired generation displaced to natural gas and an upgrade of the magnitude necessary to support 

the EPA's target could be substantial. According to the commenters, cost of generation would 

also be significantly higher for the generation 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 rule will further drive up the price of natural gas.

Comment 5: Commenters stated that the EPA should consider the impact of FERC on 

achievability of Building Blocks 2, 3 and 4.

Response 5: The EPA believes that FERC Order 1000 is consistent and compatible with the

111(d) final rule. The rule provides states with 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 comments 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 

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:

Commenters 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 commenters noted that the U.S. Court of Appeals for the DC Circuit 

recently unanimously upheld FERC Order 1000, which updated and enhanced requirements for 

utilities to participate in regional transmission 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. The commenters additionally noted 

that since FERC jurisdiction is limited in Texas, not all Texas utilities are subject 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 states' legal authority to set prices affecting dispatch.
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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 required 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 generators 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 the 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 turn impacts system. See VIII.C of the preamble of the final CPP.

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

Commenters stated that the EPA should address, from a legal perspective, whether a state could 

or should be able to set prices that would influence the dispatch of the electric market.

Commenters cited U.S. Court of Appeals for the 3rd Circuit opinion on case 13-4330. 

Commenters stated the case involve NJ's authority 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:

Commenters 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 commenters asserted that the EPA 

cannot assume the economic impact will be based on a regional trading program since that 

option has not yet been determined to be an economically viable option for any individual 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. The 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 prescriptive, but rather were used to calculate 
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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, 

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:

Commenters stated that the IPM is inconsistent with economic utility practices. Commenters

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. 

Commenters asserted that Pace Global finds the EPA analysis to be inconsistent with economic 

utility practice in its assumption that coal units, specifically Springerville Units 1, 2 and 3, would 

operate for such an extended period of time at sub-optimal dispatch. Commenters stated this 

large reduction in the overall plant utilization at Springerville Generating would result in an 

economic outcome that would favor shutdown over operating the plant at average annual 

capacity factor of 40% over a 10-year period. Commenters stated it would average 30% over a 

10-year period. 

According to commenters, Pace Global does not find this analysis to support Arizona's ability to 

maintain any more than a very minimum capacity of the existing coal fleet online beyond 2019 

while complying with EPA's goals, particularly the interim goal. Commenters stated EPA's 

analysis is flawed and disagrees with the EPA's 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 that the EPA's cost effectiveness evaluation underestimates the 

economic impact of EPA's rule on Arizona.

Response 9: The EPA disagrees with interpretation of the BSER 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 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 
373

and VIII.G.2 of the final rule preamble of the CPP and Chapter 3 of the GHG Mitigation 

Measures TSD for the CPP Final Rule supporting the final CPP. 

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

Commenters stated that the 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 hypothetical, coal-fired EGU to 

a representative NGCC EGU when, in reality, the EPA used the IPM to assess the costs of redispatch [79 FR 34864]. Therefore, the commenters asserted, $30/metric ton represents an 

average cost across the entire modeling domain. This is an important distinction, according to the 

commenters, 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 commenters, the proposal does not provide any information about the range of 

cost effectiveness as it would apply at the source level, probably because the EPA uses an 

electricity-sector-wide approach to determining BSER. 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 commenters, calculate cost effectiveness values 

($/metric ton) for each state. From that data, the commenters stated the EPA would be able to 

evaluate if its chosen BSER is truly cost effective; from that, then determine if adjustments or 

subcategorization is warranted.

The commenters stated they estimated the cost effectiveness 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 commenters estimated that the cost 

effectiveness of the proposal for Arizona (based on compliance with its interim and final goals) 

is at least $122/metric ton. The commenters believed this a conservative estimate, as PACE did 

not run a true business-as-usual case (i.e., absent the CPP). The commenters further estimated 

that $122/metric ton is not a direct comparison 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 commenters stated nothing in the docket explains how Arizona, a significant exporter of 

energy, would become a significant importer by 2020. During a teleconference with EPA 

officials on September 18, 2014, the officials 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 CO2 emissions) to power imported into California, however, 

the commenters do not believe such a shift in interstate power transfers is likely to occur. The 

commenters 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 commenters, as would the cost to abate the resulting emissions to meet 

Arizona's stringent goal.

The commenters stated that a flaw in 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 

availability 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 commenters. While the commenters recognized that it would be difficult for EPA to capture 

that level of granularity, the commenters believed EPA should, at a minimum, acknowledge that 

incorporating these elements accurately would increase the cost of compliance for each of these 

scenarios.

The commenters 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 commenters do not 

believe IPM's turn-down constraints accurately reflect economic realities of operating a large, 

coal-fired unit at low capacity factor. The commenters stated that EPA's compliance case show 

several units at SGS, which is operated by TEP, operating at annual capacity factors far below 

what TEP would consider economical. 

Most significantly, according to the commenters, EPA's cost estimates failed to consider the 

remaining book value of assets forced to retire early. The commenters stated EPA apparently 

dismisses stranded costs based on the notion that states could avoid them through the 

"flexibility" allegedly afforded in the rule. [79 FR 34897] The commenters believe they are 

entitled to recover their capital investment, having approximately $1 billion in book value 

remaining 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 commenters asserted their 

customers would be paying for nearly $1.1 billion in new generation to replace the retired coalfired plants. The commenters concluded these combined costs would have a significant impact 

on retail rates. 

The commenters urged EPA to correct these deficiencies and re-evaluate the cost effectiveness 

of Proposal, recognizing the need for modifications to the final rule to maintain the desired cost 

effectiveness.

Commenters stated that, as proposed, application of BB2 accounts for 77 percent of the required 

reduction in the CO2 emissions/net-MWh in Arizona. The commenters added that EPA 

assumptions result in an overstatement of the amount of coal and gas steam generation in 

Arizona (and likely other states) that could be displaced by NGCC generation starting in 2020. 

The commenters asserted that the costs projected by EPA for implementation of the Proposed 

Carbon Rule must be reevaluated for Arizona and 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 modest 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 increases 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:

Commenters stated that because burning natural gas also releases carbon we must soon phase out 

electric generation from natural gas. Thus, the commenters 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 commenters, must incorporate the estimated cost of switching 

away from natural gas soon thereafter. The commenters asserted that the true cost of switching to 

natural gas now is the cost of that change plus the cost of replacing natural gas with renewables 

(the only feasible alternative) in a few years.

The commenters stated that the EPA's estimates for energy efficiency and renewables are far too 

high, and its estimate for natural gas far too low and that even modest corrections to EPA's 

estimates would show that both efficiency and renewables are cheaper carbon-reducers than 

natural gas. The commenters asserted that switching to natural gas may burden consumers 

because the price of natural gas is expected to rise steeply-23% by 2030. Also, the commenters

believe that if the CPP spurs additional demand for natural gas, it could increase prices further, 

deepening the strain on low-income households, whereas the cost of building renewable 

generation 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 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, 
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 are summaries of the specific public comments under this comment:

Several commenters expressed concern about the economic impact of redispatch, including 

infrastructure. Commenters 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. Commenters noted concern regarding stranded costs for 

existing retrofitted coal units and believed the addition of NGCC would exacerbate stranded 

costs while raising rates to pay for new NGCC units.

Commenters stated that, as a small business entity with only one generating unit, they have no 

other means to supply their customers, thus, redispatching from coal will increase the cost to 

owners/customers. The commenters estimated the cost increase to be 10-20%, dependent on the 

decrease in their output. The increased cost, stated the commenters, 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, 

commenters stated concern that in moving from an "economic dispatch" to an "environmental 

dispatch," units will be called to generate primarily based upon the emission profile of the unit. 

The commenters stated this could be reconciled with economic dispatch if a carbon fee were 

added to each generator's costs to reflect its emissions profile, forcing the costs of greater 

emitting generation higher in the merit order of dispatch. 

The commenters questioned whether there will be sufficient pipeline capacity to support this 

increase in natural gas generation and noted that pipelines have traditionally 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, according to the commenters, often in "organized" wholesale 

markets with day-ahead and real time energy markets that require power plant owners to bid into 

these markets (as opposed to base load plants in vertically integrated markets). For example, the 

commenters 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 commenters 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 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 
377

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:

Several commenters stated that the EPA had not adequately analyzed the economic impacts of 

NGCC dispatch. Commenters stated that EPA guidance did not explain fully how an economical 

dispatch of NGCC will occur and the CPP did not take into consideration the mechanism used to 

require the operation or incentivize utilities under an economical dispatch model to operate 

NGCC plants. The commenters requested that the final CPP specifically address how state plans 

and cooperatives will economically dispatch NGCC units to meet the CPP. The commenters

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 commenters asserted that obtaining rights-ofway is often difficult and time consuming and doing so hastily can create additional costs and 

risk. The commenters also stated that the CPP cost benefit analysis did not consider the cost of 

natural gas pipeline and firm contracts to meet the rule and requested that infrastructure costs to 

meet the CPP using additional NGCC generation be 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 job losses, and tailor the final rule to 

minimize these impacts.

Commenters asserted many of the units that the EPA's IPM model predicts will retire have been 

upgraded recently with emission control equipment mandated by other CAA programs, such as 

the Regional 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 billions of dollars in 

stranded assets; whose costs would be borne either by the units' owners or by ratepayers. The 

commenters added that the forced retirement of coal-fired EGUs would have even more severe 

consequences for merchant generators because coal-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 

significant economic impacts on local economies. For example, the commenters asserted that the 
378

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. The 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 concern 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 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:

Commenters expressed concern regarding the cost of additional natural gas pipeline 

infrastructure that will be needed through 2030. Commenters stated that INGAA estimated that 

the U.S. and Canada will need 28,900 to 61,600 miles of additional natural gas pipelines through 

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 working gas storage 

capacity at an estimated cost of $12.5 billion. Commenters cited tables from a September 2, 2013 

Oil & Gas Journal indicating the U.S. average cost-per-mile for onshore pipeline construction on 

FERC applications submitted by June 30, 2012, was $3.1 million. In addition, commenters stated 

these numbers would be vastly higher if existing 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.

Commenters stated that generators in Pennsylvania must bid into PJM's capacity markets and do 

so on an economic basis. The commenters believed the forced incentivizing of natural gas over 
379

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 commenters 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 concern 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 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.1 and VIII.G.2 of the final rule preamble of the CPP and Chapter 3 of the GHG 

Mitigation Measures TSD for the CPP Final Rule supporting the final CPP.

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

Commenters stated that 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 commenters 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 commenters 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 billion less. The commenters 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 needs to consider that fuel costs vary 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 flexibility 
380

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, 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 coal costs for serving electricity generation vary significantly between 

regions and that the EPA has biased 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 commenters noted that most coal sourced within Minnesota 

comes from the Powder River Basin (PRB) of Montana/Wyoming. The commenters stated that 

Minnesota's imported coal-based electricity is also mostly fueled with lower cost PRB coal and 

North Dakota lignite. The commenters referenced a table from the EIA November 2014 Short 

Term Energy Outlook that portrays how the price of coal for different U.S. regions significantly 

varies, and establishes that the coal serving the Minnesota region is much less expensive than the 

coal delivered for electricity generation in much of the Eastern U.S. An underlying factor for this 

relatively lower cost for PRB and lignite coal, according to the commenters, is the natural 

resource being suited for strip mining. The commenters stated that PRB and lignite also benefit 

from relatively cheap transport by rail across the Great Plains to Midwest utilities for electricity 

generation and mine-mouth to generating unit operation. 

In contrast, the commenters asserted that natural gas pricing that may result from expanded 

operation of existing NGCC units is expected to be more uniform across the U.S., resulting in a 

much higher premium for compliance with the EPA's 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 commenters believed the 

BSER cost-effectiveness analysis should be recognizing a higher coal to natural gas fuel 

switching difference expressed as a cost per ton CO2 reduction in the Midwest compared to the 

eastern U.S. The commenters 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 commenters 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 subregion (state) 

level. The commenters stated that this $53/ton CO2 reduced significantly exceeds the EPA's $36 

per short ton CO2 ($40 per tonne) cost-effectiveness threshold. The commenters asserted that this 

MISO modeled high cost reinforces how Minnesota Integrated Resource Planning that includes 

CO2 cost consideration designates existing NGCC for dispatch to support reliability for 

intermittent renewable resources and to serve peak customer demand periods rather than a base 
381

load dispatch capability. Considering that the cost premium to redispatch existing coal 

generation to existing NGCC exceeds the EPA's own cost effectiveness criteria, the commenters

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 cost effectiveness analysis does not properly 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 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:

Commenters stated that Block 2 redispatch from existing coal to existing NGCC 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 provide 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 commenters 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 commenters 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 power is purchased in the wholesale 

electric market and not self-generated, the commenters stated it exposes utility consumers to 

considerable cost and availability risks. The commenters stated that Minnesota utilities manage 

the risk of market cost exposure for their customers by including a managed segment of 

purchased power in their generation mix. The commenters asserted that Minnesota's IRP process 

requires that utilities consider and manage risk in their overall resource planning processes. The 
382

commenters 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 not 

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, 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:

Commenters 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, commenters said. The EPA's proposal does not take into 

account the billions in stranded costs to consumers if this occurs, commenters further added. The 

commenters asserted not assessing the cost impact is contrary to the EPA's own guidelines 

requiring cost impact assessment of a section 111 proposal. Commenters stated that 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 consequences for the electric grid, electric 

reliability and for the cost of energy to consumers. 

Commenters stated that among the practical problems the EPA has not addressed into its models 

are:
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, were 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: Serious 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 shortfalls that will serve to limit change in 

dispatch.

Similarly, commenters concluded that the EPA should recalculate state goals to account for 

physical constraints, actual gas generation capacity and known pollution control investments. 

Additionally, the commenters believed states should have the flexibility to further adjust goals 

for stranded investment, and physical and permit constraints that prevent or delay redispatch.

Comment 18: Commenters stated that the lack 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) 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.1 and VIII.G.2 of the final rule preamble of the CPP and 
384

Chapter 3 of the GHG Mitigation Measures TSD for the CPP Final Rule supporting the final 

CPP. 

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

Commenters stated that while the EPA believes that the 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 commenters

stated that increased natural gas power generation will require pipeline expansion to maintain a 

reliable source of natural gas, particularly during peak winter heating season. Pipeline 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 commenters. The 

commenters 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 plan, permit, sign 

contracts, finance and build additional infrastructure).

The commenters asserted that the EPA does not value coal fired generation and seems to favor 

shutting down all coal. The commenters stated that risks of losing the coal fleet will be an 

unstable grid, soaring electrical energy pricing due to lack of fuel diversity and the loss of 

economic growth. The commenters suggested the EPA consider recent activities in Germany 

where they are building highly efficient coal fired power plants without carbon controls after 

years of following the same policies the EPA is proposing today. The commenters 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 capacity will be prohibitive and the impact on manufacturing 

will be negative due to higher power prices.

Comment 19: Commenters stated that the EPA's IPM results are not supportable.

Response 19: The EPA disagrees. We consider our analysis 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 

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:
385

Commenters 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 commenters 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 commenters 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 

commenters added that EPA also assumes certain coal units can be operated as cycling/peaking 

units, which is untrue for those units in Arizona.

The commenters added that import capacity into Arizona from New Mexico, taken from a 

Western Electricity Coordinating Council (WECC) report, is overstated by over 3,000 MW. The 

commenters 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 commenters stated EPA did not consider the cost of "stranded assets" in its analysis, which 

in Arizona alone could amount to $3.0 billion. The commenters added that EPA did not consider 

the electric transmission and gas pipeline constraints within Arizona with adoption of the 

proposed rule. The commenters 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 commenters 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 commenters 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 cost 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 goals. 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 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 
386

generation assets, other regulatory requirements and infrastructure. See sections V.A, V.D, 

VIII.A, VIII.C.1 and VIII.G.2 of the final rule preamble of the CPP and Chapter 3 of the GHG 

Mitigation Measures TSD for the CPP Final Rule supporting the final CPP.

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

Commenters 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. Commenters asked for an 

explanation of why the EPA believe the costs in its GHG TSD accurately reflect the cost of 

redispatching NGCC to 70% capacity factor at the state level. The commenters also asked for 

clarification of whether the IPM can restrict redispatch modeling to the same owners. Finally, the 

commenters 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 CO2, 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 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.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. 

Commenters 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, full 

implementation would result in substantial stranded investments in Arizona. For example, 

commenters stated that Unit 4 at the Springerville Generating Station commenced operation in 

December 2009 with bond financing of approximately 30 years with final bond maturity in 2038. 

In addition, commenters stated SRP recently 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 final bond maturity in 2041. The commenters 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

Commenters stated that several existing coal-fired units in Arkansas likely will be forced to retire 

as a result of the proposed rule, resulting in stranded assets for which cost recovery will be a 

significant concern for AECC and its members. The commenters 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 commenters added that if a unit is shut 

down, the historical and present-day costs to build and maintain that unit do not simply go away, 

and there are additional costs in the form of decommissioning and the like associated with the 

closure.

Commenters stated that Florida's ESPS depends 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 commenters asserted the shift would result in the premature closing of many coalfired units, which the Federal government through the Fuel Use Act required us to build and add 

pollution controls. The commenters noted that FMEA utilities recently added $2 billion of "state 

of the art" air pollution control systems to coal plants to meet the emission limits of the CAIR, 

CSAPR and the Utility MATS (UMATS) rules. The commenters 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 prematurely shut down, and also threatens 

electric reliability.

Commenters asserted that application of BB 1 and 2 results in all coal and other steam boiler 

generation units being completely displaced by redispatch of natural gas at a higher capacity 

factor than currently employed in Nevada. The commenters 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 commenters 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 commenters stated NV Energy reasonably assumed it would be able to 

operate the units for a duration such that it would be able to depreciate its investment in 

environmental controls over a reasonable period of time, certainly after 2020. 

Similarly, commenters stated that the EPA did not adequately 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 commenters stated the remaining useful life of 

these units dictates that to avoid 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.

Commenters stated that section 111(d) of the CAA requires the EPA to develop regulations that 

allow states to consider, among other factors, the remaining useful life of the existing source to 

which the standard applies. The commenters stated that while, arguably, the EPA will allow the 

states to take this aspect into consideration 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 commenters suggested 

that 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 of 
388

the existing source to which such standard applies" to address situations where affected EGUs 

have made recent emission control retrofits or have significant remaining book life.

Comment 22: Commenters stated that there is a disproportionate burden on states with 

perceived underutilized NGCC capacity.

Response 22: The EPA disagrees. We believe the comments do not 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 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 infrastructure. See sections V.A, 

V.D, VIII.A, VIII.C.1 and VIII.G.2 of the final rule preamble of the CPP and Chapter 3 of the 

GHG Mitigation Measures TSD for the CPP Final Rule supporting the final CPP. 

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

Commenters stated that while the proposed rule purports to produce a 30% reduction nationally 

in CO2 emissions from EGUs by 2030, Arkansas must produce a disproportionately higher 

amount of reductions (44%) over that same time period because it assumes Arkansas it has a 

relatively large amount of "underutilized" existing NGCC capacity. Based on current fuel prices, 

the commenters stated that the proposed rule's concept of "redispatch" from coal to natural gas 

will cost Arkansas ratepayers an estimated $75 million per year. The commenters added that 

AECC expects that amount to increase over time as natural gas prices increase in response to 

higher demand and constrained supply.

The commenters asserted Arkansas is penalized under the proposed rule because it has been 

diligent for a long time in diversifying its energy portfolio to ensure a proper generation mix that 

includes both coal- and natural gas-fired EGUs, and those efforts ensured access to stable fuel 

prices. The commenters argued that such a burden on one of the smallest and poorest states in the 

country will hamper its ability to join in a regional compliance plan, further limiting its ability to 

offset its disproportionately high 44% compliance burden.

Comment 23: Commenters commented on the cost and 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. The flexibility 
389

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:

Commenters stated that Arkansas has been identified to achieve a significant portion of its 

emission reduction by redispatching NGCC plants to a 70% utilization factor, and that, in 2012, 

approximately 27% of Arkansas' electricity was produced at natural gas plants. The commenters

were concerned this increase will result in either significant coal retirements or major reductions 

in coal utilization, which would result in increased electricity costs and compromised reliability.

Comment 24: Commenters stated that the significant investments required, costs, and timeframe 

assumed under BB2 are unreasonable.

Response 24: The EPA disagrees. We do not agree with the 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 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:

Commenters stated that the BB2 requirement to increase the generation of existing NGCC units 

to a 70% capacity 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 the short 

time leading up to 2020. The commenters asserted that dialing up capacity from 2012 levels to 
390

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 cost impacts for this, the commenters 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 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.1 and VIII.G.2 of the final rule preamble of the CPP and 

Chapter 3 of the GHG Mitigation Measures TSD for the CPP Final Rule supporting the final 

CPP.

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

Commenters stated BB2 entails significant cost, as reflected in the modeling projection that 

Pennsylvania would need to impose a $50/ton CO2 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. Our analysis 

addresses recognizes that different types of EGU’s perform different functions in the market. The 

111(d) final rule requires that states develop 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 
391

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:

Commenters 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 serve 

different functions. Commenters stated first, coal generators provide local reliability support, 

including the ability to restart without any electrical input, voltage stability, and ancillary 

services. Thus, the commenters stated, certain coal facilities may be "reliability must run" units 

that cannot be retired without imperiling local grid reliability. For example, the commenters cited 

a Western Electricity Coordinating Council study that stated:

The path rating for Path 8 [the Montana to 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 caution 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. 

Second, the commenters asserted that coal-fueled EGUs have the ability to stockpile fuel onsite, 

whereas natural gas units receive their fuel through pipelines vulnerable to disruptions. The 

commenters noted that, according to FERC, during last winter's cold weather, numerous natural 

gas generators 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 prices. The commenters 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 

commenters 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 the EPA modeling does not properly account for 

transmission-related constraints and costs.

Response 27: The EPA disagrees. 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 includes, for example, the choice of approaches, 

trading, time to develop plans, additional time before the start of the interim performance period 
392

(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. Commenters stated 

the conclusions reached in the BB2 analysis that suggest Louisiana could, and should, improve 

its generator efficiency performance, and that the IPM assumptions and results simply reflect 

these efficiency opportunities are inconsonant with conclusions reached in prior LPSC 

investigations.

The commenters stated that over the past decade, LPSC has investigated opportunities for better 

utilizing NGCC generation that included leveraging a considerable amount of CHP-based 

generation at many of the state's large industrial facilities, and consistently concluded that in 

most of these investigations expanding newer NGCC generation and ramping down older, less 

efficient natural gas-fired steam generation, come at a cost of billions in transmission-related and 

bulk power sector investments. The commenters noted that LPSC's investigations were based 

upon very detailed multi-area electric generation dispatch 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 commenters stated the EPA correctly notes efficiency opportunities and 

opportunities for reduced emissions across a range of pollutants (not just CO2) through the 

increased utilization and redispatch of NGCC generation are considerable. However, the 

commenters 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 commenters added that while the EPA calculates costs based on the cost of compliance, it 

did not consider the upgrades in transmission required for 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 commenters

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 million. According to the commenters, when 

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 higher than anticipated costs due to 

transmission issues, natural gas prices and forced closures.

Response 28: The EPA thanks the commenters. The EPA believes that the 111(d) final rule

provides states with the flexibility to develop plans that consider reliability and local 
393

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 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:

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. Commenters 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. Commenters asserted that reducing usage of coal-fired EGUs lowers their efficiency 

and, thus, their cost-effectiveness, while potentially increasing emissions of ozone precursors. 

Commenters believed this creates pressure for early retirements, raising the risk of stranded 

assets and higher costs for electricity consumers.

Comment 29: Commenters noted factors influencing power 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 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 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 noted challenges faced in making energy investments. Commenters 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 the challenge of 

climate change. Commenters stated the Lazard analysis provides estimates for key characteristics 
394

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. Commenters

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 finance. According to commenters, 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. Commenters stated the assumption is 

that there is a risk/cost tradeoff that defines an efficient frontier and investors want to be on the 

efficient frontier, where risk and reward are balanced. In applying this framework to the 

evaluation of generation options, the commenters stated that analysts frequently measure reward 

as kilowatts per dollar (a measure of economic efficiency), which is the inverse of cost. 

Commenters believed that options that move the portfolio toward the efficient frontier should be 

adopted since they embody lower cost and/or risk.

Commenters stated that decisions made by utility and independent power producers regarding 

the need for new generation can take years to develop and investments routinely exceed 

hundreds of millions of dollars, and their life expectancy spans 40-50 years. Thus, commenters

stated that investors and financiers look to stable markets/rates and long-term contracts to 

minimize risk and justify these large investments. Commenters believed one of the greatest risks 

in recent years is the regulatory risk that puts those investment decisions in jeopardy. For BB2 to 

succeed, commenters stated investors need clear, unambiguous signals from EPA that this 

proposed rule is the last and final rule regarding power plant emissions. Commenters believed

fuzzy rulemaking commitments and shifting standards hinder any plans to finance new gas-fired 

EGUs and that investors are concerned that environmental groups will next challenge natural 

gas. Commenters urged EPA to provide a clear regulatory framework whereby long-term capitalintensive decisions can be made.

Comment 30: Commenters stated that changing economic dispatch to environmental dispatch 

would raise wholesale market prices by 39% and cost Ohioans $2.5 billion more per year in 

electric costs in 2025.

Response 30: The EPA disagrees with the commenter’s 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 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, 
395

VIII.A, VIII.C.1 and VIII.G.2 of the final rule preamble of the CPP and Chapter 3 of the GHG 

Mitigation Measures TSD for the CPP Final Rule supporting the final CPP. 

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

Commenters stated that to quantify costs associated with implementing environmental dispatch 

in the PJM footprint, the PUCO utilized the Ventyx PROMOD IV modeling software, which 

they considered superior to EPA's IPM for a number of reasons. Specifically, the commenters

asserted PROMOD IV accounts for losses and 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-regional level, including IPM, 

would underestimate the impact of the proposed rule. Additionally, the commenters stated 

PROMOD IV allows for analysis to be conducted under current conditions and for forwardlooking transmission cases to be incorporated into the dispatch algorithm, facilitating long- and 

short-term analysis.

According to the commenters, PUCO's modeling 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. The commenters provided 

a graph (titled: "Wholesale Market Impacts from the Clean Power Plan (based on 2025 projected 

powerflows and prices)"), which shows changes in marginal price per month. The commenters

asserted that BB2 compliance would cost Ohioans approximately $2.5 billion more for electricity 

in 2025 alone. The commenters added that, when considering economic impacts beyond the 

price of electricity, the CPP would impose more strain on Ohioans as the cost of goods and 

services would increase as businesses are forced to pass on higher electricity costs.

Comment 31: Commenters stated that the CPP's volatility 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:

Commenters stated the CPP seems to conflate the concepts of volatility and affordability in its 

attempt to depict expected price increases as within acceptable, normal limits. The commenters

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 downward direction. 

In 2008, according to the commenters, energy price volatility resulted in significant decreases in 

end-user consumer costs. The commenters asserted that energy prices may be significantly 

volatile from year to year with no appreciable net trend either upwards or downwards in 

consumer costs and believed that conflating the 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 unique redispatch challenges for SMMPA and 

the state 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 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.1 and VIII.G.2 of the final rule preamble of the CPP and Chapter 3 of the GHG 

Mitigation Measures TSD for the CPP Final Rule supporting the final CPP. 

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

Commenters stated that Blocks 2 and 3 will significantly increase costs and impair their ability to 

provide affordable power to members. The commenters believed the assumption that utilities can 

increase the average utilization of existing and under-construction NGCC is flawed with respect 

to SMMPA, as NGCC plants are non-existent in its fleet. Thus, the commenters asserted, there is 

no opportunity for SMMPA to redispatch among its own units under BB 2. If EPA insists on 

implementing BB 2, the commenters stated they would have to depend on the purchase of NGCC 

generation from other utilities, resulting in significant additional costs under PPAs after having 

already invested millions of dollars in the construction and improvement of Sherco 3.

Comment 33: Commenters stated 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 establishment 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 the final CPP. Commenters stated that TVA, like 

most utilities and system operators, operates under least cost dispatch principles - seeking to 

meet demand by dispatching lower-cost generation resources before higher-cost resources. With 

regard to energy oversight and rate regulation, the commenters asserted that TVA and Tennessee 

are unique compared to other states. The commenters stated EPA's modeling using the NEEDS 

Database 5.13v3, as an input for planned and future retirements of EGUs in states, does not 

accurately reflect the changing TVA fossil fuel-fired EGU portfolio and past and future 

commitments made to retire and idle units in the state. The commenters recommended EPA 

update its modeling with current data inputs prior to finalizing the guidelines.
397

Comment 34: Commenters stated that the modeling 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 Regulatory Impact 

Analysis of the final CPP.

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

Commenters stated comparison of Model Run (b) with Model Run (c) shows that the EGEAS 

model selects installation of new NGCC capacity instead of operating existing NGCC capacity 

above a 15% capacity factor in 2020, resulting in new NGCC units operating at over 80% 

capacity 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 commenters, and encourage construction of new NGCC units that would not 

otherwise be necessary to meet load. The commenters concluded that market dynamics of the 

proposal significantly disadvantages existing NGCC facilities, regardless of their emissions level 

relative to a new NGCC facility. 

Comment 35: Commenters commented on the cost effectiveness of 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:

Commenters stated that their preliminary analysis shows that Wisconsin can meet EPA's CO2

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 commenters asserted it is costcompetitive 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 commenters, the 30% RPS scenario will also result in highly diversified generation mix 

that will insulate Wisconsin's utilities and electric ratepayers against volatile fuel prices and 

potential CO2 compliance costs. 
398

Comment 36: Commenters stated that the cost 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:

Commenters 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 expected coal 

plant retirements. If market conditions continue to be depressed, the commenters stated that 

generation resources on the margin that are forced to decide between investments to maintain 

viability or retirement, will choose retirement, further exacerbating reliability concerns and 

consumer cost volatility.

Comment 37: Commenters stated that redispatch 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 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.1 and VIII.G.2 of the final rule preamble of the CPP and Chapter 3 of the GHG 

Mitigation Measures TSD for the CPP Final Rule supporting the final CPP.

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

Commenters stated that the EPA's proposal to re-dispatch coal-fired steam generating units to 

NGCC units will result in significant economic harm to the 49 public power communities in 

Georgia that receive their wholesale electric power from MEAG. The commenters asserted 

"environmental dispatch" creates winners (NGCC owners) and losers (coal unit owners) without 

regard to the associated economic harm. The commenters believed 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.

Comment 38: Commenters commented on the treatment 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:

Commenters 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 CO2 annual emissions 

reflecting unimpeded operation across their full operating range. The commenters 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 difference 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 commenters suggested the 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 

CO2 emitting performance regardless of CO2 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 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:

Commenters stated that while the EPA estimates that NGCC power plants can achieve a 70% 

capacity factor, in fact, their availability is in the 85-95% range. The commenters further stated

that the feasibility of higher NGCC utilization should be determined by modeling system-wide 

transmission constraints. Given that the EPA is concerned with consumer costs, the commenters

stated that the EPA should carefully consider how locational marginal prices are affected in order 

to achieve these higher capacity factors and also says that their research indicates consumer costs 

(and capacity markets) could be profoundly affected by market-based mechanisms needed to 

achieve this goal.

Comment 40: Commenters stated that the gas turbine peaking 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:

Commenters stated that as a municipal generator Fremont has very little flexibility. Although the 

commenters 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 results in higher 

operating costs, the commenters explained. The commenters 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 commenters, 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: Commenters suggested 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 proposal 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 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 “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 final CPP. 

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

Commenters 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 within the CPP and 

that compliance can be met by the states in a cost effective manner. In the IPM output data 

summary provided in EPA-HQ-OAR-2013-0602-220.xls, the commenters noted that all of the 

coal or petroleum coke-fired units in Louisiana, except for Cleco's Dolet Hills Unit 1 and Brame 

Unit 3, are designated as "Coal Unit Retirement." The commenters further noted that this leaves 

only the 634 net MW provided by Dolet Hills and the 516 net MW provided by Brame Unit 3 

(presented as two separate 258 MW boilers) to provide a total of 1,150 net MW of coal-fired 

generation after 2020. The commenters 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 an 85% 

capacity factor - 400 MW more than the EPA spares from retirement. The commenters stated 
401

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: Commenters 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.

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 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 “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, Chapter 3 of the GHG Mitigation Measures 

TSD for the CPP Final Rule supporting the final CPP, and the Regulatory Impact Assessment of 

the final CPP.

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

Commenters stated that there is no technical or economic evidence that NGCC power plants can 

sustain generation at a 70 percent capacity factor, as the EPA assumes. The commenters stated 

that the EPA's assumption is derived by using an arbitrary $30/ton CO2 price (tax) as a 

reasonable cost a consumer should pay for fuel switching from lower cost coal generation to 

higher cost sources. The commenters further stated that the EPA would fundamentally convert 

the current electric grid from an economic dispatch to a carbon dispatch model. The commenters

asserted that the EPA's assumptions also 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 understanding of how electric utilities plan and operate to meet demand 

and insure reliability. The commenters 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 commenters also stated 

that the EPA's analysis erroneously indicates that 11 states can replace all of their coal generation 

capacity with NGCC generation. Further the commenters stated that the EPA's 2012 baseline 

inventory includes NGCC units that have been either out of service for several years or retired. 

The commenters also noted that the EPA acknowledges a serious gap of at least 10 percent 

between the amount of natural gas needed to sustain this assumption and the current natural gas 

pipeline delivery network. The commenters finally 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 clarify 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 the 

EPA’s response to this comment.

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

Commenters 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 the plan will factor 

both gains from shutting down coal plants and add back in the impacts of new gas when 

calculating compliance, the commenters 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 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, 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:

The commenters 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 commenters

explained that these increases do not match the EPA's goal for a national average of 51 percent 

by 2030, and that the plant recently dropped its capacity factor to 43 percent in 2013 due to the 

limited natural gas supply in winter months. Regarding the NRG Indian River plant, 

Commenters remarked that the CPP would require reducing generation 13 percent and reducing 

the capacity factor to 34 percent. The commenters explained that the EPA is expecting coal-fired 
403

power plants to hit a national average capacity factor of 73 percent by 2030, but the Indian River 

facility is currently tied for the cleanest coal-fired power plant in the country. The commenters

questioned why the EPA would want this facility to run at half the capacity factor of the national 

average. Finally, commenters stated that the CPP 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: Commenters described why 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 comment:

Commenters rejected claims that increased use of natural gas in the power sector will increase 

natural gas price volatility. Commenters specifically rejected claims that natural gas is inherently 

volatile and should not be increasingly relied upon for power generation. Commenters stated that 

none of the root causes of volatility would be exacerbated by increased use of gas in the power 

sector. Commenters stated that natural gas producers and pipeline companies have invested 

heavily to enhance gas deliverability and mitigate supply shocks.

Commenters stated that concerns that increased natural gas demand "could add upward pressure 

on natural gas prices" are unwarranted. Commenters referred to Figure 8, Henry Hub Natural 

Gas Price (2011$/MMBTU), which shows a range of different price forecasts relative to EIA's 

outlook since 2009. Commenters stated that, as the EPA notes in the RIA, "current and projected 
404

natural gas prices are considerably lower than the prices observed over the past decade." 

Commenters 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 

ramp up production as needed. Commenters stated the vast supplies of natural gas as a result of 

U.S. shale plays mean that there is enough natural gas available to power and heat homes and 

businesses and run vehicles for generations to come. Commenters stated that a stable and 

abundant supply of natural gas will provide for markets, making natural gas an attractive option 

for power generation, transportation, industrial and residential uses.

Commenters stated that natural gas price volatility is defined as "sustained, unpredictable price 

movements" that cause uncertainty for both users and producers of natural gas. Commenters

stated that expected seasonal price fluctuations (e.g., due to greater demand for heating) do not 

constitute "volatility" in the proper use of the term. Commenters 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 volatility: (1) 

the California energy crisis in 2000-2001; (2) the hurricanes of 2005; and (3) the price spike in 

2008. Commenters stated each of these events provided a different lesson in potential causes of 

price volatility: deliverability issues, supply shocks, and erratic market behavior. Commenters

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 

capacity, 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 of 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 indicative 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 increase. 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 

geographic 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 expectation 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 shown in 

Figure 9 (Correlation between natural gas and crude oil, 1997-2013) demonstrates 

that natural gas prices have become less correlated with the price of oil over the 

past 15 years. In today's market, a dramatic and sharp increase in the price of oil 

would not have the same impact on the price of natural gas as it would have had 

historically.

Commenters stated that, outside of these three anomalous events, prices in the period from 2000 

to 2010 were relatively stable, and considering the mitigating factors discussed above, there is 

nothing to suggest that increased use of natural gas in the power sector would cause a market 

disruption similar to these episodes. Commenters 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.

Commenters stated that, in addition to the changes to deliverability and market pricing, 

production from shale formations distributed throughout the U.S. has fundamentally changed the 

industry's ability to respond to price signals. Commenters stated that, in conventional production, 

higher prices drive producers to increase exploration, but the link and timing to actual production 

is lagged and imperfect. Commenters stated production from shale formations reduces 

exploration risk significantly, and allows producers to increase production far more responsively. 

Commenters 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. 

Commenters stated that, with the ability to react efficiently to price signals, production volumes 

should further significantly reduce the risk of sustained, unpredictable price movements. 

Commenters stated this is a major benefit of the size of the technically recoverable total natural 

gas resource base. Commenters stated the rapid 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. Commenters stated the 2013-2014 winter was severe and the rare, 1-in30 winter caused natural gas storage volumes to be depleted to levels not seen since 2003. 

Commenters stated that, due to significant production increases from natural gas producers, 

storage injections set weekly records throughout the injection season; the April 1 to October 31, 

2014 total injection volume set a new season record at 2,734 Bcf.

Comment 2: Commenters stated the EPA's proposal for increasing the dispatch of natural gas 

combined cycle units will lead to increases in natural gas prices and/or price volatility.

Response 2: The EPA disagrees with the commenters’ interpretation of the rule, and we believe 

the commenters’ analyses 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. The 
406

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.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:

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.

Commenters 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%. Commenters 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.

Commenters stated the EPA failed to fully account for impacts to fuel price-stability in the 

evaluation of impacts resulting from removing coal generation from the generating portfolio mix. 

Commenters stated that, due to the shift in the generating portfolio mix resulting from the 

proposed rule, delivered electricity costs will increase by between 12% and 17% between 2017 

and 2031. Commenters 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. 

Commenters stated that one example of risk associated with artificially accelerated changes in 

dispatch is that existing facilities may be forced to purchase additional gas outside of their 

existing contracts; thus incurring additional costs on the spot market. Commenters stated spot 

market pricing is volatile and usually higher than long term contract pricing. 

Commenters claimed that the proposed rule will 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 commenters 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, high 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. 

Commenters expressed concern that the phasing out of older coal-fired power plants by 

increasing electricity generation at natural gas-fired power plants will increase historically 

volatile fuel prices.

Commenters stated that such an unbalanced generation mix leaves Florida extremely vulnerable 

to natural gas price volatility and supply constraints. Commenters, 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.

Commenters 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. Commenters

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. Commenters 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.

Commenters stated that Building Block 2 ignores the importance of portfolio diversity. 

Commenters stated the retirement of coal-fired EGUs places more emphasis on NGCC EGUs, 

thereby limiting portfolio diversity and creating significant vulnerability to natural gas price 

fluctuations. Commenters 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 commenters stated it important to maintain portfolio diversity in 

order to minimize cost volatility to ratepayers. Commenters stated that, while recently the United 

States has enjoyed low natural gas prices, those prices are likely to rise in the face of increased 

competition for supply due to nationwide increased utilization of existing NGCC EGUs and 

construction of new NGCC EGUs. Commenters stated that additional environmental regulation 

may also cause natural gas prices to rise.

Commenters stated that, because the natural 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. Commenters stated that this volatility is likely to be 
408

particularly true upon the implementation of EPA's Proposed Rule, which would drastically 

increase the demand for natural gas, despite EPA's cursory statement otherwise.

Commenters stated that, historically, natural gas prices are highly volatile and increased use of 

natural gas for electricity generation is constrained by transmission capacity, particularly in the 

U.S. Northeast. Commenters stated that, while the economics for increased natural gas 

generation are favorable presently, the history of natural gas prices in the U.S. has shown that 

current natural gas price trends can shift rapidly and unpredictably. By creating goals for states to 

increase their natural gas consumption, commenters stated the EPA is only increasing the 

likelihood of potential steep natural gas price increases that would be passed on to ratepayers 

across the country as higher electricity prices. Commenters stated that the more electricity that is 

natural gas fired, the greater would be the effect on ratepayers of a steep increase in natural gas 

prices.

Commenters stated that, as coal units are forced to retire to meet the CPP goals, this will cause 

more volatility in the price of natural gas, which will begin a never-ending trend upward as 

demand outstrips supply. Commenters stated the MISO has conducted an economic-only 

analysis that has estimated that in its region 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 coal resources, there will be a rush to gas as utilities and 

merchants scramble to fill the void with NGCC resources.

Commenters expressed concern that the cost of spot energy can be difficult to control, especially 

during inclement weather. Commenters 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.

Commenters 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. Commenters noted that last spring during 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.

Commenters expressed concerned that natural gas is subject to substantial price fluctuations that 

create market uncertainty. Commenters suggested the EPA should consider the consequences of 

using a price-volatile fuel such as natural gas to meet our needs year-round. Commenters stated 

that renewable energy is a more price-stable form of electricity generation. Commenters stated 

that natural gas is more price volatile than renewable energy or coal power generation, and is 

particularly susceptible to spiking during cold weather. 

Commenters stated that, while the EPA assumes natural gas prices will remain low and supplies 

high, the natural gas market is becoming increasingly volatile. Commenters suggested the EPA 

lower the NGCC capacity factor to a more realistic goal.

Commenters expressed concern that future increased gas prices may render NGCC generation 

less economic and adequate coal-fired resources may not be available to meet resource adequacy 
409

requirements in PJM. Commenters contended that PJM's existing coal fleet may not be able to 

provide adequate flexible operations as most existing coal plants were not originally designed for 

load following and/or extended low output generation. Commenters are also concerned that 

establishing a dispatch-based mitigation goal that impacts other existing generation types without 

thorough consideration of the impacts to resource adequacy may significantly degrade reliability. 

Commenters stated this concern is best exemplified by the experiences in the PJM region during 

the January 2014 polar vortex event, when a 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. 

Commenters stated that, despite these challenging conditions, PJM's robust generation portfolio 

was able to weather the period without major service outages. Commenters stated they are 

concerned that, under a future scenario where the EPA's BB1 and BB2 proposals 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.

Commenters did not agree that natural gas prices will remain relatively flat through 2030. 

Commenters 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. Commenters provided Figure 4 showing the volatility of natural gas as compared to 

coal since the late 1990's. Commenters stated the proposed rule would expose OMU's ratepayers 

to significantly more natural gas price risk. Commenters stated the impact of natural gas price

volatility was recently demonstrated during the Polar Vortex of 2014. Commenters stated that 

were OMU's ratepayers exposed to these high natural gas prices during the Polar Vortex, they 

would have had electric bills that were more than 30% higher than normal. Commenters

provided Figure 5 and Figure 6 to show the extreme volatility of natural gas and the stability of 

coal prices during the 2014 "Polar Vortex."

Commenters stated the move to a greater dependence on natural gas places Florida and the City's 

electric grid at a greater risk to price spikes, 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 regions during the oil embargos of the 1970's).

Commenters 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. Commenters stated TVA passes along 

all fuel costs used in 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. Commenters stated that natural gas price 

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. 

Commenters referred to EIA data comparing the price fluctuation between natural gas and coal 

and stated the price volatility of natural gas stands in stark contrast to coal's historically stable 

price. Commenters stated this natural gas volatility continues in spite of growing natural gas 

production. 

Commenters expressed concern that increased use of natural gas nationally could lead to 

increased market dislocations, such those as seen in the winter of 2013-2014, as well as overall 

increasing prices and price volatility due to higher gas demand. Commenters stated 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: Commenters 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 emission 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 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:

Commenters stated that firm fuel arrangements and spot market natural gas procurement can be 

volatile and costly. Commenters 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 exorbitant 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 generator 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 PJM footprint.

Comment 4: Some commenters focused mainly on fossil portfolio diversity, while others 

insisted 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:

Commenters stated the portfolio diversity of the 21st century must be a combination of 

renewable energy generation and demand-side resources including efficiency, demand response, 

storage, etc. Commenters 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 EPA disagrees with the commenters’ interpretation of the rule, and we believe 

the commenters’ analyses do 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 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, and the Regulatory 

Impact Assessment of the final CPP.

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

Commenters stated the EPA's proposal to increase 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. Commenters 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 Virginia's coal and electricity exports to other 

states.

Commenters stated that fuel diversity ensures competition and lower prices. Commenters stated 

that, when demand increases throughout the US, in all industrial sectors, not just the utility 

sector, higher gas prices will result in increased prices for electric power. Commenters noted that 

EIA projects that the RFC region, which includes Ohio, confronts one of the highest growth 
412

demands for natural gas as utilities shift from coal. Commenters stated that it is unwise to rely 

too heavily on any single source of energy because, like any other commodity, natural gas is 

susceptible to fluctuations in supply, demand and price - not to mention the specter of additional 

environmental and drilling regulations, which could have a serious impact on future production 

and price levels.

Commenters stated that the lack of fuel diversity would negatively impact on cost. Commenters

stated that, by increasing reliance on natural gas, the proposed rule creates a market in which 

many participants want the same product which will likely increase the price demanded. 

Commenters stated the upper Midwest relies heavily on natural gas for winter heating, and it is 

also used in industrial processes such as ethanol production. Commenters stated that additional 

build-up of natural gas to support grid reliability will increase the price for the product and could 

decrease the availability that some parts of the nation have enjoyed in recent years. Commenters

stated that natural gas contracts 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 prices each 

time contracts are discussed for renewal. 

Commenters 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 previously Southern Company has utilized its ability to dispatch its 

generation fleet to reliably serve customers in the lowest cost manner. Commenters stressed the 

danger of disregarding the uncertainty of future fuel prices and the potential benefits of utilizing 

a variety of fuels to mitigate those uncertainties. Commenters indicated that Southern Company 

is dedicated to providing a diverse electricity generation portfolio to the benefit of approximately 

4.4 million customers in the Southeast, nearly half of whom earn less than $40,000 per year. 

According to the commenters, in 2012, across the Southern Company system, fuel costs were 

reduced by over $1 billion by leveraging a diverse fuel mix to the benefit of its customers.246

Commenters added that while natural gas has been 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 gas prices fluctuate. 

Commenters 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.

Commenters stated that it is in the national interest for utilities to have the opportunity to 

maintain generation fleet diversity in order to hedge against fuel price fluctuations, and thereby 

protect customers. Commenters indicated that for decades available coal generation has 

mitigated against natural gas price increases and vice versa - the wide pendulum swing of fuel 

costs can only be damped by maintaining a diverse portfolio of generation assets. Commenters

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 customers.

Commenters stated that recent analysis conducted by Georgia Power assessed the impact that 

plausible natural gas price forecasts for the year 2020 would have on the most cost-effective mix 

of generation resources. According to the commenters, the analysis showed that natural gas 
413

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 company would minimize costs for its customers by generating 

only 28 percent from natural gas and 40 percent from coal. Commenters indicated that the EPA's 

proposal would prevent utilities from continuing to develop a fleet that relies on diverse fuel 

mixes for the benefit of their customers. Commenters 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. 

Commenters provided an example which commenters 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 customers: 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). Commenters provided a figure showing the capacity factors for Plant Daniel's 

four units over the period of 2002 to 2013. According to the commenters, 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 EPA disagrees with the commenters’ interpretation of the rule, and we believe 

the commenters’ analyses 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 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, and the Regulatory Impact Assessment of the final CPP.

The following are summaries of the specific public comments under this comment:
414

Commenters 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. Commenters 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.

Commenters 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. Commenters 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. Commenters 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. Commenters 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. Commenters stated that, noting the uncertainty associated with the longterm impacts to natural gas pricing associated with the incremental demand under 

a Clean Power Plan compliance scenario, these costs were assessed both with and 

without the impacts of potential higher gas pricing. Commenters referenced their 

Exhibit 22, which compares these costs, and stated the analysis shows that the 

current building block plan would cost electric 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. Commenters 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, commenters stated the price 

increase under the Clean Power Plan is around $1.35 on average between 2020 

and 2030, with deltas in the $1.50-2.00/MMBtu range by the end of the 2020s. 

Commenters noted Henry Hub pricing projections for the reference case and the 

EPA Building Bock scenarios are presented in Exhibit 24.

Commenters stated that natural gas utilities would be negatively affected by the Proposal. 

Commenters 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 increase 
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as market demand for firm transportation increases and pipeline companies seek 

recovery of pipeline system expansion costs. While UNSG is not a power 

producer, pipeline companies spread the costs of 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 rates 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 expose utilities and 

other system users to additional risk due to unforeseeable future conditions.

• Commenters stated that UNSG customers will bear the costs of gas storage, which 

will need to be developed to support the increased natural gas-fired generation 

resulting from the proposed rule. Existing storage facilities in New Mexico and 

Texas are too remote to assist in managing pipeline reliability in Arizona; 

therefore, storage will need to be built in or near Arizona. Without any change in 

UNSG customers' usage, the increase in natural gas demand from the power 

sector will require that UNSG acquire storage to ensure reliability. When 

combined, these increases in commodity costs, transportation costs, and storage 

costs will increase both electric and gas rates for UNSG customers. 

Comment 7: Commenters stated the EPA underestimated not only how much the proposed rule 

will raise electricity prices, but natural gas 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 develop their plans, 

including system reliability, fuel diversity, the “useful life” of generation assets, other regulatory 

requirements and competing demands for natural gas. We believe our analysis is appropriate and 

we do not expect the 111(d) final rule to result in large increases in natural gas prices. See 

sections V.A, V.D, VIII.A, VIII.C.1 and VIII.G.2 of the final rule preamble of the CPP, Chapter 

3 of the GHG Mitigation Measures TSD for the CPP 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 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 industrial sector would be hit the hardest, seeing their electricity and gas costs soar 
416

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 in 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 EPA disagrees with the commenters’ 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 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, 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 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 the EPA's proposal for increasing the use of natural 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. Commenters stated that increasing electricity demand, coupled 

with decreased supply, is a recipe for skyrocketing electricity prices that will be passed directly 

on to the consumers. Commenters stated their area has already seen increased costs due to 

renewable standards and mass associated plant closures. Commenters stated their communities 

and consumers cannot afford another round of EPA-related plant closures.

Commenters stated the EPA's proposal would lead to a significant increase in the cost of natural 

gas for both electricity generators and other consumers. Commenters stated that the EPA's own 

projections demonstrate that this cost increase would be especially severe in the near term. 

Commenters 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. Commenters stated these 

impacts, in combination with the up to 49 gigawatts of additional coal retirements that EPA 
417

projects by 2020 (Regulatory Impact Analysis at 3-32), could deal a severe blow to American 

workers.

Commenters noted that the EPA projects that the Clean Power Plan will lead to further increases 

in delivered natural gas prices of 7.5% to 11.5% in 2020 (CPP RIA, June 2014). Commenters

stated that the U.S. DOE's projection for Henry Hub wellhead natural gas prices do not account 

for the increase in natural gas demand expected to result from EPA's proposed Clean Power 

Plan. Commenters stated that the Henry Hub wellhead prices are a key determinant of future 

electricity prices. Commenters stated the EPA's CPP will substantially increase electric prices for 

America's 65+ households. Commenters stated the 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. Commenters

stated the existing EPA rules are already driving up the costs of natural gas and electricity prices 

and the new proposal will add even more unacceptable costs.

Commenters stated MRES expects future demand for transmission expansion to be great under 

the Clean Power Plan. Commenters 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 Americans. Commenters 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.

Commenters stated the proposed rule does not properly account for infrastructure from either a 

timing or a cost perspective. Commenters stated the costs of this shift in generation toward 

NGCC would require an unprecedented investment in infrastructure, including construction of 

new NGCC capacity, natural gas pipelines, and transmission infrastructure. Commenters 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 analyses and could trigger review under the Endangered 

Species Act.

Commenters 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. Commenters noted the EIA's Annual Energy Outlook

estimates that residential natural gas prices will increase by about 1.4 percent per year, from 

$10.69 to $13.80 per 1,000 cubic feet (in 2012 dollars), between 2012 and 2030 in the reference 

case. Commenters 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 impact on low-income households 

than the draft CPP. Commenters stated the trajectory proposed by the CPP is about the same as 

the natural gas reference case in EIA AEO 2014 (Table 13). Commenters stated the price 

increases estimated there would cause significant hardship to low-income households, especially 

those using natural gas for heating, which is the case for about half of U.S. households. 

Commenters 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 since 
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about 2006. Commenters 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. 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 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 and Chapter 3 of the GHG Mitigation Measures 

TSD for the CPP Final Rule supporting the final CPP, and the Regulatory Impact Assessment of 

the final CPP. 

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

Commenters stated that natural gas is a globally traded commodity and the price will eventually 

more closely reflect the global prices. Commenters stated that cheap, domestic natural gas prices 

are likely a short-term phenomenon and will move closer to either the historic domestic price 

volatility or possibly even soar to a level much higher based on global demand. Commenters

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?

Commenters stated the 2012 model year does not take into consideration variations in natural gas 

prices and how states will dispatch NGCC units economically. Commenters 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 state and (2) the CPP should include in their 

cost benefit analysis a forecasted price for carbon reductions per ton or other methods to 

artificially inflate gene ration cost to drive economic dispatch by states to facilitate the NGCC 

generation required to meet emission targets.

Commenters stated the EPA should evaluate any variance in natural gas supply or pricing under 

this proposal. Commenters stated this variable needs to be explored through sensitivity analysis 

and reporting of potential costs. Commenters noted that it has been well understood and 

documented within the electric power sector that natural gas supply and prices play a pivotal role 

in determining both the current and projected future electricity mix, as well as electricity costs. 

Commenters stated 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

Commenters stated the EPA should conduct a thorough analysis of the proposed rule's impact on 

natural gas prices in Indiana and the effects that will have on Indiana consumers and the state's 

economy. Commenters stated proposed rule will greatly increase demand for natural gas, 

creating upward pressure on prices and operating costs. Commenters 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 increase 

in wholesale electricity prices EPA and others anticipate taking place as a result of the proposed 

rule. Commenters stated the EPA views these projected impacts as not unreasonable because the 

price increases in question are well within the range of historical natural gas price variability (79 

FR 34865). Commenters 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. Commenters 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. 

Thus, if natural gas prices increase (or decrease) by $1/mmBtu, a customer's bill will increase 

(decrease) by $1 for every mmBtu of natural gas 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, infrastructure and competing demands. The IPM model includes a 

natural gas supply module that includes demand and supply of natural gas nationwide. In 

response to additional analysis and many comments, we have modified the proposal and RIA. 

States may consider local circumstances as they 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 sections 

V.A, V.D, VIII.A, VIII.C.1 and VIII.G.2 of the final rule preamble of the CPP, Chapter 3 of the 

GHG Mitigation Measures TSD for the CPP Final Rule supporting the final CPP, and the 

Regulatory Impact Assessment of the final CPP, and the Regulatory Impact Assessment of the 

final CPP.

The following are summaries of the specific public comments under this comment:
420

Commenters stated this volatility has impacted not only the prices utilities pay for natural gas, 

but also the wholesale price of electricity. Commenters cited several reported prices including 

above $200 per megawatt hour (MWh) during a brief cold spell in mid-December 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. Commenters

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. 

Commenters 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. 

Commenters listed several factors that could put upward pressure 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. 

Commenters referenced a 2010 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. Commenters stated that EPA's Proposed Rule assumes that prices will remain 

relatively 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. 

Commenters stated that the Proposed Rule does not take into account 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. 

Commenters cited a July 15, 2010 Navigant Consulting paper on price instability in the U.S. 

Natural Gas Industry which concludes that "the vitality of and responsiveness of the supplydemand balance is the most important factor determining whether price volatility in either 

direction will occur." Commenters stated that, while current natural gas supply is ample and 

prices are relatively low, they are concerned this may not remain the case prospectively and, 

therefore request the Agency to ensure that its 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. Commenters stated the price of natural gas has increased 

significantly since the Proposed Rule was announced in June 2014 from about $3.50 to $4.04 

Mcf. 

Commenters stated that the Proposed Rule does not 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. Commenters stated that the 

EPA needs to examine the combined impact of greater use of natural gas for electric generation 

and manufacturing on supply and prices.

Commenters observed there is a secondary issue that needs to be addressed in the RIA: the 

storage of natural gas and normal demand is met by gas that is purchased on long-term fixed 
421

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. Commenters stated the impact of this affects the users of natural gas as 

well as the price of electricity generated using natural gas.

Commenters urged the EPA to more closely examine the complex dynamics of the natural gas 

delivery system and the potential impacts of altering these dynamics on both natural gas and 

electricity costs to the consumer. Commenters 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 

impacted in a negative manner. Commenters stated it is also possible that the proposed rule could 

force natural gas units to secure firm contracts in markets where such action would be 

uneconomical. Commenters stated that, in Ohio, residential and industrial natural gas 

consumption represented 61% of all natural gas consumed in the State of Ohio in 2012. Given 

these numbers, commenters stated, the EPA must consider the complex dynamics of the natural 

gas delivery market, the role of natural gas as an economic source of residential heating, if 

realistic re-dispatch goals are to be set. Commenters 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. Commenters noted they have significant 

concerns with even a projected 10% increase in delivered natural gas prices from this proposal 

alone.

Commenters expressed concern regarding potential increases in natural-gas prices caused by the 

CPP. Commenters 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 functioning of society. Commenters

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 attributable to the CPP Commenters stated there could also be a 

significant increase in the price of natural gas causing harm to consumers and Arkansas 

businesses. Commenters noted the EPA's own analysis of the CPP reflects a 12% increase in 

natural gas costs resulting from plan implementation. Commenters stated that, while the EPA has 

asserted that each individual building-block target that is assigned to each state is based on 

"reasonably achievable rather than maximum performance levels," the technology assumptions 

have yet to be demonstrated as achievable at a reasonable cost or, in some cases, achievable at 

any cost.

Commenters 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. Commenters stated that price spikes in the northeast 

last winter, for example, exceeded $123.50/MMBtu. Commenters 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 sector natural gas demand projected 

under the Clean Power Plan.

Commenters expressed concern that the EPA did not consider the significant negative impact of 

price volatility on energy-intensive, trade-exposed (EITE) manufacturers. Commenters stated 

that natural gas prices are known for being relatively volatile and that sudden increases in 
422

demand such as that the proposed rule will generate, coupled with existing strains on 

infrastructure in parts of the country, will cause price spikes that disproportionately impact 

domestic EITE manufacturers. Commenters stated that the EPA's acknowledgement of an 

increase in natural gas demand prior to 2020, combined with a higher-than-expected industrial 

demand for natural gas, must push natural gas prices higher than EPA estimates. 

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. 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 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 of the GHG Mitigation Measures TSD 

for the CPP Final Rule supporting the final CPP, and the Regulatory Impact Assessment of the 

final CPP and the Regulatory Impact Assessment of the final CPP. The EPA considers the EIA 

Annual Energy Outlook 2015 cases for high and low oil and gas supply. Any comments 

regarding regulation of the natural gas extraction or supply industry are outside of the scope of 

the CPP final rule. 

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

Commenters stated that EPA needs to look at the issue of future local, state, and federal 

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. Commenters 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 production; 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, specialty tank cars and other rail equipment used to 

transport natural gas. 

Commenters 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 natural gas in the future. 

Commenters 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 gas 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. Commenters stated that State- and local-level regulation 
423

has included fracking bans and moratoria including, for example, a ban on fracking in Vermont 

and statewide moratoria in New York, Maryland, and North Carolina. Commenters stated that, as 

a result, it is reckless and short-sighted to rely so heavily on current and projected natural gas 

availability and prices in proposing this rule.

Commenters stated that simple economics indicates 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. 

Commenters stated that a related concern regarding natural gas prices is the EPA's plans for 

possible expanded controls over fracking and natural gas recovery. Commenters requested the 

EPA to clarify its regulatory plans for fracking operations prior to finalizing the CPP.

Comment 12: Commenters 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 

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 preamble of the CPP, Chapter 3 of the GHG Mitigation Measures 

TSD for the CPP Final Rule supporting the final CPP, and the Regulatory Impact Assessment of 

the final CPP. al CPP.

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

Commenters stated that the gas price response (i.e., gas price elasticity assumptions) built into 

EPA's IPM model appears to be materially higher than those reflected in the February 2014 

NorthBridge analysis of the CATF Power Switch approach and the October 2014 Rhodium 

Group analysis of the CPP using the NEMS modeling platform. Commenters 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 platform by at least 

factor of 2 to 6. Commenters 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 reserves and, as a result, EPA's modeling could overstate 

the natural gas price impact of the CPP policy and needlessly constrain the potentially costeffective role of additional use of natural gas in re-dispatch of existing and new NGCC units as 

well as through gas co-firing in coal units. 

Commenters stated that since the base case prices appear high, the increase in gas prices 

forecasted in the policy cases may well also be overstated. Commenters stated that if there is 
424

more natural gas available at relatively low prices, then increased demand for natural gas may 

cause prices to rise by a smaller amount than forecasted in the IPM policy cases. Commenters

stated that this overstatement of gas prices raises the estimated cost of the CPP rule and can 

cause the role of gas in the compliance mix to be understated. Commenters 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 heating and electric 

generation, as well as offshore sales of liquefied natural gas. 

Commenters 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. Commenters stated that natural gas is a globally traded commodity and the 

price will eventually more closely reflect the global prices; thus, cheap domestic natural gas 

prices are likely a short-term phenomenon and will move closer to either the historic domestic 

price volatility or possibly even soar to a level much higher based on global demand. 

Commenters 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 

consistently 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:

Commenters stated that establishing a mitigation goal based on an assumption of persistent low 

natural gas prices is not a reliable or dependable approach to estimating capacity factors for 

NGCC plants over a long period. Commenters 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". Commenters 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, commenters 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. 

Commenters stated that numerous industry studies demonstrate the historical volatility and 

unpredictability of natural gas prices. Commenters stated that this information illustrates the 

danger of EPA's reliance on forecasted natural gas prices for its policy choice. Commenters cited 

in particular, a June 2012 study completed by NERA which addresses the difficulty in accurately 

forecasting natural gas prices. Commenters stated 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 

indicators of the actual natural gas price with large errors and biases in the most widely used 
425

forecasts, including forecasts from the Energy Information Administration (EIA). Commenters

stated that, while domestic natural gas prices have been historically low, the swing away from 

natural gas could be abrupt, especially because the U.S. natural gas market does not reflect 

current global price trends (citing EIA, 2011). Commenters 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. 

Commenters provided data indicating that natural gas prices have been historically volatile and 

unpredictable. Commenters objected to the proposed rule because it relies on potentially 

erroneous projections that may not only shift, but may drastically shift, thus exposing the 

reliability of the nation's energy grid to a highly volatile commodity.

Commenters stated the EPA should not assume that present low prices will sustain their 

emissions reduction objectives. Commenters 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. Commenters stated the EPA's analysis suggests that low 

natural gas prices will enable sustained operations at a high capacity factor, but this is a very 

dubious assumption. Commenters explained that natural gas has a highly volatile price curve, 

and multi-year projections are regularly inaccurate. Commenters stated that, even short-term 

events can cause wild oscillations in the price of natural gas; last winter's polar vortex so stressed 

natural gas infrastructure in the northeast that many natural gas facilities had to curtail operations 

or sell power at absurdly high prices. 

Commenters 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 plants over a long period. 

Commenters 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 

commenters stated that, for example, during extreme temperatures across most of the Southern 

and Eastern United States from January 6 to 8, 2014, natural gas generating plants did not 

perform as expected due to both plant outages and natural gas delivery system inadequacies. 

Commenters stated that the assumption that natural gas prices will remain relatively flat through 

2030 fails to take into account the historic volatility of natural gas, the impact on price from 

future regulations on upstream production, or how increased demand will put upward pressure on 

prices. 

Commenters stated that, in establishing its NGCC capacity target, EPA should be sensitive to the 

long-term impact on natural gas prices. Commenters stated that, while the EPA contends natural 

gas prices will remain low going forward, the EPA's projection suffers from the same 

uncertainties that have characterized natural gas 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. 

Commenters provided a graph which illustrated the price volatility for natural gas rom 1991-

2013 as ranging from $1-14 per dekatherm. Commenters stated that mandating reliance on 

NGCC units will increase the price of natural gas as both gas supplies and delivery capacity 

become constrained across the country. Commenters stated that enhanced reliance on NGCC 
426

units as baseload capacity will put upward pressure on both wholesale and retail natural gas 

prices, which will ultimately be borne by electric and natural gas ratepayers.

Comment 14: Commenters supported the EPA's determination not to base its goal-setting 

calculations for reduced utilization of coal-fired EGUs based on retirements directly, but instead 

on the availability of underutilized NGCC capacity.

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:

Commenters 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 assign a probability of 

closing a plant by a certain date until a final determination is made. 

Commenters supported the EPA's determination not to base its goal-setting calculations for 

reduced utilization of coal-fired EGUs based on retirements directly, but instead on the 

availability of underutilized NGCC capacity.

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 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 their 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 preamble of the CPP and Chapter 3 of the GHG 

Mitigation Measures TSD for the CPP Final Rule supporting the final CPP, and the Regulatory 

Impact Assessment of the final CPP. 

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

Commenters stated 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. Commenters stated that the growth in 

international trade in natural gas facilitated by construction of LNG terminals in the U.S. and 
427

other major exporting countries could expose the power industry to significant price shocks or 

supply disruptions. Commenters stated the EPA has failed to consider the impacts of LNG 

exports and increased non-electric utility demand on natural gas supply. 

Commenters stated the manufacturing sector serves as an example of the unintended loss that 

would occur as the economic benefits of increased manufacturing in the U.S. economy would 

decrease due to LNG exports. Commenters stated their analysis disproves the notion that the 

shale-driven natural gas supply curve is flat and instead shows that it is upward sloping. 

Commenters 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/MMBtu by 

2030. Commenters stated that layering in additional demand from LNG exports in the Likely and 

High Export scenarios would raise prices to $8.8/MMBtu and $10.3/MMBtu in 2030, 

respectively, assuming no price-induced demand feedback. Commenters 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 costs 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 exiting 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 relative 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/petroleum/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. 

Commenters 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 around 

$20/MMBtu. Subtracting the costs of liquefaction, shipping, and regasification (netback costs) of 

$6/MMBtu, commenters stated that exports to Asia are attractive with domestic natural gas 

prices up to $14/MMBtu. Commenters stated this netback price is well 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 manufacturing.
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 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 their 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 preamble of the CPP and Chapter 3 of the GHG Mitigation Measures 

TSD for the CPP Final Rule supporting the final CPP, and the Regulatory Impact Assessment of 

the final CPP.

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

Commenters stated that 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. 

Commenters 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 manufacturing, as well as the heating cost 

impact for commercial and residential natural gas users, in the economic impact assessment for 

the proposed rule. Commenters stated that most energy intensive manufacturing is located in 

states with low energy cost structures 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.

Commenters 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 considerations, 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 jobcreating engine of economic growth. Commenters stated that current natural gas export growth in 

Australia provides a cautionary scenario in this regard. Commenters stated that, in Australia, 

significant growth in natural gas production has been accompanied by a tripling of wholesale 

natural gas prices in the domestic market due to the explosive growth in Australia's natural gas 

export market. Commenters stated this is occurring even with the recent repeal of Australia's 

carbon tax and without the concurrent pressures of an electricity generating base that is rapidly 

shifting to natural gas fuels, as is contemplated by the proposed 111(d) rule. Commenters stated 

these pressures in the US would have a significant detrimental affect not only on the broad US 

manufacturing base but specifically on the production of secondary (recycled) aluminum given 

the role natural gas as a key input into the secondary aluminum recycling process.

Commenters stated the proposed Clean Power Plan focuses on electricity, but the increased use 

of natural gas by power industry to comply also will put upward pressure on natural gas costs, an 

important energy source for South Carolina manufacturers
429

Commenters stated the EPA failed to assess the economic effects on other economic sectors from 

higher natural gas prices or potential gaps in the incremental natural gas supply. Commenters

noted that many sectors of the economy rely on natural gas and have increased natural gas 

consumption since pre-recession levels, including the power, industrial, and transportation 

sectors. Commenters stated that natural gas exports will begin to coincide with the accelerated 

retirement of coal generators. Commenters noted that (1) four liquefied natural gas 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 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. Commenters stated the 

EPA's analysis does not even touch upon, let alone analyze, any of these market developments 

and how the proposed rule will affect the economic sectors and residential customers that depend 

upon natural gas. 

Commenters stated that recent history provides more than ample experience on the scope and 

depth of the consequences of over-relying on natural gas. Commenters 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. Commenters stated this occurred even when natural gas 

demand fell-but prices increased by 160 percent. Commenters stated all of this coincided with an 

increase in natural gas power plant builds and a 27 percent increase in natural gas consumption 

in the power sector-more than three times the overall growth in natural gas demand by all 

sectors. Commenters concluded that there is little question of the direct correlation between 

manufacturing job losses and higher and more volatile natural gas prices during this period. 

Commenters presented a figure, which illustrates a decline in employment in the manufacturing 

sector from 1195 to 2005 (a reduction of over 3,000 jobs) (Figure: U.S. Manufacturing 

Employment 1195-2005; Data Source: U.S. Bureau of Labor Statistics). 

Commenters 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 could restrict use of their land for 

agricultural purposes.

Response 17: The EPA disagrees to the extent that we we believe our analysis appropriately 

considers natural gas supplies, infrastructure and competing demands. The IPM model includes a 

natural gas supply module that includes demand and supply of natural gas nationwide. In 

response to additional analysis and many comments, we have modified the proposal and RIA. 
430

States may consider local circumstances as they develop their plans, including system reliability, 

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 111(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 for 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 the 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 infrastructure 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 Analysis of the CPP final rule. 

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

Commenters stated farmers and ranchers could be affected in another, more direct way by any 

wide volatility in natural gas prices. Commenters 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. Commenters stated 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 activists continue to 

increase pressure on regulatory agencies to oppose fracking. Commenters 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.

Commenters stated the CPP will undoubtedly increase the average cost of electric generation as 

well as increase the price for nitrogen fertilizer due to the increased demand for natural gas. 

Commenters stated that natural gas is the largest 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. 

Commenters stated the rule will create the need for new transmission lines, natural gas pipelines 

and electrical generation facilities which will be constructed on farm and ranch land. 

Commenters stated that, as such, farmers and ranchers will either lose property and/or the ability 

to fully utilize portions of their property.

Comment 18: Commenters expressed concern that the EPA has not accounted for impacts at 

efficient, low-emitting generators of combined heat and power. 
431

Response 18: The EPA disagrees with the commenters’ 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 Regulatory Impact Analysis of the final CPP.

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

Commenters stated Verso's gas turbines at two facilities in Maine generate power for the 

electrical grid when it is most needed. Commenters stated that, with limited natural gas supplies 

in the region, their costs can skyrocket in winter, surpassing revenues. Commenters stated that 

natural gas costs in Maine, particularly peak prices, can be expected to escalate further as a result 

of the Carbon Pollution 111(d) Rule. Commenters 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. Commenters stated this would rob the northeastern grid of reliable, efficient, 

low-emitting generators of combined heat and power, just the sort of CHP units EPA is touting 

as solutions to carbon pollution. 

Comment 19: Commenters expressed concern that requiring 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 IPM model includes a 

natural gas supply module that includes demand and supply of natural gas nationwide. In 

response to additional analysis and many comments, we have modified the proposal and RIA. 

States may consider local circumstances as they develop their 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 preamble of the CPP and Chapter 3 of the GHG Mitigation Measures 

TSD for the CPP Final Rule supporting the final CPP, and the Regulatory Impact Assessment of 

the final CPP.

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

Commenters stated that TVA is exposed to higher gas prices when demand exceeds expectations, 

which raises electricity prices, such as was the case during the Polar Vortex experienced in the 

winter of 2013-14 when spot prices spiked to historic levels. Commenters recommended the 

EPA include consideration of secondary uses and localized price impacts in its analysis of 

natural gas fuel supply. Commenters noted an EIA report that indicates natural gas fuel prices 

have a history of volatile pricing for local distribution company customers in Tennessee and 

stated that this is an area where EPA should devote additional consideration in its analysis. 
432

Comment 20: Commenters 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 commenters. The EPA disagrees with the commenters, 

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 the 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:

Commenters stated the natural consequence of the Proposed Rule is that much of the 

infrastructure for coal-fired generation will cease to exist as the country switches to natural gas 

for its base load energy needs. Commenters stated that, if the supply of natural gas is interrupted 

or the cost of gas rises beyond predications, the consequences may be profound. Commenters

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: Commenters 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 Measures 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:

Commenters 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. 

Commenters stated the EPA should sharply reduce the Clean Power Plan's reliance on natural 

gas. Commenters stated there is little if any room for natural gas in a proposal that replaces 

fossil-fuel generation incrementally by using the emission-reduction strategies that come at 

lowest cost to consumers.

Comment 22: Commenters 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 of 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 factor 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 

another 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 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. 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 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. 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 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 

the 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 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.

• 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 higher than the value in 2012. It is uncertain whether this is due to 

the assumed impact of planned coal unit retirements and NGCCs taking up the 

slack or another reason. 

• Page 3-26: At the top of the page it is stated: This is because only 29 state goals 

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. This second 

sentence is confusing and should be clarified.

Comment 23: Commenters 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 

further impact cost and reliability factors?

• Why did the EPA not analyze how Dodd-frank has and will impact capacity 

elasticity?

• Why did the EPA not analyze with system peak-day usage rates.

• Why didn't the EPA consider how extreme events and seasonal changes 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 changes at Henry Hub from 1981-2012 as 18.5%. See GHG TSD 3-

26. The EPA projection less than historic changes. Why isn't the 10% in addition 

to the 18.5%?

• The EPA provides estimated increases in natural gas prices in national average 

delivered; why didn't the EPA provide state & 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 sector. 

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 concept 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 comments 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 sections V.A and V.B of the preamble for this final rule.

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

Commenters stated the EPA should not expand the definition of the NGCC fleet to include cofiring or new NGCC units in states' baselines.

Commenters observed that gas co-firing, as a unit-specific control measure, more properly 

belongs within building block 1 as a strategy that can be accomplished by modifications at an 

existing fossil steam unit.

Commenters concluded that co-firing should remain a tool available to states to help them 

achieve emission reduction goals, but should not be part of BSER. Also, commenters said, 

simultaneous inclusion of co-firing with re-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 recover costs to operate and maintain the units. For this reason, the commenters 

believe coal-fired CHP facilities must be excluded from the re-dispatch evaluation under BB2.

Commenters referred to the NODA and objected to any use of natural gas co-firing as a 

supplement to the re-dispatch assumption. 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 individual 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 EPA 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 

analyze 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 months 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 EPA'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 including 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. 

Commenters 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 not 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 implement confidently in a state plan, or from which a state may base an 

alternative approach to reducing CO2 emissions.

Commenters supported allowing "Other Gas" units to count toward the target implied by BB2, 

welcoming the flexibility, but stressed that Other Gas units should not be added into the cohort 
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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 setting 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 NGCC, 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 new 

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 generating 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 evidence 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 CO2 avoided is "relatively 

expensive," but it is not "exorbitant," especially when the full 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 believed that the adoption of a minimum value for Block 2 that accounts for cofiring 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 that 

the EPA could revise BSER to include a 20 percent (%) co-firing rate, which could, in turn, be 

utilized to calculate more stringent Block 1 or Block 2 values for states. Commenters stated that 

Block 2 should be revised such that a 12% shift from coal-fired 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. Barring the EPA's adoption of such an 

approach, commenters said that natural 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. 
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Rather, commenters stated, all of the Building Blocks together synthesize the assumptions that 

lead to each state's goal. While not all steam EGUs will necessarily co-fire natural gas, 

commenters concluded that co-firing should be 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 stringent by assuming 

that EGUs can implement some amount of co-firing or rely on construction of new NGCC 

capacity to reduce emissions from coal-fired EGUs. Commenters stated that this approach is 

problematic for at least three reasons. Commenters stated that designating co-firing or new 

NGCC construction as BSER would effectively 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 emissions 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 existing 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 cofiring to be as high as $150 per metric ton of CO2. Commenters stated that the cost of reducing 

emissions through redispatch to new NGCC units, meanwhile, would be as high as $81 per 

metric ton, and therefore, it would be unreasonable to designate these exorbitantly costly 

alternatives as the "best system of emission reduction (considering the cost of such reduction) 

that has been adequately demonstrated for designated facilities.

Commenters stated that in its Notice of Data Availability, EPA requested comment 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 deploying 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 

wildlife, 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 1: Commenters opposed the two new proposed approaches for calculating building 

block 2 of imposing a minimum level of natural gas dispatch and calculating Building Block 2 

on a regional basis.

Response 1: The EPA has not adopted the minimum floor approach for the final rule and 

believes the approach to developing state goals is not arbitrary (See Preamble Section V).

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

Commenters said that it is inconsistent with the 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 diversity and cost 

effectiveness. Commenters 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. Commenters 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. Commenters concluded that the calculation of Building 

Block 2 should support this 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 Proposed 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 capacity 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 CO2 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 this 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 Regulatory Impact Assessment of the final 

CPP.

Commenters stated, although the building blocks in the Proposed Rule incorporate an increase in 

dispatch from natural-gas fired units, but do not 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 retiring 

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 mandatory 
440

capacity markets will greatly impede such new natural gas generation 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 markets 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 reliability in an economically efficient way, and thus should be substantially 

modified, or eliminated - not expanded in scope or introduced to new regions. Commenters said 

a major open FERC docket is currently considering the core design and purpose of RTO capacity 

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 that RTO capacity markets can 

take on the new function of advancing the Proposed Rule's objectives. 

Commenters said that EPA needs to withdraw the 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-Operated 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 ineffective 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 percent 
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of the $72 billion in revenue committed through the PJM capacity markets is for 

new resources, demand response, or energy efficiency. 

• 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 specific 

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 infrastructure 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-mustrun agreements to coal plants to remain 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 owners 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 stated, 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 said, contrary to this key 

necessity, however, RTO markets include some design elements that impede long-term 

investments and long-term bilateral contracts." 

C. Recent Mandatory Capacity Market Developments Create Direct Impediments to New 

Resources.

Commenters stated, not only are mandatory capacity markets generally ineffective in new 

resource development, but the markets can actually serve as barriers to new capacity 

development. Commenters said, these markets all have some type of MOPR or "buyer-side 

mitigation" (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 cooperative utilities negotiated specific and express exemptions from these MOPRs in PJM 
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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 FERC 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 within RTOs that had become frustrated with the lack of new, more efficient generation 

in their states given the billions of dollars spent by their utility customers on capacity payments. 

Commenters said, these states had sought to take control of their energy 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 contracts. 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 open 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 

service 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 therefore 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 jurisdiction 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 decisions.

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 with 
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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 proper 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 develop 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 response 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 because 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 impeded 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 CO2 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 demand 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, regulators, 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 implement 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 Section 111.
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Response 3: EPA thanks the commenters. EPA has determined that new NGCC is not BSER 

and is not allowing shifting generation to new NGCC units to be used as a measure for adjusting 

CO2 emission rates for affected EGUs in rate-based state plans. See Preamble Section V for 

BSER issues and Section VIII for State Plans.

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

Commenters stated that the proposed BSER for 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 of 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 new 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 standards 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, which 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 modifications 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 

facilities. 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 approach 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 which are organized by 

topics (comments) below. Responses are provided for these topics.

Comment 1: Some commenters supported using a regional approach to building block 2 to 

account for interstate re-dispatch opportunities.

Response 1: The EPA decided to not include the state level 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 the EPA's proposed methodology to calculate re-dispatched generation 

assumes that each state must have the existing NGCC capacity to increase output in the amount 

needed to reduce emissions from existing coal units in the same state. Commenters 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. Commenters said that calculating re-dispatch on a regional basis would 

increase the amount of re-dispatched generation by 104 TWh (or 24%). 

Commenters said that section 111(d) rules permit the Agency to recommend the contours of an 

allowance system that could be adopted by multiple states. According to commenters, many 

states have asked for such guidance.

Commenters stated EPA should recognize that for some states, a regional budgeting approach 

will make more sense than using RECs for compliance. Therefore, the commenters believed

states should be allowed to enter into multi-state agreements that allow for emissions budgeting 

so long as the emission reductions are verifiable and not being claimed by another entity or 

state.

Commenters supported a regional approach because it would more accurately calculate the 

availability of underutilized NGCC capacity nationwide and more fairly assign emission 

reduction obligations across the states. Commenters stated that existing power plants are 

components of a complex and interconnected electricity grid that stretches across state lines. 

Commenters 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. Commenters provided several examples of this 

interconnectedness, including ISO-NE, New England's regional transmission organization, which 

includes 300 generating plants and 8,000 miles of transmission lines. Within each ISO system, 

commenters 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 amount of existing NGCC capacity that is available for re-dispatch under Block 2. 
446

Commenters 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 Independent System 

Operator ("MISO") are considered as a group. According to commenters, 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 emission reduction obligations 

between "low impact" states, such as North Dakota and Indiana, and "high impact" states, such 

as South Dakota, Michigan and Minnesota. Commenters stated that this approach would also 

facilitate regional cooperation by limiting the difference between rule's impact on states that are 

"winners" and those that face a more challenging regulatory burden. 

Commenters noted that applying the same concept to five of the states served by the Western 

Electric Coordinating Council (WECC) results in an additional 11 million MWh of reduced coal 

generation. Commenters added that it also 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. 

Commenters said that the preceding examples illustrate a more simplified calculation process 

(i.e., assume that all of the units in the states are part of MISO or WECC, which is almost, but 

not completely correct.) Commenters recognized that it may be more appropriate to organize and 

evaluate generating capacity on a sub-regional basis. Commenters recommended that the EPA 

evaluate 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, commenters 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. 

Commenters similarly noted that a regional methodology is a way of making the targets 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). Commenters added that a regional 

approach would also more consistently align with ongoing grid operations and electricity 

dispatch decisions. Commenters concluded that regionalization of the gas re-dispatch targets 

would be more consistent with how the EPA calculates the renewable energy building block 

targets. Commenters 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 can be easily regionalized in a similar manner for consistency.

Commenters 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. Commenters concluded that the impact of meeting New 

Hampshire's need should be evaluated on a regional level. 

Commenters acknowledged while that regional plans will be complex and time-consuming to 

develop, they will be needed to provide the lowest cost solutions. Commenters appreciated the 

EPA's recognition of the disparate impacts between states that have invested in NGCC and those 
447

that have not. Because most generation is operated in order to meet regional needs, commenters

said that it makes sense to apply building block 2 on a regional basis as well. 

Commenters recommended that the EPA calculate the emission reduction potential for 

redispatch on a regional, rather than state-by-state, basis. Commenters stated that, while the 

EPA's proposal does not mandate that states achieve emission reductions through any particular 

building blocks, or for that matter, via any 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 building block. Commenters 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 

commenters, nowhere is this "fix" more appropriate than on tribal nation lands, which function 

as "islands" of generation under the EPA's proposal. Commenters noted that, of the three nations 

affected by the supplemental proposal, the Navajo 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. Commenters said that the EPA's 

approach calculates no emission reductions under Block 2 for any of these three nations. Far 

from "islands," commenters stated, the plants that are hosted on these lands export the vast 

majority of their electricity to ratepayers in other jurisdictions and could easily be expected to 

reduce their dispatch in accord with the available NGCC capacity in nearby states. 

Commenters calculated the impact on the emission 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 from 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 approach, while achieving greater reductions than the 
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EPA's proposal, would also balance the reductions that APS will need to make between assets in 

states and on tribal nation lands.

Commenters said that the appropriate emission rate for tribal nation lands, applying the EPA's 

Blocks 1 and 2 but employing factually documented 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-fired EGUs, is 1,292 lbs CO2/MWh for 

units located on Navajo lands and 1,336 lbs CO2/MWh for the unit located on Ute lands. 

Commenters said that this rate should be further adjusted to reflect the EPA's Building Blocks 3 

and 4, as described elsewhere. According to commenters, 1,292 lbs CO2/MWh may seem to be a 

large difference from the EPA's proposed emission rate of 1,993 lbs CO2/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 CO2/MWh. Commenters said that the Nation 

would be able to meet its target with modest additional emission reductions through coal 

curtailment or RE development.

Commenters 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. Commenters stated that a regional approach would enable tribal 

areas to take advantage of the flexibility to switch to cleaner generation resources and reap the 

benefits of doing so.

Comment 3: Commenters 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 the 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 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 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 state line simply due to 
449

the target for the first state being lower than the target for the second. For instance, commenters

said, in the IPM run illustrating the regional 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. Commenters stated that 

coal-fired generating 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 IOUs, 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.

Commenters noted that the service territories of the Entergy operating companies (utilities) have 

a higher percentage of existing NGCC capacity (relative to load) than most other regions. Under 

the Proposed Rule, commenters said that Entergy's utility states (Arkansas, Louisiana, 

Mississippi, and Texas) are required to reduce emissions significantly even though its utility 

fossil average emissions/MWh already is below the standard for new NGCCs. According to 

commenters, this approach also ignores the fact that Entergy is in an interstate power pool 

balancing authority, MISO, whose MISO load represents approximately 24% of MISO TWh, but 

they include approximately 45% of the NGCC redispatch potential within MISO. Commenters

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: Commenters 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:

Commenters 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. Commenters believed 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, operates on a regional or multi-state basis. Commenters

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 Administration and PacifiCorp), and in RTO centralized markets that cover 

much of the rest of the country. [Commenters noted that exceptions include California, New 

York and Texas ISOs which operate within single states.] Commenters 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

Commenters indicated that this means that state and federal regulators, and both verticallyintegrated 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. Commenters 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. 

Commenters noted that while the EPA gives a 2 year delay in filing a state plan if a state is 

participating in a multi-state plan, it does not currently allow for a delay in meeting the initial 

2020 emissions targets. Commenters added that the NODA requests comments on a potential 

phase-in of building block 2, which presumably would give more time for regional approaches to 

be considered.

Commenters 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. 

Commenters 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 state, 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 

state 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 what 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 increased to reflect less dependence on neighboring systems.

Commenters 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 utilities 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 commenters, even though state regulators in regulated states may not 

have the authority to directly dictate dispatch and/or may not feel comfortable doing so, they 

likely could provide direction on how many hours plants could operate in a given period similar 
451

to what is done with respect to other pollutants. Commenters 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 environmental dispatch. Commenters 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. Commenters added that another option could be for the state to 

set a mass-based limit and require its utilities to meet that requirement through the plants it 

operates - perhaps by closing coal plants or limiting the hours per year coal plants can operate. 

Commenters stated that there are significant equity issues in these determinations if there are 

plants with multiple owners within the state: How does a state decide which plants must close or 

limit operations to meet the state requirements? Commenters 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.

Commenters 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. Commenters added that to this extent, traditional 

vertically-integrated utilities operating in multiple 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 clearer path to implementation of the CPP than do the RTOs and ISOs.

Comment 5: Commenters argued that a regional system is the only way to completely eliminate 

potentially serious inconsistencies in the operations of power plants in different states.

Response 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:

Commenters stated that the ideal approach would be a regional, market-based system that is 

harmonized across all states sharing a regional power market. Commenters added that 

coordination across states is most easily achieved if states convert to a mass-based standard and 

implement a flexible, market-based approach to compliance. Under an emissions trading 

program, commenters said, emissions reductions could be traded freely across states. 

Alternatively, commenters said, if states chose to achieve compliance via the introduction of a 

carbon tax or fee, a uniform regional emissions tax or fee would result in cost-effective dispatch.

Commenters discussed rate-based and mass-based standards in a regional context in which the 

dispatch of electricity production across a multi-state region is centrally coordinated. 

Commenters 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 their 
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capacity is needed. Commenters said that the introduction of an emissions regulation alters a 

fossil-fueled power plant's variable operating costs and can thereby affect the merit-order of 

dispatch. Commenters 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.) Commenters noted 

that although the analysis is calibrated using data from a specific region and year (the western 

interconnect in 2007), the main results apply with generality.

Commenters stated that the following analysis assumes that all states use a market-based 

approach to meet their compliance obligation. Under a mass-based system, commenters said this 

means that producers within the state must purchase allowances to offset their emissions while 

under a rate-based system, it means that plants with emissions rates below the standard can sell 

compliance credits to the plants with emissions rates that exceed the standard.

Commenters discussed how the simulated power system dispatch is affected under a regionally 

coordinated rate-based or mass-based standard. Under the mass-based regime, commenters 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, commenters continued, the analysis 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, commenters 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, commenters said, the 

dispatch model is used to identify the permit price that clears the market and therefore brings the 

region into compliance.

Commenters described Figure 1 (titled: "Changes in the merit order of electricity generating 

units with no regulation, a region rate-based regime, and a regional mass-based regime") to 

illustrate how these policies affect plants' operating costs. Commenters said that the figure serves

to illustrate two general results. First, commenters 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. Commenters said 

that one should not infer from this that social costs are higher under the mass-based standard. 

According to commenters, the private variable costs indicated in the graph are comprised of 

variable input costs (e.g., fuel) and compliance costs, whereas social variable costs are comprised 

of variable input costs and the external damages from emissions.

Commenters said that lower electricity prices under the rate-based standard reflect the fact that a 

rate-based standard confers an implicit subsidy to plants with emissions rates below the standard; 

hence, to the extent that demand for electricity is price-responsive, there will be a higher level of 

electricity consumption under the rate-based approach compared to the mass-based approach. If 

consumer prices under the rate-based standard fail to reflect the full social cost of electricity 

production, commenters said that the level of electricity production, and the overall costs of 

achieving any mandated level of reductions, would be higher under the rate-based standard. This 
453

means, commenters 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.

Commenters 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, commenters said, some coal plants are replaced with low-cost 

gas plants at the bottom of the merit order. Thus, commenters stated, the main difference 

between the regionally coordinated mass-based target and regionally coordinated rate-based 

target lies in the level (versus dispatch order) of production.

Commenters also considered a scenario where the stringency of the standard varies across states 

in a regional power system. Commenters continued to assume that the form of the standard does 

not vary and all states convert to a mass-based 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., commenters 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, commenters said that it is important to keep in mind that electricity will nevertheless be 

traded among states within a regional power system.

Commenters described Figure 2 (titled: "Changes in the merit order of electricity generating 

units with a regional mass-based regime and individual state-level mass-based regimes") to 

illustrate how variation in stringency across states affects the merit-order in this case. 

Commenters said that Figure 2 illustrates how a lack of coordination or linkage between states 

with different mass-based standards significantly alters the order of dispatch. For example, 

commenters said, technically identical coal plants that sit side-by-side in the reference merit 

order (the black line) are impacted very differently under the uncoordinated policy if they are 

located in states with very different emissions standards. Plants in states with relatively 

aggressive standards see operating costs increase relative to the reference case, commenters said, 

whereas coal plants in states with much less stringent standards move to the front of the dispatch 

order.

Commenters 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 operations. Commenters stated that 

this underscores the importance of allowing for trades in emissions across states in the same 

electricity market.

Commenters also considered a scenario in which some states in a region adopt rate-based 

standards while other states elect to convert to a mass-based standard, i.e., a "hybrid" regime. 

Commenters said that Figure 3 (titled: "Changes in the merit order of electricity generating 

units"), which illustrates one such hypothetical 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

Commenters 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, 

commenters said, this is because some compliance is achieved in the capped states by increasing 

imports of electricity from the rate-based states. Under a hybrid scenario, commenters said we 

should expect to see a re-allocation of production towards the rate-based states because the ratebased regulation subsidizes gas production. Commenters stated that this hybrid design effectively 

makes imports of gas from the rate-based states to the mass-based states even more attractive

than they would otherwise be. Under such conditions, commenters noted, increasing imports 

from rate-based states becomes a low-cost option for complying with the mass-based standard 

imposed by the coastal region.

Also, according to commenters, the states may face strong incentives to choose different 

compliance approaches (i.e., rate- versus mass-based). Setting aside concerns about the 

administrative and process costs of coordinating compliance across states, commenters said that 

regional coordination is not the most likely outcome given incompatibilities in economic 

incentives. Notably, commenters said, it can be in a state's interest to choose the opposite 

regulatory mechanism as their neighbors, and this is true regardless of whether carbon 

allowances are traded between the states. According to commenters, Figure 3 illustrates this 

point quite clearly. Commenters noted that, conditional on the coastal region adopting a massbased standard, the inland states will want to adopt a rate-based standard in order to enhance 

their opportunity to increase exports to the mass-based states. Commenters 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 other words, commenters said, by choosing to 

implement the policy in a way that differs from the coastal states in the region, inland states can 

take advantage of new opportunities to import or export power that could lower their own 

individual compliance costs.

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 final rule builds on the 

proposal and includes provisions to support trading mechanisms, both in terms of the BSER and 

in terms of planning and implementation. See the 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 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 exclusive jurisdiction of FERC 
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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 the 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 mixes.

Commenters 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. 

Commenters added that a regional approach would add another subjective element to the goal 

computation. Commenters stated that the EPA has not provided any details on how regions 

would be determined or how shares would be allocated among the states within a region. If a 

regional approach is used to determine NGCC capacity availability, commenters said, a regional 

approach must also be used to determine how much coal-based generation is available to be 

displaced. Finally, commenters noted that the electric system is planned and built as an organized 

and coordinated structure, largely independent of state boundaries.

Commenters 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. Commenters believed 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. 

Commenters said that it is not reasonable to consider regional scenarios when establishing goals 

for state plans. Commenters believed that changing economic dispatch to environmental dispatch 

of specific EGUs, which is integral to the EPA's unique attempt to move outside the fence to 

effect CO2 reductions, is an extreme and unwise move away from the existing dispatch scenario. 

Commenters stated that such a massive change to the grid reliability/economic dispatch model is 

difficult to envision on an individual state basis, and even more difficult to envision on a regional 

level. Commenters agreed that this proposal would 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 this proposal.

Commenters explained that System Operators generally dispatch electricity regionally on a leastcost basis, so states whose transmission facilities are under the operational control of an RTO or 

ISO cannot unilaterally impose redispatch to natural gas. Commenters said that the only manner 

in which an individual state could ensure that its coal-fired EGUs are not dispatched is to bid 

generation from coal into the RTO or ISO at a price high enough to ensure that it would be 

dispatched after natural gas. However, commenters 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. 

Commenters 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

Commenters said that the only way in which states 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. Commenters 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. Commenters

described an example of such states that would have to enter into multiple state plans, which the 

commenters thought was unrealistic.

Commenters said that the EPA's approach ignores the ownership of NGCC units, and it assumes 

that the utilities that own fossil steam generation will be able to purchase energy from NGCC 

merchant generators. Applying Building Block 2 on a regional basis would exacerbate this 

problem commenters added. Commenters concluded that a regional approach would presume 

that a state reliant on another state by the EPA's calculations could actually procure energy from 

generators within that other state as one possible compliance option. In bilateral wholesale 

markets, such as those used in Arizona and other surrounding states, commenters said that this 

may not be possible even if the necessary infrastructure were in place. 

Commenters said that resource selections are determined, in part, on a utility's customer load. 

According to commenters, new resources are added only if there is sufficient load to justify the 

need for additional resources or in response to a state's energy policies. Commenters stated that 

the proposed regional approach reduces states' flexibility to accomplish emission reductions and 

could force customers to pay for additional resources simply to accomplish a shift to natural gas 

resources. Commenters added that a regional approach may also serve to discourage increased 

utilization of renewable energy and end-use energy efficiency programs. Commenters’

experience in developing 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 for states and 

utilities as they implement the final rule commenters concluded.

According to commenters, 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 or how 

shares would be allocated among the states within a region. In the BSER formulation, 

commenters 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. 

Commenters opposed using a regional approach to the application of Building Block 2. 

Commenters stated that there are already serious 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 commenters, a prime example is the failure of the EPA' goal calculation to 

recognize the impact 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. Commenters

said that applying Building Block 2 on a regional basis in the EPA's goal calculation 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

Commenters stated that the existing 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 commenters, 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, commenters said that the NERC concludes that "[p]ipeline constraints and growing 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 commenters, 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 natural 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 associated 

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 transmission infrastructure to maintain 

acceptable margins of reliability assurance. 

Commenters 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 system 

reliability and resource adequacy. That study has not been finalized; but commenters 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, commenters 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. Commenters 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 circumstances after sufficient analysis of reliability and resource adequacy has been 

completed.

Commenters 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 made a 

determination that justifies the imposition of a mandate for natural gas use as a component of 

BSER. Commenters said that although the mandate would ostensibly be used only to determine 

the target for Building Block 2, for practical purposes, the actual implementation of state goals 

would have to mirror the targets in the other Building Blocks to a very large degree. Commenters

said that 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 - 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.
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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 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:

Commenters stated that the EPA should not redefine BB2 by calculating it on a regional basis (or 

modify the way it calculates state goals by imposing a minimum level of re-dispatch). 

Commenters believed that to do so ignores the fact that every state and region has unique 

generation portfolios that reflect specific energy demand requirements and resource availability. 

Commenters similarly did not support the regional 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. Commenters 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 commenters’ state (Iowa) and Iowa's utilities have no input or control. 

Commenters 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 varying 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 potential 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 proposed in 

the NODA will ultimately do nothing to alleviate the harms that the Rule Proposal and BSER 

Block 2 will inflict on these states. Commenters referred to the NODA and stated that, EPA's 

proposed revisions to Block 2 stringency are largely illegal, provide little relief to coalgenerating units, and may actually increase stringency on coal electricity generators. 

Commenters stated that, since the EPA has not provided specific proposals or explanations 

regarding the use of natural gas "more comprehensively or holistically," they are unable to 

comment further.
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Commenters stated the EPA must consider state- and source-specific factors in establishing the 

Building Block Two targets. Commenters objected to the regional approach suggested in the 

NODA to the extent it would assume NGCC capacity can be made available in a state where 

such capacity currently does not exist.

Commenters stated the other Block 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. Commenters stated that requiring a minimum 

level 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. Commenters added that the regional approach may not qualify as the BSER, 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. Commenters stated that such a determination is 

not supportable, since individual states have limited 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, commenters 

noted that some plants must be run to maintain load; transmission bottlenecks can prevent 

perfectly efficient distribution, and it cannot be assumed that electricity generated from 

alternative sources can be transmitted to all consumers. Commenters stated, in States such as 

Texas where electricity transmission is managed by multiple ISOs, it may be impossible to move 

electricity across ISOs from one part of the State to another; the availability of wind and solar 

generation will depend on local conditions that 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 

connection 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 

minimum 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 final rule preamble of the CPP.

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

Commenters stated the Navajo Nation agrees with 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, commenters noted that the Navajo Nation economy is highly dependent on the use of 

Navajo coal, a tribal trust asset.

Commenters said that under the Proposed Rule, all 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; 
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therefore, the EPA does not need to require a regional application of any of the building blocks. 

Commenters added that the proposed rule allows jurisdictions to establish their own regional 

trading programs which can help to even out differences between states.

Commenters stated 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 

commenters stated that this concept presents numerous achievability 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. 

Commenters opposed the inclusion of coal 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 commenters 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. Commenters 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 from coal firing natural gas and such actions simply 

cannot be rationalized or cost justified. 

Comment 9: Through RGGI, commenters 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 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:

The commenters stated that RGGI already provide a framework for participant states to 

collectively work together to reduce CO2 emissions, and it has generated revenues from the sale 

of CO2 allowances that are used to fund EE and RE programs. For example, the commenters

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 CO2 emissions. (Regional 

Investments of RGGI CO2 Allowance Proceeds, 2012 (2014), available at http://www. 

rggi.org/docs/Documents/20 12 .Investment-Report.pdf).

Commenters 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 CO2, but Congress 

has not provided the authority to the EPA to tax CO2 emissions, nor can the EPA force states to 

tax CO2 emissions. Commenters stated that the EPA should not use the RGGI approach as an 
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example program since the RGGI approach relies on voluntary carbon taxes that cannot be 

legally forced upon a state.

Commenters 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."

Commenters stated that, although the EPA has said that they 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. 

Commenters stated this looks like what one of the regions, New England, has already been going 

through.

To implement a regional approach, commenters stated FERC recognized the need to ensure that 

as it moves forward, that some of the concerns seen in New England with the pipeline constraints 

and the rapid conversion to gas and the very tight reliability system and sometimes very high 

cost for electricity aren't exported to other regions of the country, and overcoming that could be a 

challenge. Commenters concluded that the national experts charged with reliability, FERC, 

recognized the RGGI program has experienced growing pains as it was implemented. 

Commenters did not believe it should be touted as a model program for the entire country when 

FERC has described reliability and cost concerns.

Comment 10: Commenters noted that the proposal to use a 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 emissions 

programs that permit use of nuclear as an offset to fossil fuel generation.

Response 10: The EPA decided to not include this provision in the final CPP, as detailed in 

Section V.A of the final rule preamble of the CPP.

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

Commenters stated that such programs would both limit the extent of CO2 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. 

Commenters stated that replacement of state renewable portfolio standards with so-called "clean" 

energy standards that include nuclear would have a similar effect.
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Commenters described previous efforts to create regional emissions-reduction programs, but 

none of them reached fruition. Commenters noted that 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 utilize nuclear as a primary compliance mechanism for 

achieving state goals. In so doing, commenters said, states may be able to achieve the goals, not 

by reducing CO2 emissions significantly, but by "diluting" their emissions rate with additional 

nuclear capacity. According to commenters, 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 accurate calculation 

of the costs and environmental impacts of nuclear could create a biased yardstick by which to 

evaluate state implementation plans.

Commenters recognized that regional approaches may be advantageous, especially considering 

that all but five states participate in RTOs with 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, commenters said that the adoption of regional 

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, commenters added, 

leaving them unprepared to make deeper reductions in emissions after 2030. Commenters

encouraged the EPA to set forth guidelines for how states may structure regional greenhouse gas 

programs to reflect best practices and to optimize emissions reductions and cost-effectiveness. 

Commenters stressed that programs that adopt emissions offsets should be strictly limited, and 

those that include nuclear as an offset option should be disqualified.

Commenters 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 reliance on nuclear in states' implementation plans. Without 

such guidance, commenters 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. Commenters 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 programs. According to 

commenters, that would require states to set higher offset limits, in order to credit resources that 

are effective at reducing emissions or converting or removing greenhouse gases from the 

atmosphere. Doing so, commenters 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' electricity generation, commenters noted that just 6% of nuclear would 

account for nearly all of the 3.3% of CO2 emissions from fossil fuel generation sources - without, 

however, removing a single pound of CO2 from the atmosphere. Even in states with lower 

proportions of nuclear capacity, commenters added, the effect would be the same, just to a lesser 

degree. Commenters stated that the EPA may not be able to directly regulate regional emissions 

compacts under the CPP, but it can define the way in which measures states include in their CAA 

section 111(d) implementation plans are credited toward compliance. In the final rule, 
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commenters concluded, the EPA should establish guidelines defining what aspects of regional 

emissions programs will count toward compliance.

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:

Commenters said that the U.S. Court of Appeals for the DC Circuit recently unanimously upheld 

FERC Order 1000, which updated and enhanced requirements for utilities to participate in 

regional transmission 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). Commenters said that it is 

unclear whether the EPA assessed the impacts 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. Commenters added that since FERC jurisdiction is limited in Texas, not all Texas 

utilities are 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: Commenters 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:

Commenters said that having pre-defined regions would reduce flexibility and limit the costeffective options available to states. In order to address the issues raised by stakeholders with 

crediting in-state generation purchased by other states, commenters said that the EPA should 

allow states with renewable resources to net their renewable generation sold out-of-state against 

their targets. Commenters said that this approach will allow compliance while also avoiding 

double-counting.
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Comment 13: Commenters 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 commenters. 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 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 the ability to shift emission rate achievement between performance periods. See sections 

V.A, V.D, VIII.A, VIII.C and VIII.G of the final 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 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. Commenters stated that this value is about 1.75 lb/kWh and 

recommended this in place of the proposed reassignment of NGCC capacity to states currently 

without NGCC.

Comment 14: Commenters stated the proposed rule places Florida in a southeast region with 

Kentucky, North Carolina, South Carolina, Tennessee, Mississippi, Alabama, and Georgia.

Response 14: The EPA decided to not include this provision in the final CPP, as detailed in 

Section V.A of the final rule preamble of the CPP.

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

Commenters stated Florida's import transmission capability is limited to approximately 3,800 

MW, or 6.6% of total capacity. Commenters concluded that Florida's geographical location and 

corresponding energy import limitations should minimize reliance on regional 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 approach to BB2 would work.
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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 determinations, 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 the 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 

it in the final rule. Commenters added that if the EPA pursues this approach, then it must 

withdraw the Proposed Rule and issue a new proposed rule that details how the regional 

approach works and the specific requirements that 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.

Commenters stated that a critical problem with the CPP is that responsibility for meeting and 

enforcing targets appears to be left only with the states, even though regional approaches are 

encouraged. Commenters indicated that the EPA suggests that regional implementation is viable, 

referencing 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. Commenters

identified two issues with the California program: (1) they assign carbon emissions from imports 

to the state to the first seller in the state, which would not work in a regional plan, and (2) the 

program has multi-sector coverage as opposed to the EPA plan which covers electric generating 

units only. Commenters also noted that RGGI uses a mass-based emissions target that is 

regionally based and does not require individual states to meet state emission targets as long as 

they have bought sufficient credits from someone else in the region. Commenters 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 Floor

This section discusses issues related to setting a floor for the shift of generation to NCCU units 

as part of Building Block 2. 

Commenters have raised a number of issues related to this subsection which are organized by 

topics (comments) below. Responses are provided for these topics.
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Comment 1: Commenters expressed support 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 shift 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. Commenters urged EPA to consider ramp 

rates up to and including a continuation of a 5% per year shift rate, the 1-year historic average. 

Commenters 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 assume 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 flexibility 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 natural gas. Commenters found that the building 

block and flexible compliance concepts proposed in the CPP are generally constructive and 

suggested the EPA continue to ensure the intended flexibility is carried through in the final rule.

Comment 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.
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Response 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 public 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 alternatives 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 

accurately 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 potential 

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 the 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 power 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 another 

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 commenters concluded it does 

not seem reasonable to change only building block 2 just because application of that building 

block has varying impacts on states without taking a more holistic look at how all the building 

blocks have varying impacts on states.

Commenters stated the EPA should not modify the way it calculates state goals by imposing a 

minimum level of redispatch or redefine BB2 by 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 natural 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 targets 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 

reducing 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 where 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 natural gas infrastructure necessary 

to serve those generators, and it is not clear that the assets would be in place by 2020 or even 

2030 in some cases. Commenters stated creating a 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 less, 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 reflect 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 limited thermal capacity 

that presently exists in the region (this would be the only operationally effective alternative to 

trying to try on building blocks three and four to maintain grid reliability). The commenters said 

requiring the development of a very large reserve 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 necessary if the proposed baseline and emission-rates proposed for Pacific Northwest states 

were modified to accommodate the region's dependence on hydropower generation. The 
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commenters said that review and decisions related to generation resource planning infrastructure 

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 impact. 

The commenters declared that its analysis indicates that the proposed 12% floor would only 

apply to nine states and add a small amount of additional NGCC generation - about 30,000 GWh 

nationwide. The commenters suggested that, in lieu of a floor, EPA consider deriving new state 

NGCC capacity targets using the national compound 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 pipelines, 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 understanding 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 existing 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 new NGCC capacity has been closer to load in Utah, a reflection of the fact that 

existing transmission is not the dominant economic determinant. 

Commenters stated they have similar doubts about co-firing, as it may increase ratepayer costs 

without materially altering the scale of the task 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 coal fleet, and to 

the resulting increase in electricity rates, which will directly affect the state's economic base of 

industrial users, who accounted for 58.98% of Wyoming electricity sales in 2012. 

According to commenters, such a mandate restricts the ability 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 could only recognize new NGCC in 
470

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 its 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 'count' towards satisfying section 111(d) 

compliance targets. The commenters said EPA should leave it to the discretion of the state 

whether they wish to opt-in new NGCC in target setting for EPA's proposed 70% capacity factor 

target for existing NGCC. The commenters added that EPA should eliminate the BB2 target 

component for Minnesota, giving deference to the Minnesota established Integrated Resource 

Planning process, which is already giving consideration to fuel diversity, cost and environmental 

profile, including CO2 environmental externalities. The commenters also supported EPA's 

clarified intention to allow RE and customer energy efficiency to receive treatment in the 

denominator of emission rate compliance determinations.

Commenters stated that RTOs may be 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 construction NGCC units. The commenters stated that 

EPA should simply acknowledge that those resources already in approved state integrated 

resource plans or under permitting and/or physical construction pre-date the timing of CPP 

applicability, represent a small population of 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. 

Commenters 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 integrated 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 

deployed that is able to replace the services of existing NGCC, considering that today's IRP 
471

deployments and wholesale markets show optimized performance at existing NGCC utilization 

levels.

Commenters said that the aspects of the NODA for which comment were sought may add further 

complication to understanding the proposed rule and do not offer additional insight as to how 

EPA might ease the interim goals or glide path. The commenters said that it appears any easing 

of the interim goals will be offset with stricter 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 may 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 to 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 emissions 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-firing 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 to 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 equity, 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 the EPA should not adopt the 

suggestions advanced in the NODA to expand the definition of the NGCC fleet to include cofiring or new NGCC units in states' baselines (79 FR 64549-50).

Comment 3: Commenters agreed with NODA approach for minimum floor of 12% on a 

regional basis.

Response 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:

Commenters 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 from 
472

those states that have not, such as Kentucky. The commenters believed 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 Texas, which has significant under-utilized NGCC capacity. 

The commenters agreed with the approach in the NODA, establishing a minimum floor value for 

each state to achieve through Block 2 - regardless of a state's existing NGCC capacity - and 

reducing the burden by an equivalent amount for those states with higher amounts of NGCC 

capacity. The commenters believed that the minimum value of 12% suggested by EPA in the 

NODA appears reasonable and should be established on a regional basis. The commenters stated 

that 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 4: Commenters expressed opposition to setting a floor for the Navajo Nation.

Response 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, commenters stated that the 

Navajo Nation opposes requiring a target or minimum level of transition to natural gas from coal 

even for jurisdictions with little or no NGCC capacity because trying 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 commenters asserted Navajo Nation coal is local to the mine and, at 

roughly $5/ton, costs only about $0.28/MMBtu. The commenters believed the suggested "one 

size fits all" approach ignores the recent investments that have been made in coal generation and 

would push more coal generation (and the associated investments) toward an uneconomic state 

with stranded assets. The commenters added that the "one size fits all" approach ignores recent 

investments made in coal generation and would push more coal generation and associated 

investments, toward an uneconomic state with stranded assets.

Comment 5: Commenters stated that the EPA should not adopt the "minimum level of 

generation shift" concept.

Response 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:

Commenters 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 of 
473

"generation shift" within these comments in the context of the EPA's acknowledgment that there 

are no NGCCs on the Navajo Nation. The commenters 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 commenters also opposed inclusion of co-firing natural gas as part of BB2 because of the 

technical obstacles and cost considerations that co-firing would present for the FCPP. The 

commenters stated these units can combust a small 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 commenters 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 

commenters believed this effort not cost justified, especially considering the extremely small 

load demand in the Navajo Nation. The commenters 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 6: Commenters expressed opposition to setting a floor based on national averages, 

suggest establishing a floor on a state-by-state basis.

Response 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:

Commenters asserted that requiring states to meet a floor might create more equitable goals 

between those states that have little existing NGCC capacity and those with excess, but could 

result in even less flexibility for states. The commenters believed 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 national average, the commenters 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. The commenters believed 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.

Commenters stated 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 commenters suggested the EPA establish a floor based 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 commenters 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 commenters believed this approach would achieve 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 of 
474

ongoing fuel diversity. Consistent with the NODA, according the commenters, the reduction in 

redispatch from this adjustment could be made up by requiring a minimum level of dispatch 

from all states: for example, a state producing 15% of its generation from coal or oil/gas would 

have to redispatch one-third of that amount, reducing the amount generated by oil/gas or coal 

units to 12% of its total generation. Alternatively, the commenters suggested the EPA could limit 

the application of BB2 to New York in recognition of the geographic and system topology 

constraints of NY's electricity system.

Comment 7: Commenters stated infrastructure concerns and questioned the definition of 

"region".

Response 7: See section V.D of the final rule preamble of the CPP for the EPA’s response to 

this comment.

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

Commenters believed 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 

commenters believed 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 8: Commenters stated the 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 8: See section V.D of the final rule preamble of the CPP for the EPA’s response to 

this comment.

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

Commenters 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. Commenters recommended that the EPA select a 

maximum utilization/capacity factor that is no lower than the level that each state or region has 

achieved historically. Commenters specifically recommended that the EPA use the average of 

the highest monthly utilization/capacity factors achieved during the winter and summer seasons 

during the years 2011 through 2013 in calculating the portion of the CO2 emissions reductions 

targets achievable through BB2 redispatch. Commenters stated this would reflect the times of 

greatest NGCC production during the 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 9: Commenters stated questions regarding goal recalculation.

Response 9: See section V.D of the final rule preamble of the CPP for the EPA’s response to 

this comment.

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

Commenters 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. 

Commenters also asked if the number goal will be less than that included in the original proposal 

if the RE/EE fossil offset is established in the final rule.

Comment 10: Set natural gas ramp rate at 5% per year.

Response 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:

Commenters 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 prices 

in the evaluation of the total costs of the BSER targets. Additionally, commenters 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 different for the different pathways. 

Commenters 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 

commenters did not have time to complete additional modeling at higher ramp rates. 

Nonetheless, commenters urged the EPA to consider higher shift rates, up to and including a 

continuation of 5%, the 10-year historic rate.

Comment 11: Commenters suggested adoption of a minimum 2% annual conversion rate for 

Tribal Nations and U.S. Territories.

Response 11: See section V.D of the final rule preamble of the CPP for the EPA’s response to 

this comment.

The following are summaries of the specific public comments under this comment:
476

Regarding the Tribal and Territories Supplementary Rule, commenters 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 equivalent or greater reductions is particularly 

important, according to the commenters, given that BB2 would not otherwise apply to these 

facilities given the lack of existing NGCC plants in these jurisdictions. The commenters asserted 

lack of existing facilities within the jurisdiction does not reflect a reduced opportunity to switch 

to lower-emitting fuel sources.

Comment 12: Commenters expressed support and opposition to redispatch approaches in the 

NODA.

Response 12: See section V.D of the final rule preamble of the CPP for the EPA’s response to 

this comment.

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

Commenters stated that there is significant 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 new NGCC 

units or by co-firing, and by repowering existing coal-fired EGUs with natural gas. The 

commenters stated that incorporating the potential to improve emission performance from all 

three of these methods into the BSER is in keeping with the EPA's overall approach and would 

better reflect the actual system that states have used to achieve emission reductions.

Commenters opposed the redispatch approaches in the NODA. Commenters opposed the 

redispatch approaches as well as the proposed alternative approach and co-firing as a 

consideration in lieu of, or addition to shifting from coal to natural gas. The commenters

believed the approaches could make the goals less achievable. The commenters asserted new 

resources are developed based on demand, cost and current 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 commenters stated it would be infeasible to apply on a 

uniform basis across states. The commenters 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.

Commenters stated the BB2 alternative approaches 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 commenters believed requiring a minimum 

level of natural gas dispatch may not be technically supportable as the BSER.

Comment 13: Commenters noted negative impacts of co-firing.
477

Response 13: See section V.D of the final rule preamble of the CPP for the EPA’s response to 

this comment.

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

Commenters stated that co-firing natural gas with coal, as discussed in the NODA, would require 

significant investment, leading to higher cost of electricity. The commenters 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 commenters also stated that moving 

coal-fired or co-fired units away from baseload operations into more of an intermediate or load 

following mode will decrease any gains in power plant efficiency envisioned in Building Block 

1. The commenters 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 CO2 emissions.

Comment 14: Projected emission rates for gas-fired EGUs should be based on combined cycle 

turbines.

Response 14: See section V.D of the final rule preamble of the CPP for the EPA’s response to 

this comment.

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

Commenters 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 

commenters 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 MWhr, which are the criteria EPA used to identify gas-fired units included in its proposal.

Comment 15: 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 15: See section V.D of the final rule preamble of the CPP for the EPA’s response to 

this comment.

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

Commenters stated that if the EPA 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 commenters stated that the EPA's existing 

proposal already raises substantial concerns about infrastructure adequacy, reliability and 
478

stranded investments; therefore the commenters would not be in favor of an expansion of the 

total amount of re-dispatch required.

Comment 16: Commenters were concerned about the interplay between BB2 and the CPP's 

objective of encouraging re-dispatch from higher-emitting generating units to lower emitting 

generating units.

Response 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 only 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 redispatching existing NGCC fleet investments, while states that have yet to make these 

investments may utilize the unconstrained dispatch to newly constructed NGCC units that are 

economic to build without any regulation. To address this inequity, where the re-dispatch is 

limited only by the lack of in-state NGCC capacity, commenters said that a minimum floor of redispatch should be attributed to the states to recognize likely cross state transfers of NGCC 

generated electricity to even out the compliance burden and more accurately 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 ability of states to meet the proposed 

glide path time line, 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 

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, 
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

Commenters expressed concerns regarding the ability of states to be able to meet the proposed 

timeline to comply with the interim emissions goals. Several of these comments are provided in 

the following paragraphs.

Commenters asserted that the proposal tries to do too much too fast. Commenters believed that 

state limits are too stringent and they offer a wide and differing level of compliance for many 

different states. Additionally, the commenters 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.

Commenters 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 commenters, 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. Commenters 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). 

Commenters reported that Arkansas's interim goal for 2020 through 2029 is 968 lb/MWh, and 

the final goal in 2030 is 910 lb/MWh. Commenters reported that, in order to meet the interim 

goals and 2030 targets, the large majority of emissions reductions must be made prior to 2020. 

Commenters stated that, because utility forecasting and generation planning are long-term 

prospects, they will effectively have to comply with Building Blocks 1 and 2 prior to 2020, in 

order to achieve the interim goals. 

Commenters argued that forcing the re-dispatch 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 commenters, during the recent polar vortex, natural gas demand exceeded delivery capacity 

demonstrating a current need. Commenters opined that permitting and construction of additional 

infrastructure would take more than two or three years to complete. According to the 

commenters, 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

Commenters 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 assets, increase 

power prices dramatically, and cause a stampede of new base-load natural-gas fired generation. 

Commenters opined that this wave of new base-load gas generation would lock-in levels of new 

fossil fuel emissions in the US power sector that would make getting on the IPCC pathways to a 

world with no more than two degree centigrade warming much more difficult, if not impossible. 

Commenters 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. Commenters opined that states will 

have no choice but to make dramatic changes in generation resource dispatch to achieve near or 

full compliance with the interim goals by 2020. Moreover, according to commenters, the 

constricted timeline will prevent states from cushioning economic impacts from retirements.

According to commenters, the EPA has overestimated the ability of states to achieve re-dispatch, 

and the EPA has proposed interim emissions goals that are so stringent that many states will be 

required to achieve most of their CO2 emissions reductions by 2020. According to commenters, 

given the EPA's proposed timetable for the approval of state plans, this would leave states at 

most with approximately 2 years to implement the necessary CO2 reduction measures; a task that 

they asserted will be extremely difficult or impossible to achieve without severe economic 

disruption. Commenters explained that, to determine the interim goal for each state, the EPA 

assumed that all emission rate reductions from Building Block 1 and Building Block 2 could be 

achieved at the start of the ten year interim goal compliance period. As a consequence of this 

assumption, commenters stated that, for many states, almost all of the emission rate reductions 

that the proposed rule ultimately requires must be achieved in the first year of the ten-year 

interim goal compliance period.

Commenters 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 commenters, this 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. Commenters 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. 

Commenters argued that states are left with little or no flexibility to determine a different 

compliance path to avoid the compliance cliff under EPA's proposed schedule for implementing 

the Proposed Rule. Commenters stated that the EPA intends to finalize the proposed rule in 

2015, which means that the earliest state implementation plans would be approved by EPA is 

2017. At most, commenters 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 electric generation, transmission, and distribution systems. Given the stringency of 

the interim goals, commenters reported that the proposed implementation schedule will force 

states to adhere to the EPA's anticipated re-dispatch and coal and oil/gas-unit closures to achieve 

compliance with the goals. 
481

Commenters asserted that the interim goals are largely unachievable in their current state for 

many jurisdictions. Commenters stated that, this is in no small part because it requires most of 

the emissions reductions to occur in 2020 via the natural gas re-dispatch in Building Block 2.

Commenters 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 implied by the 

goal computation) is uncertain. According to the commenters, 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. Commenters

stated that procuring adequate natural gas supplies to sustain a high level of utilization year 

round could mean, in the case of some states, building new pipelines or increasing the capacity 

of existing ones. For others, the commenters stated that getting the electricity to consumers 

currently served by steam units without expanding transmission may be a challenge. Thus, 

although the commenters 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 without increasing NGCC utilization to 70 

percent, they also agreed with stakeholders who are recommending to EPA that changes be made 

to the rate at which Building Block 2 is deployed as part of the goal-setting process. 

Commenters 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 the EPA's stringent interim goal requirements. Commenters reported that full redispatch by 2020 would be unachievable and bad public policy. Commenters 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 commenters, EPA fails to explain why interim goals are necessary to achieve the Proposed 

Guidelines' ultimate goal. Commenters stated that, although they do not believe EPA's suggested 

approaches will significantly alleviate the 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 guidelines. 

Commenters 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. 

Commenters 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 compliance strategies that ensure reliability. In particular the 

commenters 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.

Commenters stated that, while the idea of a "glide path" to the final requirements of the year 

2030 appears appealing, it would not work. In 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, the 

commenters believed 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 shifting 
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generation away from coal-fired plants to more expensive lower emitting carbon dioxide sources 

prematurely.

Commenters 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. 

Commenters opined that, in states 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 likelihood, leading to unnecessarily large amounts of new natural gas power plant investment 

and the long term lock-in of their CO2 emissions. Commenters 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 adequacy crisis in states with much smaller reserve margins. According to 

the commenters, 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 

emissions simply don't count under the proposed rule.

Commenters argued that, requiring that all changes in dispatch be achieved before the interim 

compliance period begins eliminates any flexibility states have to determine how quickly to 

make these changes or to assess and address the implications for the interconnected power 

system. Commenters 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, commenters

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 plants by 2020." Commenters

reported that Arizona is required to achieve at least 75 percent of its final 2030 goal by 2020. 

According to commenters, the DEQ reported that Arizona's only option to achieve this level of 

reductions by 2020 is through switching from coal to natural gas. Commenters reported that, 

even if Arizona has an approved state plan by 2017, this is an unprecedented reductions 

requirement that must be achieved in, at most, a few short years.

Commenters expressed concern that states will have 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 have significant impacts on Minnesota utility 

resource planning processes. Commenters stated that energy-intensive trade-exposed industries 

that their members operate in are not only vulnerable to electricity price increases, but also price 

volatility. Commenters opined that allowing states more flexibility to establish their own glide 

paths would allow for more efficient planning and provide the ability to take advantage of more 

cost-effective options that may arise in the 2020-2029 timeframe. Commenters further expressed 

serious concerns about reliability issues that could be caused by the proposed 2020-2029 interim 

emission performance period. Commenters 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 reliability safeguards. Commenters opined that the Clean Power Plan 
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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.

Commenters stated that the EPA assumes that the re-dispatching from existing coal-fired EGUs 

to NGCC EGUs under Block 2 can happen by 2020. However, according to commenters, the 

EPA does not consider that legislative changes, and in particular, ERCOT market changes that 

would be necessary to effect such a re-dispatching change. According to commenters, the shift in 

generation assumed by the EPA for Texas' NGCC units is the largest of all states, approximately 

19% of the total MWh increase assumed for the entire United States NGCC fleet. In fact, 

according to commenters, 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, commenters reported that the EPA assumes that Texas can effect 

such a change in less than four years. Commenters 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 its permitting authority to restrict operation of units. 

However, commenters asserted that the EPA's arbitrary assumption is flawed. Commenters

stated that neither the TCEQ nor the EPA has the legal authority to call the permits for the 

affected units to implement such a change through permitting actions. In citing RGGI as an 

example of how states might cause such a change, commenters asserted that the EPA fails to 

acknowledge the significant amount of time required to implement RGGI. According to the 

RGGI program design history webpage, commenters reported that discussions to create the 

program began in 2003. RGGI was reported by commenters to be first established in 2005 and 

includes two control periods, spanning from 2009 to 2014. According to commenters, from the 

initial concept to the final phase, the RGGI program encompasses more than ten years.

Furthermore, commenters 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. Commenters asserted that the effect of the EPA's assumption 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. Commenters reported that 

approximately 60% of Texas' required reductions on a lb/MWh bases are derived from Block 2 

and the majority of reductions for Texas will be required to be made by 2020. Commenters

stated that, given the legislative, regulatory, and implementation factors, it is not possible for 

Texas to implement such a drastic shift in energy policy in the time period assumed by the EPA.

Commenters asserted that, according to the proposed rule, EPA assumes Arizona would be able 

to complete this foundational transition from coal to natural gas by around 2020 - about five 

years after Arizona receives clarity on the state target and even less time from when Arizona's 

state plan actually gains approval. According to the commenters, since Arizona has no natural 

gas storage and only two major natural gas pipelines, this radically compressed timeline leaves 

Arizona virtually no time for proper economic, safety, and reliability based preparation.

Commenters noted that, in Arizona, the application of Building Block 2 makes a 

disproportionate contribution to the overall required CO2 reductions. According to the 

commenters, this result would essentially require Arizona to choose re-dispatch over other 

measures.
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Commenters opined that the time frame the proposed regulation would provide from its 

predicted finalization in June 2015 to implementation 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 multistate or regional plan; 

3. Meeting any requisites for proposing legislation 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 compact, 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 property 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 Endangered 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 devices to assure 

performance as intended. 

According to commenters, 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.

Commenters 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 

commenters, 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 in 
485

the proposed rule. More recently, commenters stated that, in the NODA, the EPA has noted the 

problems with the strict phase-in targets and has expressed an interest in additional ideas 

regarding the "glide path" to ensure that the overall framework of its rules includes sufficient 

flexibility. Commenters agreed that the originally proposed "glide-path" is a substantial, 

intractable problem. Commenters did not agree that allowing a credit for early excess CO2

emission reductions or a phase-in of Building Block 2 corrects the issues. 

Commenters 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. Commenters opined 

that the interim goals effectively remove all flexibility and limit the opportunity section 111(d) 

provides to take advantage of the remaining asset value of coal-fired generation. According to 

commenters, this problem is not limited to states for which Building Block 2 results in large 

amounts of CO2 reduction. Commenters reported that their state's (West Virginia) coal-fired 

EGUs with remaining useful life have already installed controls and undertaken work practices 

to meet the ARP, CAIR, CSAPR, and MATS. Commenters reported that compliance has come at 

a high capital cost, which can only be recovered if the units are allowed to operate at reasonable 

levels. According to commenters, in order for West Virginia to achieve the interim goal as EPA 

has outlined in the proposal, existing coal-fired EGUs would be have 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.

Commenters asserted that the EPA's presumption that Building Block 2 can be implemented by 

2020 is unrealistic. Commenters stated that, if EPA chooses to retain the interim goals 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 commenters, will require at least five to seven years. The commenters

stated that it is impossible for this capacity to be operational by 2020, given that it is very 

unlikely the state will have an approvable plan prior to 2019. Finally, the commenters reported 

that EGU outages for equipment installations have to be coordinated by the independent system 

operators (ISOs). Commenters argued that this planning and approval process, along with any 

necessary permitting, cannot occur by 2020.

Commenters reported that, between 2012 and 2016, Georgia is retiring over 3000 MW of coalfired capacity. In January 2016, commenters reported that there will be 9400 MW of capacity 

remaining in its coal-fired fleet. According to commenters, selective catalytic reduction (SCR) 

controls and flue gas desulfurization (FGD) controls will be installed on 95% of the remaining 

coal-fired generation capacity. Commenters reported that installation dates of these controls will 

range from 2001 to 2014. Assuming a 40-year book life for this equipment, commenters reported 

that the book life retirement dates will range from 2041 to 2054. Commenters asserted that these 

control systems should be viable assets for at least 21 years past 2020, the year that the EPA has 

assumed re-dispatch to NGCC to be completed.
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Commenters asserted that the EPA's proposed target schedule for Georgia is asking too much, 

too soon. Commenters reported that the Georgia's re-dispatch from coal unit to NGCC makes u 

30 % of the overall reduction in their emission rate reduction from 2012-2030 and is targeted by 

EPA for implementation by 2020. Commenters opined that re-dispatch away from coal-fired 

generation will result in a significant quantity of stranded viable assets. For example, accordig to 

EPA's modeling, commenters stated that Plant Scherer Units 1 and 2 will be retired by 2020 after 

recently installing nearly $500 million in air pollution control equipment. Commenters reported 

that these units are partially owned (30%) by Georgia municipal utilities and (60%) Georgia's 

EMCs. The premature retirement of these units, according to commenters, will leave small 

municipal utilities, and the Georgia citizens served by these utilities, with financial obligations 

for the installation of the air pollution control equipment extending for the next forty years 

without any benefit of electricity generation.

Commenters stated that, although EPA has determined that, on an average basis, many states 

have significant excess capacity at existing natural gas plants, this may not necessarily mean all 

of this capacity is available to displace coal-fired electricity on a year-round basis. Commenters

expressed that some states may have strong seasonal variations in demand for natural gas 

electricity, for example to accommodate high air conditioning demand during the summer in the 

Southwest. Commenters further expressed that other states may not have the natural gas pipeline 

capacity to allow power plants to run at 70 percent capacity in months when demand is high for 

gas as a heating fuel. Commenters stated that these concerns are surmountable with new or 

upgraded infrastructure, but this will take time to deploy and that Building Block 2 should be 

shaped in a way that accounts for this time.

Commenters stated that the existing transmission network in Arizona is designed for coal-fired 

EGUs located in the eastern and southern periphery of the State, while the NGCC EGUs are 

located in and around Phoenix and in the western periphery of the State. Commenters

complained that significant modifications and additions to the transmission network would be 

required to account for shutdown of the coal-fired EGUs and still provide reliable electricity. 

Commenters reported that, at the earliest the Kentucky SIP would be approved by EPA in June 

of 2017. According to the commenters, 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. Commenters stated, at a minimum, that process would take 6-12 months. 

Commenters further stated that permitting a new natural 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. Commenters

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. 

Commenters also reported that 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. According to the commenters, with a minimum construction 

period of 24 months depending upon start date, the retirement of an ESGS unit in 2020 would 

expose OMU ratepayers to market prices for a minimum of two years before a replacement 
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natural gas fired generating facility comes online. Commenters suggested that EPA should at a 

minimum permit a compliance timeline based upon the assessment made by the Kentucky 

Division of Air Quality working with the affected 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.

Commenters stated that the EPA glide path for Building Block 2 inherently assumes that redispatch 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 

commenters, 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 commenters asserted that 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 commenters suggested that 

the EPA acknowledge that the 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 commenters stated that, in the upper Midwest, where the MRES load is centered, 

there are already constraints in natural gas capacity. Commenters 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 additional supply to existing NGCC plants that EPA anticipates 

running at a higher capacity factor, not to mention what will be required for the construction of 

new facilities. Commenters further reported that new natural gas lines would also face the need 

of ample time frames to be permitted and constructed. Commenters stated that public notice, 

permitting, and construction will take years, not months. Commenters further stated that there 

will also be added delays if the lines are opposed, if there are environmental impact issues, or if 

there are eminent domain complications. Commenters 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 commenters, 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. Commenters stated that 

this is for the construction of lateral lines only and not including any mainline costs. Commenters

opined that the rules before us would lead to even more natural gas-fired generation than the 

predicted 830 MW; again, adding to the complexity and the time for planning, permitting and 

constructing sufficient natural gas construction in the upper Midwest alone. Commenters stated 

that, as the MISO natural gas infrastructure analysis concluded, there must be consideration for 

the lead-time required for pipeline construction to meet the need of power generators by 

2015/2016 and the potential for construction delays due to the anticipated increase in power 

generation interconnection request. Lastly, the commenters asserted that the decision-makers 

must recognize the competing needs for pipeline construction as industrials and other reshoring 

industries ramp-up. Commenters opined that this will affect the availability of skilled labor and 

materials and will most likely increase costs for those that postpone decision-making. 

Commenters 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 commenters, the 
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anticipated 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, commenters 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 mandated reductions by 2020, 

North Dakota 67 percent, South Dakota 67 percent and Wyoming 53 percent. This, according to 

the commenters, would require substantial changes in the entire electric industry in the matter of 

less than four years, which the commenters 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 ramp-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.

Commenters stated that Missouri can achieve all its needed reductions through alreadyannounced coal plant closures and through compliance with state policies already in place.

Commenters asserted that states have many alternatives to comply with the interim and final 

standards if re-dispatch would result in temporary reliability issues. Commenters noted that it 

should be emphasized that the building blocks are used to calculate what a state could do to cut 

emissions, not what it must do. Therefore, according to the commenters, if local reliability 

genuinely prevents re-dispatch of coal to gas, as some claim, there are other options. 

Commenters stated that other options are being deployed by Western states and utilities, and are 

already leading to significant emission reductions. According to the commenters, 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 reliability; and

• implement demand-side management at the regional level.

According to the commenters, 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 

commenters 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 commenters expressed that this 

provides states with flexibility to use the blocks in amounts different than EPA assumed in 

setting the state targets.
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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 

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 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 provided in 

the following paragraphs.

Commenters requested that states be allowed to use all years up to 2030 rather than the first two 

to three years to achieve the bulk of its carbon intensity goals would allow a more reasonable 

schedule for infrastructure expansion, thereby avoiding significant cost increases to rate payers.

Commenters 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 commenters 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.

Commenters opined that a more measured phase-in schedule would provide time for 

infrastructure improvements that would be required to ensure grid reliability. Commenters

requested that any improvements to Building Block 2 and the interim period take into account 

the remaining useful life of affected electric generating units.

Commenters 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. 

Commenters urged EPA to phase-in the re-dispatch component of Building Block 2.

Commenters stated that a substantially longer runway for states to make this coal-to-natural gas 

transition and include a phased approach to re-dispatch is needed. Commenters stated that it is 
490

needed because the interim average target is so close to the end 2030 target and it leaves little 

room for flexibility let alone enough time to site needed upgrades. 

Commenters recommended that the EPA adjust the 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. Commenters stated 

that additional timing will enable more cost effective decision making and reduce the cost and 

reliability impacts associated with stranded coal investments and simply defaulting to natural gas 

for compliance.

Commenters 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. 

Commenters 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 capital investment (e.g., in the form of pollution control retrofits)."

Commenters 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.

Commenters believed 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. Commenters also recognized the need to balance this redispatch 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 comply with other recent EPA rulemakings. Therefore, although the 

commenters believed 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 

requirements would better allow for necessary infrastructure improvements and economic 

considerations.

Commenters argued that, if the interim goals remain in the EPA's final guidelines, they 

supported the phase-in of emissions under Building Block 2.

Commenters requested the "front loaded" problem be addressed by building in phase-in periods 

for the implementation of the NGCC re-dispatch called for under Building Block 2, while 

providing a mechanism for utilities to get credit for early action, such as purchase of Rio Nogales 

in 2012.

Commenters preferred that the EPA phase-in Building Block 2 to allow for a more gradual glide 

path instead of the current cliff facing their state (Arkansas). Commenters 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, commenters stated that, if EPA chooses to retain the interim 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 supply. According to the commenters, 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) and North American Electric Reliability Corporation. Commenters 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.

Commenters agreed that many NGCC facilities have the technical capability to operate at an 

annual average capacity factor up to 70%. However, according to the commenters, other factors 

limit the ability of NGCCs to increase their current annual average capacity factor. To ensure 

existing NGCCs can provide up to 70% capacity factors, the commenters reported that many 

states/regions would need to address natural gas delivery and/or transmission constraints. 

Commenters recognized that strict implementation 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 commenters recommended that EPA 

provide a glide path that allows for these reduction opportunities to occur evenly throughout the 

interim compliance period. Commenters reported that projects to address natural gas delivery 

and transmission constraints take time to implement, and stated that two prime examples have 

occurred in New Jersey:

1. BL England Closure/Repowering

According to commenters, BL England entered into a consent order with the New Jersey 

Department of Environmental Protection ("NJDEP") in 2006, which required BL England either 

to meet NJ's standards for coal-fired EGUs or repower the facility to natural gas (NGCC). 

Commenters 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 (coalfired EGU), according to the commenters, was originally scheduled to shutdown in 2015 and the 

owner planned to complete construction of a new NGCC unit in 2016. However, the commenters

stated that Units 2 and 3 (oil-fired EGU) remain in operation. Commenters reported that a natural 

gas pipeline through the Pinelands must be built to deliver natural gas to facility, and that the 

Pinelands Commission rejected the pipeline project in January 2014.

Subsequently, the commenters reported that the plant 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 commenters, stated that the closure 

of Units 2 and 3 would 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 commenters reported that the NJDEP extended the retirement requirement 

for Unit 2 to mid-2017. Commenters stated that the amended consent order allows for an 

extension beyond 2017 if the New Jersey Board of Public Utilities ("NJBPU") or PJM determine 

that additional time is necessary to avoid reliability issues. The commenters further reported that 
492

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")

Commenters stated 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. Commenters 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. Commenters

further reported that the Project required approvals 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, according to the commenters, commencement of construction was delayed by 

three years due to the NPS Environmental Impact Study. In total, the commenters reported that 

the Project will have taken eight years from PJM approval to complete.

Commenters 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. Commenters concluded that, given the significant delays states may face 

in planning for increased use of NGCC units, EPA must allow for a gradual phase in of Building 

Block 2.

Commenters asserted that, as a preliminary matter, phasing in reductions under Building Block 

2, similar to the phase-in of reductions under Building Blocks 3 and 4, could address some of the 

near-term compliance challenges discussed in these comments for some states. In general, 

commenters stated that phasing in these reductions is more reasonable than assuming that all 

changes in dispatch between coal- and gas-based generation occurs before 2020. As EPA 

recognizes in establishing the Building Block 3 and 4 goals, commenters believed that it is 

appropriate to give states and electric utilities sufficient time to make system changes or create 

new programs. Commenters 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.

Commenters stated that the EPA should revise 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. Commenters asserted that a gradual approach would provide more flexibility for 

states and utilities to invest in the infrastructure that will be necessary to increase NGCC 

utilization to the levels assumed in calculating state goals.

Commenters shared the concerns of stakeholders who have requested EPA replace the current 

interim compliance period goals with a more reasonable glide path. Commenters 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 compliance 
493

scenarios so long as the State can demonstrate the same or better cumulative emissions are 

achieved.

Although commenters 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. Commenters stated that a phase-in schedule would 

provide time for infrastructure improvements that would support increased existing natural gasfired generation as well as modifications that would minimize stranded investments. 

Commenters opined that easing the emissions "glide path" in the first few years of the interim 

compliance period gives states time to focus on long-term infrastructure needs. Commenters

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 commenters opined 

that states would be able to develop increased renewable generation capacity, including new 

transmission lines where necessary, to reduce fossil fuel consumption. Commenters 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. Commenters 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. Commenters stated that, 

while they appreciate EPA's willingness to explore softening the emissions glide path for states, 

they are not suggesting that any change to this 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 in zero-emitting capacity.

Commenters 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 implemented in the proposal, the commenters 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, according to the commenters, 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. 

Commenters 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.

Commenters 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.

Commenters asserted that, to maintain affordability and reliability, the switch from coal to more 

natural gas fired generation needs to be phased in at an achievable rate through 2030, rather than 

by 2020.
494

Commenters 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. 

Commenters expressed that the EPA does not provide any specific information on how it would 

determine an appropriate phase-in schedule for Building Block 2. Commenters opined that it is 

not realistic to assume that the EPA will be able to establish 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

Commenters stated that they did not take a position on whether EPA should phase-in Building 

Block 2, and they reported that their states may have different positions on this issue. However, 

commenters requested that, if the EPA does choose to develop a phase-in schedule for Building 

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. Commenters recommended 

that the EPA carefully consider historic changes in the relative utilization of coal and NGCC 

plants in response to price considerations, as well as natural gas supply capacity, as an important 

source of information about the potential for and pace of shifts in utilization between coal- and 

gas-fired power plants.

Specifically Supported Phase-In of Building Block 2 Alternatives Raised in the NODA

Commenters supported a phase-in of Building Block 2 under both alternatives raised in the 

NODA. Commenters stated that utilities could be in a situation to need the flexibility afforded by 

each alternative. Commenters reported that, where 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. Commenters 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 

commenters’ analyses of EPA's modeling results, there are numerous stranded assets as a result 

of this proposal. Commenters 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.

Commenters recognized that a phase-in to provide an opportunity to develop infrastructure 

necessary to fully realize the effects of Building Block 2 may be necessary and supported a 

phase-in for Building Block 2, as EPA discusses in the NODA.

Commenters expressed that, if the EPA does not 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. Commenters

opined that such an approach is consistent with the statute, which provides for consideration of 

energy system impacts and the remaining useful life of the affected source. Commenters further 

opined that a more gradual glide path would also likely facilitate deeper long-term reductions. 

According to the commenters, there is likely an inverse relationship between forcing states to 
495

reduce greenhouse gas emissions almost immediately (i.e., by 2020) and a state's ability to shift 

generation to renewable sources of energy, since early reductions will depend predominantly on 

natural gas dispatch. Commenters 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 deferring alternative investment in renewables, energy-efficiency and energy 

storage. Commenters requested that states be able to retain the authority to select the approach 

best suited to their needs and to time the reductions accordingly.

Commenters supported the allowance for compliance of measures which occur between the 

baselines year(s), and the first interim compliance deadline in 2020. Commenters opined that this 

would encourage states to act early in building renewable generation and energy efficiency 

incentive programs to create a smooth transition into the compliance period, and will also 

provide some credit to states already making these investments. Commenters further stated that, 

while it would not be appropriate to make these early reductions legally enforceable prior to 

2020 given the timeline for SIP submission and approval, these reductions can be noted as part 

of a state's plan as a source of emissions reduction. Commenters agreed with commenters who 

suggest that the re-dispatch of NGCC units contemplated 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. Commenters expressed that 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.

Commenters 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. Commenters 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. Commenters 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. 

Commenters believed 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 more 

consistent with Buildings Blocks 3 and 4 where increased utilization is phased-in between 2020 

and 2029. Commenters further stated that they supported the second phase-in option included in 

the EPA's NODA; that Building Block 2 be modified to respond to stakeholder concerns about 

the pace with which generation in some states may need to be shifted from higher-emitting to 

lower-emitting-units.

Commenters expressed that it is not clear from the NODA how EPA would structure a phase-in 

schedule for Building Block 2. Commenters stated 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. Commenters stated that, at minimum, the EPA should recognize 

that it takes three to five years to plan, permit, contract for capacity, finance and build additional 
496

pipeline capacity. However, commenters believed 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.

Commenters urged the EPA to examine early action (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. Commenters urged the EPA to work with states, 

regulatory authorities such as the 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, 

the commenters requested that EPA develop a more reasonable, phased-in timetable for redispatch that would not threaten the reliability of the regional grid nor impose undue stranded 

costs on states' electric ratepayers. Commenters opined that such a development should result in 

more realistic interim goals, which would not imply such sharp emission rate reductions by 2020, 

and which would provide the EPA and states a more measured way to gauge progress toward the 

2030 goals. Commenters stated that a more reasonable, phased-in timetable is important for 

states like California that have both significant NGCC capacity and few high emitting resources. 

Commenters 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

Commenters agreed with stakeholder 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 

pipeline expansion or transmission improvements) needed to support more use of existing natural 

gas-fired generation. However, commenters did not support either of the alternative approaches 

that EPA has requested comment on in the NODA to address stakeholder 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. 

Commenters recommended another glide path approach 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 Sufficient to Address Compliance Concerns

Commenters 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.

Commenters asserted that, in the NODA, the EPA did not provide any additional data to support 

either of their proposed approaches. Moreover, according to commenters, 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) as 
497

proposed. First, commenters stated Building Block 2 is an "outside the fence" activity over 

which the EPA has no authority. Commenters stated that the EPA is neither authorized nor 

qualified to dictate to states how their natural gas units should be operated or dispatched. Second, 

commenters stated that Rule 111(d) does not provide flexibility for their state (Texas), but 

instead would require their state to implement approximately 77% of its emission reductions by 

2020, which they opined is both unreasonable and unachievable. In conclusion, commenters

stated that the alternate glide path proposals in the NODA do not appear to provide any 

meaningful flexibility for their state to meet EPA's interim emissions goals.

Commenters stated that, while they understand the 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. Commenters asserted that climate change is a threat of epic 

proportions, and adequately addressing that threat must not be compromised.

Commenters stated that, while the EPA seems to 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 

phasing in of NGCC units) is inadequate. Commenters stated the NODA still fails to recognize 

the infrastructure, permitting and construction limitations. Commenters stated that, while the 

proposal contemplates adjustment of individual state targets for this building block based on 

infrastructure needs and the time to complete them, such approach will require significant time to 

study and implement, which is not feasible given the timing requirements for filing of state 

plans. Commenters added that construction timelines are difficult to accurately predict and thus 

create unnecessary compliance uncertainty and risk.

Commenters opined that, while the idea of a "glide path" to the final requirements of the year 

2030 appears appealing, it will not work. Commenters stated that, in addition to the glide path 

requiring a sharp decrease in emissions in the year 2020 or over-compliance in the latter years of 

the period, they had other objections as well: Commenters asserted that the glide path proposed 

by the EPA would prematurely 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.

Commenters stated that the EPA has begun to recognize 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 coalgeneration. However, according to the commenters, 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.

Commenters expressed that, in the NODA, EPA appears to acknowledge the major timing issues 

associated with NGCC re-dispatch and has asked for comment on whether a more gradual phasein would alleviate concerns over workability and reliability. Id. at 64,548-549. The commenters

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 commenters, states have no authority 

to mandate dispatch of NGCC within their state; the dispatch of power is governed by the RTOs. 

Commenters stated that NGCC units in existence were planned, permitted, constructed and 

interconnected with transmission based on the needs of the operating/owning utility, and are 
498

limited by physical pipeline and transmission constraints, permit limits and gas availability, none 

of which can be simply ramped up to meet the 70% assumed capacity factor by 2020. 

Commenters stated that the glide path's assumption that all NGCC can be ramped up to 70% in 

2020 ignores basic operational issues. Commenters 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 meeting reliability requirements of the North American Electric Reliability 

Corporation (NERC). And of course, according to the commenters, that is predicated on the 

assumption that transmission capacity is available for the increase in NGCC operation. In fact, 

according to the commenters, if the existing units are in a transmission constrained area, new 

transmission must be added to accommodate the load. Commenters stated that transmission 

studies on average take about two years to complete and that new transmission cannot be 

guaranteed to materialize in the time frame suggested by the proposed rules. Commenters

reported, for example, the Minnesota CapX 2020 project took roughly 10 years from initial 

planning stages, to permitting, to the placement of the new lines into service. Commenters

further reported that the CapX project has taken 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 purchased in whole, and not just the impacted portion. See Minn. 

Stat. 216E.12, subd. 4. The commenters asserted that, as the EPA is well aware, contested case 

proceedings would significantly lengthen the timeframe of building needed transmission, will be 

a significant barrier to states meeting glide path milestones, and are an inevitable part of 

transmission siting in the 21st century.

Concerned that Phase-In Proposals Would Weaken or Delay Carbon Pollution Reductions

Commenters stated that EPA's proposals to develop 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.

Commenters requested that EPA not adopt a phase-in for either building block 1 or 2 as it will 

undermine efforts to meet the national all-sector goal of 17% by 2020 and 28% by 2025. 

Commenters 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. 

Commenters expressed that they do not support the NODA proposed changes to the glide path. 

Commenters asserted that the draft proposal already allows significant flexibility to states in the 

timing for reaching their goals of the CPP and further delays in achieving emissions reductions

are contrary to the overall goals of the CPP to make a significant contribution to reduce U.S. 

global warming emissions in a timely way. Commenters 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. Commenters also asserted that delaying emissions 

reductions could also result in more stranded assets with utilities making investments to nearterm targets that may be unsuitable for meeting the long term targets.

Phase-In Not Needed
499

Commenters opined that, with respect to the proposal for a phase-in for Building Block 2, EPA 

should refrain from adopting such methodology. According to the commenters, a phase-in 

methodology is not needed for Building Blocks 1 and 2, as it is for 3 and 4. Commenters

believed the EPA was correct in its proposed rule in determining that the BSER for Building 

Blocks 1 and 2 were feasible in the proposed timeframe.

Comment 3: Commenters said that states should have authority to define their own glide path 

and timeline to address compliance concerns.

Response 3: The EPA disagrees with commenters. The interim standards are an important part 

of this final rule and are essential for successful performance. The EPA has provided many 

pathways that states can choose to comply. The 111(d) final rule requires that states develop 

plans that establish emission standards for 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 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:

Commenters argued that, eliminating states' compliance flexibility runs afoul of section 111(d)'s 

requirement that states be able to consider a units' remaining useful life in complying with 

section 111(d).

Commenters urged EPA to recognize state authority to determine the interim path and timetable 

to achieve 2030 carbon intensity targets.

Commenters opined that 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.

Commenters suggested that EPA allowing states to establish EGU-specific re-dispatch or refiring dates by permit or rule is reasonable.

Commenters asserted that, because states are in the best position to identify the pace at which 

additional re-dispatch can be incorporated into the system, the EPA should allow states the 

opportunity to develop and submit to the EPA adjusted interim targets for 2020-2029 that 

account for a more gradual ramp-up of NGCC capacity factors. Commenters expressed that 

states' final 2030 targets could remain the same.

Commenters requested that the EPA allow states to determine what level of re-dispatch is 

feasible and the reasonable schedule for implementing NGCC re-dispatch.
500

Commenters 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. Commenters stated that, incorporating a 

phase-in of the re-dispatching as discussed in the October 30 NODA (79 FR 64548) would 

mitigate some of the near-term impacts of Block 2. However, commenters asserted that the EPA 

is not qualified to determine the feasibility of such a fundamental shift in a state's energy policy. 

Commenters opined that only the state public utility commissions are in a position to evaluate 

the feasibility of shifting generation from one fuel source to another on the scale that the EPA is 

assuming under Block 2. Furthermore, commenters asserted that, what may be feasible in one 

state is not necessarily feasible in another state.

Commenters believed that each state should be allowed 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 

Block 2 are all options that a state should be able to use when establishing its glide-path.

Commenters suggested that the EPA allow the states to determine how quickly Building Block 2 

may be phased in. Commenters reported that the EPA suggests that an appropriate phase-in 

schedule could be based on "whether, and to what 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 stranded investments 

considering the "book life" of generating assets. Id. at 64,548-49. Commenters asserted that 

states are in a much better position than EPA to assess these factors and determine an appropriate 

phase-in schedule. Commenters also stated that the EPA gives no indication as to how it would 

go about assessing these factors and developing a 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 supported eliminating or adjusting interim goals, 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 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 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 
501

“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 Eliminating Interim Goals

Commenters suggested that the EPA not finalize an interim goal for implementing the NGCC 

dispatch. Most of the commenters believed 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, 

commenters recommended 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, commenters stated that the EPA must allow each state to 

make its own determination as to which measures can be implemented on a timetable that is 

manageable for the state but leads to achievement of the 2030 goals. Commenters stated that, 

although both of the approaches set out in the NODA address some of their glide path concerns, 

neither approach provides states the same ability to design cost-effective compliance plans that 

are consistent with the technical realities of shifting generation between existing coal- and gasbased units that would be provided by eliminating the interim goals. Commenters 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. Commenters 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. Commenters suggested that interim targets be dropped and 

replaced with objective criteria that include both procedural and substantive criteria that states 

would be required to include in their compliance plans to demonstrate a reasonable glide path to 

the 2030 targets.

Commenters asserted that the flexibility that the EPA advertises with this proposed rule would be 

more credible if the interim goals were eliminated. Commenters stated that, in its current form, 

the interim goal glide path is very specifically tailored to an exact combination of building 

blocks implemented by a precise schedule set by the EPA. According to the commenters, 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 goals or final goals would not be able to be met. 

Commenters 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 factors contributing to that state or region's ability to reduce carbon emissions. 

Commenters 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.

Commenters requested that the EPA consider a glide path approach by 1) removing the interim 

goals from the final rule and/or 2) delaying the compliance deadline by five years from 2030 to 

2035. 
502

Commenters 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 tailor the 

contour of its glide path to attaining its 2030 goal based on the unique circumstances and 

limitations for implementing the four building blocks. Commenters stated that the state would be 

required to establish a plan, subject to EPA approval, with enforceable milestones for phasing in 

the reductions during the 2020 to 2029 period, and a demonstration that its proposed time frame 

for phasing in those reductions is as expeditious as practicable. Commenters asserted that such 

an approach is consistent 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.

Commenters expressed that the effect of the interim goal severely limits the opportunity to fully 

take advantage of remaining asset value of existing coal-fired generation.

Commenters requested that EPA eliminate the interim state targets or recalibrate them to account 

for a more gradual phase-in of redispatch to NGCCs over the 10-year interim compliance period. 

Commenters believed that both of these steps would help to alleviate many of the negative 

impacts this aspect of the Proposed Rule.

Commenters supported all options that provide the state with flexibility to achieve the state goal 

based on state procedures, legislation and with coordination with all appropriate stakeholders. 

Commenters believed that states should continue to be allowed to choose rate-based or massbased goals and single-state and/or multi-state plans to achieve state goals according to the glide 

path developed by the state. Commenters specifically supported states being able to design a 

"rate of progress" plan and should not preclude the use of any means the state chooses to reach 

the end goal (including whether to adopt the "alternate" 2025 state goal or adopt what are termed 

in the current proposal the interim and final goals. Commenters suggested that if a state develops 

a "rate of progress" plan that satisfies the final goal, then the interim goal should be eliminated. 

Commenters believed that the interim goal creates unnecessary reliability risks, increases 

consumer cost, and improperly restricts the state's ability to exercise its statutory prerogatives 

under the CAA to develop appropriate compliance plans and alternatives, including 

consideration of remaining useful life of existing resources.

Commenters stated the EPA should not finalize any interim goal and should allow states to 

determine and set reasonable schedules for implementing NGCC re-dispatch. Commenters noted 

there are obstacles to increased NGCC operation by 2020 that will make meeting the Proposal's 

goal unlikely, if not impossible. Commenters stated increased NGCC operation at individual 

units may require upgrades to natural gas pipelines, additional electric transmission facilities, or 

air permit amendments, as well as changes to the operation of the electrical grid. Commenters

were concerned that neither EPA nor 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 the timeline to properly comply. Commenters 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 interim 

goal, commenters suggested the EPA should assume a ramp-up period for re-dispatch 

implementation, similar to EPA's treatment of renewables and energy efficiency.
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Commenters stated that the EPA should at a minimum permit a compliance timeline based upon 

the assessment made by the Kentucky Division of Air Quality working with the affected EGUs 

that recognizes both the reality of the time 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. Commenters 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 January 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 completed 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 before 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.

Commenters recommended the EPA to eliminate the interim goal and allow states to determine a 

schedule for implementation based on feasibility and cost. Commenters stated that, if EPA 

chooses to retain the interim goals and allow states to phase in Building Block 2 over 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. Commenters stated the EPA also should consider the time required to integrate any 

transmission enhancements needed to address impacts to reliability, as indicated by MISO and 

NAERC.

Commenters stated that, based on the current and future demand on the existing and underconstruction 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 capacity 

factor is not achievable by 2020. Commenters 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. Commenters stated that Georgia's NGCC fleet 

capacity is not adequate to support a reliable power grid and 70% dispatch rate for NGCC. 

Commenters 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 Goals
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Commenters 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 commenters asserted 

that the state would still achieve the 2030 final goal established by the EPA based on the four 

building blocks, but the stringency of the interim goals would be adjusted to reflect the statespecific schedule for the expeditious implementation of the control measures within the state. 

According to the commenters, this would enable each state to develop a workable and reasonably 

achievable plan based on its ability to install the control measures, the cost of compliance, 

impacts on reliability, and other relevant state-specific factors. Commenters further stated that 

the state plan would include federally-enforceable milestones, for implementation of the 

emission reductions necessary to meet the final goal.

Commenters requested that, in cases where EPA may be unable to adjust state interim goals prior 

to the issuance of the final rule due to insufficient data, EPA establish a procedure for the 

adjustment of the state goals. Commenters 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. Commenters suggested that such state 

requests could be submitted to the EPA within 6 months from the promulgation of the final 

emission guidelines. Commenters 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 redispatched as well as the barriers or limitations for achieving the re-dispatch.

Commenters 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 Compliance Period

Commenters 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 that 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: Commenters 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 from 
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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:

Commenters 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 Clean Energy Organizations appreciate EPA's attempt to make 

state compliance with the Clean Power Plan as flexible as possible. Commenters also requested 

that EPA set an interim goal based on average emissions during the 2020-2029 timeframe. 

Commenters stated 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 goal in a costeffective manner before EPA makes any changes to the "glide path," such as those identified in 

the NODA. According to the commenters, for states like Minnesota - states that have renewable 

energy generation in 2013 beyond the 2030 goal, robust 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. Commenters stated 

that, in other words, early 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.

Commenters considered the NODA phase-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 supported or conditionally supported an allowance for early 

action credit, 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

Commenters believed that early crediting should be allowed. 

Commenters 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 be 
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useful to some states when designing compliance plans. Commenters 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 commenters, however, early recognition does not address fully the concerns raised 

in their comments about the interim compliance goal and the magnitude of reductions that are 

required before 2020. Commenters asserted that, 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. Commenters further asserted that credit for early RE and EE reductions also does not 

address infrastructure concerns or other technical challenges associated with increasing the 

utilization of existing NGCC units.

In addition, commenters argued that, given the timing challenges states face in submitting timely 

compliance plans for EPA approval, it is unlikely that states would be able to begin compliance 

plans early in order to take advantage of pre-2020 reductions. Commenters asserted that, if states 

would like to do so, the final guidelines should make it clear that this is an option. Nonetheless, 

commenters reported that early recognition, is not sufficient to alleviate these concerns and does 

not obviate the need to eliminate the interim compliance goals.

Commenters stated that, while the EPA identifies early action crediting as a potential response to 

stakeholder concerns regarding Building Blocks 1 and 2, they believe that such an approach is 

justified for reasons beyond smoothing out a "glide path." Commenters asserted that early 

crediting for new actions will also spur states to act earlier, accelerating the expansion of the 

advanced energy markets, driving earlier emission reductions, and providing states a longer 

period for compliance activity. Commenters stated that early action crediting can achieve all of 

this without weakening the stringency of the emission targets. Conversely, commenters 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.

Commenters opined that early credit for emissions reductions would help ease issues related to 

interim goals. In addition, the commenters believed that early credit would send a signal to states 

encouraging early action on emerging problems.

Commenters strongly supported EPA allowing early reductions credit to ease the 2020-2029 

glide However, the commenters asserted that the EPA should only consider such approach with 

respect to energy efficiency measures. According to the commenters, this is because energy

efficiency is a unique resource. Unlike other investments, the commenters stated that energy 

efficiency continues to replace demand long after the actual measures themselves are installed. 

Commenters 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. Commenters expressed belief that 

the EPA should consider allowing credit for savings experienced as early as the baseline year of 

2012, so long as EGUs can demonstrate a precise amount of savings using the Evaluation, 

Measurement and Verification (EM&V) methodology approved or developed by EPA. 
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Furthermore, the commenters 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. 

Commenters opined that this would encourage states to act early in building renewable 

generation and energy efficiency incentive programs to create a smooth transition into the 

compliance period, and would also provide some credit to states already making these 

investments. Commenters stated that, while it would not be appropriate to make these early 

reductions legally enforceable prior to 2020 given the timeline for SIP submission and approval, 

these reductions can be noted as part of a state's plan as a source of emissions reductions. 

Commenters supported incentives for early action to encourage investments in renewables and 

energy efficiency and a shift away from fossil-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. 

Commenters 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

Commenters stated that early 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.

Concerned Early Crediting Will Not Result in Similar Emission Reductions to What Was 

Proposed/Provides Conditions for EPA to Consider If Early Action Credit Mechanisms Allowed

Commenters expressed concern that allowing for early action credit may not result in the same 

level of emission reductions to the proposal. Commenters 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 attempt to "cherry pick" early actions only from low-emission EGUs or emission 

reduction systems. Commenters 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 for 

renewable energy deployment at the same time the state was increasing emissions from fossilfueled generators.

Comment 7: Commenters said that the EPA should account for retirements occurring in the near 

term in Building Block 2 calculations and described how this would affect Tennessee.

Response 7: The EPA thanks the commenters. The goals are based on an overall CO2 emission 

performance rate calculated using data on affected sources rates during the 2012 base year. The
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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 the specific public comments under this comment:

Commenters requested that the EPA account for retirements occurring in the near term in 

Building Block 2 calculations. Commenters expressed that the EPA's Building Block 2 

calculation assumes that emissions from units that retired in 2012 (the base year) or that will 

retire (according to their operators) in the next few years are relevant for purposes of setting a 

baseline. However, the commenters reported that the rule's proposed compliance period will not 

begin until 2020. According to the commenters, by including business-as-usual retirements in the 

target-setting exercise, EPA fails to identify the best system of emission reductions, since states 

with recent or imminent coal plant retirements may face relatively more lenient standards than 

other states. Commenters urged the agency not to allow states to ignore near-term changes in the 

generation mix, including the large number of retirements expected to occur between 2012 and 

2017 or 2018, when final state plans are due. 

Commenters 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 redispatch. For example, according to the commenters, 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. Commenters 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. Commenters stated that, 

after a 6 million MWh reduction, the units that continue 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. Commenters opined that this is a much more substantial difference in stringency 

than the range of options 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.

Commenters asserted that Tennessee's situation also illustrates this point. As of this writing, the 

commenters reported that three coal-fired units in Tennessee that were included in EPA's goalsetting calculation have either retired or have announced plans to retire prior to the 2020 

compliance period: Allen Steam Plant, Johnsonville Fossil Plant, and John Sevier Fossil Plant. 

According to the commenters, these three facilities generated approximately 7.5 million MWh in 

2012, and Tennessee's 2030 target emission rate under the Clean Power Plan is 1,163 lbs 

CO2/MWh. Under Building Block 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 commenters explained, 

because the three retired (or retiring) units noted above will be removed from the state's

generation mix regardless of the rule, the state can simply bypass the reductions needed satisfy 

Building Block 2. Commenters reported that, even if Tennessee were to replace the 7.5 million 

MWh produced by these retiring units with generation from new combined-cycle gas plants 

(which the commenters 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 of 
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1,111 lbs CO2/MWh if it adopted the measures specified under Building Blocks 1, 3 and 4. In 

fact, according to the commenters, 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 commenters 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. 

Commenters 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. Commenters asserted that the most accurate process would 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 

commenters, if Tennessee were to submit its plan to EPA in 2016, the agency would use 2015 

data rather than 2012 data to calculate Tennessee's interim and final target emission rates. If the 

state took an extra year and submitted its plan in 2017, the commenters stated that the EPA 

would use 2016 data. Commenters stated that this would ensure that plants that existed as of 

2012 but have retired since that time are not included in either the target-setting or compliancedetermining process. It would also ensure, according to the commenters, the use of the most 

accurate information concerning available underutilized NGCC capacity for purposes of 

calculating the enforceable state emission targets. Moreover, the commenters requested that the 

EPA delete from its target calculations and compliance determinations any still-existing plants 

with legally enforceable retirement obligations in place at the time the compliance period begins. 

Commenters asserted that this would ensure that Building Block 2 is fully effective in states like 

Tennessee. 

Commenters argued that their recommended approach for plant retirements would have the 

added benefit of resolving uncertainties regarding combined cycle plants that are currently under 

construction. Commenters 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 commenters, under EPA's current approach, 15 percent of 

the generating capacity of an under-construction NGCC is included in Building Block 2's redispatch scenario, whereas the other 55 percent is reserved "to meet other system needs 

presumed to have motivated the construction of the 'under construction' NGCCs" namely, to 

replace recent or imminent coal retirements. However, the commenters 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 commenters

reported that any underutilized capacity can be included in the re-dispatch scenario described in 

Building Block 2. 

Comment 8: Commenters said that EPA does not have authority to establish either of the EPA's 

Building Block 2 phase-in approaches.
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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:

Commenters asserted that both of EPA's Building Block 2 phase-in approaches require EPA to 

have authority that it does not possess. According to commenters, under the first option 

identified, EPA has suggested, "to the extent that more infrastructure is needed, the methodology 

for Building Block 2 could be modified on the basis of how much utilization shift toward 

existing NGCC generation would be possible by 2020." 79 Fed.Reg. at 64548. Commenters

stated that the EPA does not have the authority to prescribe energy policy for a state. Under the 

second option identified, commenters reported that the EPA has indicated that it "believes that 

the proposal provides states the flexibility to specify appropriate requirements for individual 

EGUs, including coal-fired EGUs, taking into account the potential for stranded investments and 

other unit-specific factors." However, commenters 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. Commenters argued that the 

EPA does not possess this authority; in their state (West Virginia), this authority resides with the 

WVPSC.

Comment 9: Some commenters said that the final rule should account for remaining useful life 

of the affected EGU and suggested taking into account the book life of the facility when 

determining the timeline for attaining interim goals, 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 VII.G.

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

Remaining Useful Life

Several commenters argued that the proposal did not adequately account for the remaining useful 

life of the affected EGUs subject to the rule and that any improvements to Building Block 2 and 

the interim period must also take into account the remaining useful life of affected EGUs.

Commenters complained that the EPA did not consider remaining useful life as required under 

the CAA, nor does its proposal allow the states to consider it. According to the commenters, 

the EPA relies upon the purported flexibility afforded states under its Proposed Carbon Rule, as 

somehow excusing its failure to consider the remaining useful life concept. However, the 

commenters, not all states have the same degree of flexibility under the Proposed Carbon Rule 

(cites Arizona as such a state). According to the commenters, Arizona has a younger coal fleet 
511

and Arizona utilities have made large investments in their coal plants in recent years to comply 

with EPA regulations. Commenters reported that two coal plants were placed in service less than 

ten years ago. Commenters asserted that failure to consider the age of coal generating units will 

result in stranded investment from premature closure of coal plants, which will have significant 

retail rate implications and reliability implications.

Commenters asserted that Arizona is home to some of the newest coal fired units in the country 

with the most recent units commencing operation as recently as 2009. Commenters expressed 

that investments assume a long and useful life of 40 years or more. According to the 

commenters, the application 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. Commenters 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.

Commenters recommended that the EPA adjust the Building Block approach to exclude 

remaining useful life units from 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 commenters, the additional timing will enable more cost 

effective decision making and reduce the cost and reliability impacts associated with stranded 

coal investments and simply defaulting to natural gas for compliance.

Commenters stated that EPA's proposal requested that comments be submitted to EPA, so that 

EPA can determine how to account for the remaining useful life of coal plants, and asserted that 

the request exposed a fundamental error in the Rule Proposal. According to the commenters, the 

CAA does not direct EPA to consider remaining 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 which such standard applies." Commenters 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 (and other factors); rather than giving that authority back to the states, EPA 

assumes this role itself. According to the commenters, this is in direct and illegal conflict with 

the CAA. Commenters 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 commenters 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.

Commenters believed that the final EPA rule must 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 to 
512

the commenters, book life and remaining useful life can be used to extend the glide-path or to 

raise the overall goal. Commenters stated that, for Arizona, five coal-fired generating units have 

remaining book lives that would result in their economic operation into the period between 2020 

and 2030: Cholla (through 2024), Springerville (through 2025), and Springerville (through 

2030). According to the commenters, there are also five coal units that have remaining book 

lives that would result in operation beyond 2030: Apache ST, Coronado, and Springerville.

Commenters reported that, absent consideration of book life and remaining useful life, the 

stranded investment in Arizona could be up to $3 billion.

Commenters stated that the EPA could either take book life into consideration itself or allow 

states to do so in calculating state-specific goals. 

Commenters caution, however, that book life is not, by itself, an indication of "useful life." 

According to the commenters, many assets, including EGUs, will have useful lives that far 

exceed the nominal "book life" due to care in operation and maintenance practices, investment in 

emissions controls, state prudency requirements, reliability needs, and overall economic value. 

Thus, the commenters asserted that the fact that an EGU may be beyond its nominal "book life" 

is not an indication that the EGU is no longer used and useful, is inadequately controlled, or is 

the subject of inappropriate life extension. Any such conclusion would require evaluation of 

many factors that are beyond the scope of this rulemaking.

Commenters explained that, book life does, however, present 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 reduction in EGU usage) prior to the end of the book life, according to the 

commenters, 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. Commenters stated that, if the EGU does not run, those costs that 

would have been recovered during the longer run life must still be absorbed by the utility's 

customers (if investor owned or a non-tax-supported publicly-owned utility), members (if 

cooperatively-owned), or taxpayers (if the publicly-owned utility is tax supported). Commenters

asserted that the earlier re-dispatch (reduced utilization) occurs within the life of an EGU, the 

higher the cost of that re-dispatch.

In summary, commenters 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 occur 

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. Commenters expressed belief 

that it is important to emphasize that their proposal is specifically intended to promote the 

calculation of more reasonable and achievable CO2 intensity targets and is not intended to 

suggest a date by which EGUs could or should be retired or cease burning coal.

Commenters asserted that a book life of 40 years is one way to account for the remaining useful 

life of the source; however, they believed that the EPA should allow state public utilities 

determine the remaining useful life of sources in their state when setting Building Block 2 targets
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Several commenters specifically opposed/conditionally supported the EPA basing the glide path 

on the book life of a facility.

Commenters objected to EPA's suggestion that book life is an appropriate means of 

implementing this statutory mandate. According to commenters, book life is an accounting and 

rate-making concept that concerns depreciation. Commenters stated that it does not describe the 

end of useful life of an asset, which should be determined on a case-by-case basis. Moreover, 

commenters opined that the statutory mandate to consider the remaining useful life by 

implication includes the discretion to exempt such sources from regulation. 

Commenters asserted that basing the glide path 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. Commenters stated that a facility may have an additional 20 years of remaining useful 

life beyond the end of its book life. Commenters also stated that building book life into the glide 

path will not necessarily protect facility owners from stranded investments. Commenters

reported that facilities selling power into organized markets recover their capital investments 

according to market conditions, without a recovery guarantee and that operating units beyond the 

end of their book lives is therefore often necessary to recover investment capital. According to 

commenters, future market conditions cannot be predicted and states will not be able to 

predetermine a glide path for these units that ensures cost recovery. Commenters asserted that, 

even facilities that sell into unorganized markets, and thus may have some form of guaranteed 

return through a FERC tariff or state rate, may not be able to recover the costs of pollution 

control retrofits if these are not included in their respective tariff or rate.

Commenters asserted that "book" life is not the criteria section 111(d) authorizes states to 

consider. Instead, commenters reported that states may consider "remaining useful life" which is 

likely to be very different than "book" life, which depends on application of accounting 

principles and the Internal Revenue Code.

Commenters suggested that, if EPA determines 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 concerned that the EPA's proposed glide path will incentivize 

significant natural gas infrastructure in the early years of the compliance period at the expense of 

renewable energy development.

Response 10: The EPA thanks the commenters. The EPA believes the modifications in the final 

rule will provide sufficient incentive for 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:
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Commenters 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. Commenters recognized the need for some compliance flexibility early on. Therefore, 

commenters 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. Commenters

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 inexpensive in 2020 or 2030, particularly given the very high 

price for natural gas elsewhere in the world and increasing demand for the product. Commenters

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. Commenters

stated that their plants, for example, use conventional steam turbines, and when combined with 

thermal energy storage have the same operational characteristics of fossil fueled power plants, 

without their emissions. Commenters also urged the EPA to recognize the speed of solar 

deployment, along with the modularity of solar, which makes it a great choice for meeting 

incremental generation needs and can assist states in quickly achieving compliance with EPA 

regulations under section 111(d). Commenters 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 energy) 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 are summaries of the specific public comments under this comment:

Commenters 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 operators of coalfired power plants to cease coal combustion at a date certain during the interim compliance 

period. Commenters asserted that these agreements effectively shorten the book life of those 

plants. Commenters reported that a limited book life approach would maintain legally binding 

commitments in Oregon and the few other states that have already secured agreement to close 

coal plants and transition to cleaner sources of energy during the interim compliance period.
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Comment 12: Commenters suggested that states could rely on other existing market 

mechanisms to define emission reduction glide paths (e.g., competitive wholesale markets 

administered by RTOs).

Response 12: The EPA thanks the commenters. The EPA believes 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) 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 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:

Commenters asserted that states could rely on other existing market mechanisms to define 

emission reduction glide paths. For example, according to commenters, the competitive 

wholesale markets administered by RTOs could be used to define a reduction trajectory for 

states. Under such an approach, commenters 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. Commenters stated that this would alter the dispatch of units to better reflect their CO2

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.

Commenters 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 fact that the maximum amount of 

re-dispatch that could be supported by the system operated by the RTO would be accomplished. 

Commenters 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. Commenters 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.

Commenters 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. Commenters added that, as noted, the EPA should strive to 

create state flexibility that promotes early achievement of emission reductions. Further, 
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commenters suggested that, to address concerns about costs for electricity customers, the carbon 

adder could be collected by the market operators and then used to offset increased costs to 

customers, ensuring that electricity remains affordable for end-users.

Commenters suggested that, to support the potential use of this option to define state glide paths, 

the final guidelines should recognize the value of using existing market dispatch structures to 

achieve emission reductions and specifically note that states could pursue this option as part of 

an approvable plan. Further, commenters suggested that the final guidelines could include a 

carbon adder value for states to require affected units to use when bidding into competitive 

markets.

Comment 13: Glide path flexibility should also be applied to other methods of compliance (i.e., 

should be available for electric infrastructure development, should not be limited to coal to gas 

re-dispatch).

Response 13: The EPA thanks the commenters. The EPA has provided a glide path in setting the 

state goals for the interim period and increased 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, 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, 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 infrastructure development in the NODA for Building Block two, expressed that such 

"glide path" flexibility should also be applied to electric infrastructure needs.

Commenters requested that the EPA apply the "glide path" flexibility proposed in the NODA to 

address gas pipeline and transmission 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 the timing of necessary electric 

infrastructure development.

Specifically, commenters 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. Commenters 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 needs that require flexibility in the overall 
517

compliance strategy set forth in the State Plan, without jeopardizing the 2030 compliance 

deadline.

Commenters explained that, while entities affected by the final rule have greater ability to 

develop electric infrastructure 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 constraints and/or 

delays, right of way processes, and other technical and/or legal issues. In particular, commenters

reported that, while the responsibility for assessing electric infrastructure needs and identifying 

related projects lies with certain reliability 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 

for applicable regulations). Further, according to commenters, where projects involve regional 

electric systems, such coordination can involve multiple state agencies. Commenters 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 the scope of the additional flexibility contemplated in the NODA. 

More simply put, commenters stated where such issues justify flexibility for gas infrastructure 

development, they should also justify flexibility for electric infrastructure development involving 

each of the building blocks and their interaction under a State Plan. Further, commenters

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. Commenters asserted that this further supports 

the inclusion of electric infrastructure development with gas infrastructure development in the 

scope of the additional flexibility contemplated in the NODA.

Commenters requested that the final rule provide that, where a demonstrated reliability issue 

would result without construction of necessary electric 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 goal is met and affirmative steps are being taken during the compliance 

period. Commenters 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 to 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 commenters 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 commenters, the NODA flexibility, even if expanded to 

electric infrastructure, may not address every situation that could arise during implementation of 

State Plans that may negatively impact grid reliability.
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Commenters expressed that additional electric infrastructure needs will not be known until State 

Plans are developed and evaluated; however, it is anticipated, in both the Proposed Rule and the 

NODA, that there will be substantial modifications to the overall generation resource mix during 

the compliance period. According to commenters, this is significant because the current electric 

infrastructure has been built and maintained to serve existing load from existing generation 

resources. As the generation portfolio changes, in terms of Megawatt output or geographical and 

electrical locations, commenters asserted that it is likely that the electric infrastructure necessary 

to support such shift will need evaluation and upgrading or additions. Hence, commenters

believed that, as State Plans contemplate meeting CO2 reduction goals through means that 

impact the generation portfolio - e.g., shifts to significantly higher utilizations 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, 

commenters reiterated their recommendation that 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 glide path associated with re-dispatching existing resources to less CO2 intensive 

resources under Building Block two. Commenters 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 building blocks in a state plan); and (3) the State Plan 

still contemplates meeting the 2030 compliance deadline.

Commenters asserted that, as delays in the siting and construction of electric transmission 

infrastructure could impact achievement of compliance through 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 increased 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, commenters

asserted 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. 

Commenters reported that detailing of this RSV-style flexibility (and the evidentiary 

requirements surrounding same) would provide welcome certainty 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 alternative glide path options and recommended 

changes (e.g., defined exceptions, allowance for states to depart from strict averaging of 

emissions, Building Block 2 calculation changes) to the glide path.
519

Response 14: The EPA thanks the commenters, 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 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. See sections V.D, VIII.A, 

VIII.C and VIII.G of the final rule preamble of the CPP and Chapter 3 of the GHG Mitigation 

Measures TSD for the CPP Final Rule supporting the final CPP.

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

Several commenters suggested alternative glide path options or recommended changes to EPA's 

proposed glide path option.

Linear Glide Path

As an alternative "glide path" option, commenters 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 Block 4. Commenters included 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

Commenters asserted that, on a regional approach, the "glide path" may be achievable. However, 

according to commenters, there is little flexibility in the rule for specific conditions arising either 

at the outset or during the 2020-2029 compliance period. Commenters 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 initial 10-year "glide-path." Commenters

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 taken 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 requirement 
520

during the interim compliance period such as additions of new electricity transmission or natural 

gas pipeline infrastructure. 

According to commenters, 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. Commenters 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. Commenters 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 entity 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

Commenters stated that, as much as the shift EPA has proposed as a part of Building Block 2 is 

about increasing NGCC utilization, it is also about decreasing steam generation and replacing the 

services that steam capacity currently provides to the grid. Accordingly, the commenters

recommended the following two adjustments to EPA's Building Block 2 calculation:

(1) Commenters recommended that, in developing the proposed state targets, the EPA assume a 

ramping to a 70 percent NGCC fleet capacity factor in order to provide states with additional 

flexibility to make sure the infrastructure necessary to support this level of utilization is in place 

or to increase the use of other compliance strategies.

(2) Commenters recommended that 2012 generation from oil/gas steam units be excluded from 

the goal computation.

To address the "front-loading" issue, the commenters 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 commenters reported that the natural gas prices were relatively low, so NGCC 

utilization rates were relatively high.) According to the commenters, the EPA could take a range 

of approaches to introducing NGCC to the goal setting equation. Commenters 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 commenters suggested that EPA could consider reaching the 70 percent level 

in 2025. Commenters suggested that EPA arrive at a ramping rate that considers the potential 

system constraints described above.

With regards to the commenters’ second recommended change, oil/gas steam units serve a 

different segment of the dispatch curve and are often used as a backup to coal and natural gas 

base load generating facilities. In 2012, the commenters reported that NGCC capacity factors 

increased significantly and coal steam utilization rates declined. However, the commenters

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 do not 
521

correlate with NGCC capacity factors. According to the commenters, by including these units in 

the goal computation, EPA is setting standards that, in some cases, assume these units are 

interchangeable.

To implement this change, the commenters stated 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 commenters, this would avoid situations where the re-dispatch of 

NGCC capacity would effectively 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.

Commenters recommended a few targeted changes to the Building Block 2 calculation that, 

according to the commenters: (1) would not threaten electric reliability; (2) would still result in 

substantial reductions in carbon emissions both in Arizona and nationwide; and (3) would be 

substantially more cost-effective and attuned to the statutorily-mandated "remaining useful life"

concept. The commenters’ 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 to 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 installation 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 Regulatory 

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 implementation 

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 prior to January 1, 2030 remain coalfired EGUs for purposes of calculating the interim and final goals. 

The commenters believed that their proposal is consistent with concepts introduced in the 

NODA, and would provide significant and much-needed relief to states that would be overly 

burdened by Building Block 2, with minimal impacts to the overall emissions intensity 

reductions EPA will achieve with its Proposed Rule. According to the commenters, not only 

would their proposal accommodate proper consideration of remaining useful life in setting 
522

performance standards for existing sources, but it would ultimately rectify a basic equity issue 

that they believe is associated with the currently proposed state goals.

Commenters provided a figure to illustrate that the impact of the changes they proposed would 

be minimal nationwide and that only a handful of states would be significantly and 

disproportionately impacted by Building Block 2 would be affected by their proposed changes.

Commenters supported the Clean Energy 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 commenters noted that the 

following three recommendations are made as a package, and are not meant to be taken 

separately.

• First, the commenters 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 utilization is in place or to increase the use of other 

compliance strategies. 

• Second, the commenters 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 the 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 commenters -- recommended that EPA retain 10% to 12% of coal 

steam MWhs in the state goal computation. 

The commenters further stated that other stakeholders have suggested a higher capacity factor 

and suggested that EPA evaluate the viability of a higher capacity factor for states with an 

increased penetration of natural gas and zero-emission resources as a lower target may, in fact, 

be appropriate.

Milestone Approach

Commenters favored a milestone approach for measuring progress during the years preceding the 

2030 goal. Commenters 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). Commenters further stated that it would give states greater flexibility in meeting 

their final goals and would create meaningful targets that take into account planned retirements 

of coal-fired EGUs. According to the commenters, a milestone approach based on the IRP 

process would involve measured decision-making taking into account various stakeholder 

interests, including inter alia individual states, tribes, utilities, and ratepayers. Commenters

opined that such a process is more likely to result in targets that address stakeholder concerns, 

such as infrastructure improvements, stranded 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

Commenters stated that the EPA should strengthen rather than weaken the compliance trajectory 

or "glide path" of emission reductions. Commenters believed that, assuming that a life-cycle 

analysis shows that natural gas plants do outperform coal-fired plants, Block 2 should create a 

dispatch hierarchy that favors the least-emitting sources (rather than NGCCs only) whenever 

possible. Commenters 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. Commenters asserted that the targets for RE and EE should be 

steeply increased while their phase-in time is shortened, decreasing the frequency of dispatch to 

NGCCs. Commenters added that these measures should make the EPA's concerns about any 

potential infeasibility of higher NGCC utilization rates unnecessary.

Commenters also noted that the EPA's concerns about the effects of the Proposed Rule on states 

that currently lack sufficient NGCC capacity to meet the Block 2 target is focused solely on 

whether those states can or should build additional NGCCs. According to the commenters, a 

least-emissions dispatch approach diminishes or avoids that concern as it will incentivize the 

construction of new renewable generation over new fossil-fuel generation. Commenters pointed 

out that the EPA has already set extremely low targets for those states that have both few 

renewable energy resources 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.

Commenters concluded that stakeholder fears that some coal-fired plants may have to stop 

operating by 2020 even though they have made significant capital investments are not legitimate 

reasons to re-design the Proposed Rule. According to the commenters, section 111 is concerned 

with exorbitant costs to the industry, not to a few individual facilities, 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 not support the concept of a glide path.

Response 15: The EPA thanks the commenters. In response to additional analysis and many 

comments, we have modified the proposal and RIA. The EPA would agree with the commenters

that further introduction of a glide path is not necessary if the commenters 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 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 the “useful life” of assets. See sections V.D, VIII.A, VIII.C and VIII.G of the 
524

final rule preamble of the CPP and Chapter 3 of the GHG Mitigation Measures TSD for the CPP 

Final Rule supporting the final CPP.

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

Commenters expressed that, for states like North Carolina that have already achieved high heat 

rate improvements (HRI), there exists little to no room for further HRI in the next few years. 

Commenters reported that the North Carolina Department of Environment and Natural 

Resources (NCDENR) does not support the concept of a glide path, and believes that a state 

should not be denied the right to meet the final goal through infrastructure changes such as 

extending the life of a nuclear plant or conversion from coal to gas late in the 2020-2029 

performance period (were those mechanisms found to be legally authorized). 

Comment 16: Commenters requested that the EPA delay the compliance deadline.

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 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, 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:

Commenters specifically requested that EPA consider delaying the compliance deadline for the 

rule.

Commenters requested that EPA consider a glide path approach that would include eliminating 

the interim goals from the final rule (discussed in another comment summary) and/or delaying 

the compliance deadline by five years from 2030 to 2035. Commenters stated that under the 

proposed rule, significant carbon reductions (80 % of the final compliance requirements) would 

be needed by 2020 in order to meet the 2020/2029 interim goals. Commenters stated 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 commenters reported that a five year delay shifts approximately $1.1 

B of $2.9 billion impacts to later years. Also, according to the commenters, operating Nelson 6 

and ISES-2 for an additional five years would bring these plants right up to the point when 
525

significant 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.

Commenters 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. Commenters 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 consumers.

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. Responses are provided for these topics.

Comment 1: Commenters stated the EPA should amend the final rule to prioritize and drive 

permanent retirements from high-intensity sources.

Response 1: The EPA thanks the commenters. 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 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 infrastructure, and the “useful life” of assets. With attention to reliability, the emission 

performance rates reflect not maximum stringency, but reasonable 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, commenters

suggested the EPA finalize the CPP to prioritize and encourage permanent retirement of the 

oldest and highest-intensity sources of carbon pollution. Commenters 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. Commenters provided modeling analysis to 
526

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. Commenters stated that, only by doing so, can the EPA drive the kind of carbon 

emission reductions necessary to meaningfully impact the spiraling costs of climate change.

Commenters stated they used a modeling tool developed by Synapse Economics and ran multiple 

scenarios assuming that certain coal-burning EGU that will turn 50 years old during the 

compliance period actually retires on that date. Commenters 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. Commenters 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. Commenters 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. Commenters 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, incorporated building block 1 and 1, but only included retirements that 

are planned or required. 

Commenters 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 EPA's carbon emission 

targets relatively easily. Commenters stated that, as a result, the CPP does little to encourage or 

compel any permanent retirement of coal-burning electric generation units, despite the fact that 

these units are at the end of their useful life. Commenters stated the most direct and straightforward 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 energy, energy efficiency, or already-planned natural gas generation. Commenters

noted that by simply retiring each of these 50-year-old units, Texas could reduce its overall 

emissions by some 76,874,904 tons--a reduction of more than 29% from 2012 levels. 

Comment 2: Commenters 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 adjusting 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 commenters. The EPA requires states to develop plans that 

achieve the goals of the 111(d) final rule. 

The following are summaries of the specific public comments under this comment:
527

Commenters 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 higher 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 commenters. 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. 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.

Comment 4: Commenters 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 commenters. 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. 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 Final Rule supporting the final CPP

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

1. In 2012, the Natural Gas Combined Cycle (NGCC) fleet capacity factor was 44-46%. 

How did the EPA determine that 70% utilization was BSER?
528

2. What 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 peerreviewed 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 did 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 EPA 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 consequently 

unavailable for re-dispatch within a state)?

Commenters stated that (1) the EPA proposal entails significant fuel switching from coal to 

natural gas, (2) most retiring coal plants cannot 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. Commenters asked the following questions:

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 be 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 flexibility 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, 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 noted that West Virginia has significant natural gas resources in the Marcellus 

Shale, and indicated that developing West Virginia's natural gas resources and investing in 

natural gas-based electricity generation will help the state comply with the Clean Power Plan and 

grow the state's energy economy. Commenters stated that the construction of new NGCC plants, 

co-firing existing coal plants with natural gas, 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.

Commenters stated that despite the benefits of integrating natural gas into state's electric power 

sector, combined with the increasingly high cost of coal-fired generation, West Virginia's rateregulated 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, commenters 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 same 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). Commenters stated that although these recent acquisitions by West Virginia 

utilities 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 

commenters, 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. Commenters noted that this additional capacity would stimulate additional demand for 

West Virginia natural gas, provide much needed resource diversity, and reduce the emission 

intensity of the state's power sector.

Comment 6: Commenters expressed the view that a carbon emission regulation that targets coalbased 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) 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 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:

Commenters 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. Commenters stated the EPA's proposed rule creates powerful 

incentives for coal plants to retrofit with natural gas turbines - a far less universally available fuel 

(at present) with far greater price volatility. Commenters expressed appreciation that the 

emissions targets under the rule allow for many paths to compliance, but expressed the opinion 

that there is an effectively unequal treatment of coal. Commenters 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 commenters 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:

Commenters stated that the transition to cleaner energy has been underway for decades. 

Commenters 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 coal burning, be 

measured, reported and included in the state goal. Citing the EPA's estimates of the health 

benefits of the proposed rule, commenters expressed support for the proposed EPA emission 

reduction guidelines in order to accelerate the pace of improvement and put targets in place that 

will promote continuous and measurable caps on carbon pollution.

Comment 8: Commenters 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 commenters. 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 achieve 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 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 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:

Commenters 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 serve their customers. 

Commenters described specific needs in the state of Minnesota, such as serving metro daily 

generation peaks with volt swings and intermittent generation support to compensate for wind 

power down times.

Comment 9: Commenters provided a range of comments on the use of the term "redispatch."

Response 9: EPA agrees with those commenters that recognize 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 generation 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 compatibility between environmental 

regulation and economic dispatch. This final rule reinforces that approach by making clear that 

the concept of emissions rate trading is part of the BSER process and can be implemented 

consistently with the building blocks 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 normally, the term "dispatch" is used to define the order in which 

particular generating plants are lined up to feed electricity into the grid. The commenters 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 commenters stated that the dispatch line-up works differently 

in competitive markets, where generation has been deregulated 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 commenters 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 technical reasons not to do so. 

The commenters 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 commenters stated that of course, an increase 

in renewable energy, nuclear energy, hydropower, solar energy, and other generation can also 

replace fossil energy. The commenters stated that however the EPA chose not 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 fuelfired generation and thereby avoids the CO2 emissions from that replaced generation." 

The commenters stated the 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 commenters 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 the term "shifting 

generation away from fossil units" used in the NODA, as noted above, is equivalent. 

Commenters stated the CPP is not in synch with the priorities and operations of regional electric 

grids. Commenters said that Ohio's utilities are part of the 13-state PJM independent system 

operator (ISO). Commenters said that PJM dispatches power based on price, with lowest cost 

generators used first, higher-cost generators used next. Commenters said that this is a sensible 

approach and in the future, if a singular fuel is mandated 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 that 
533

businesses' long-term investment decisions 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 deliberate 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, bidbased 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 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 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 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 Energy & 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%27sproposed-clean-power-plan-and-other-grid ("Moeller Testimony”).] Commenters stated that 

switching to "environmental dispatch" would result in a system in which "units will be called to 

generate primarily based upon the emission profile of the unit." Commenters stated that 

Commissioner Moeller has also informed Congress 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 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) (Answers to Preliminary Questions for the FERC, Philip D. Moeller, Comm'r, FERC), 

available at http://energycommerce.house.gov/hearing/ferc-perspectives-questions-concerningepa%27s-proposed-clean-power-plan-and-other-grid ("Moeller Responses")].

Commenters stated that it is, at best, disingenuous for the Proposed Guidelines to emphasize that 

ISOs and RTOs' existing economic dispatch rules have accommodated existing environmental 

rules on a plant-specific basis, e.g., by permitting sellers to incorporate environmental costs into 
534

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 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 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 beyond 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), available at 

http://energycommerce.house.gov/hearing/ferc-perspectives-questions-concerning-epa%27sproposed-clean-power-plan-and-other-grid ("Clark Responses")].

Commenters raised questions regarding increased natural gas prices that prevent profitable 

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 reliability 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. Ins. 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 States, 371 U.S. 156, 168 (1962)).

Commenters stated that all ISOs and RTOs use a form of regional, security-constrained, bidbased economic dispatch; commenters stated these 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 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 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 an 
535

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).] Commenters 

stated that switching to "environmental dispatch" would result in a system in which "units will be 

called to generate primarily based upon the emission profile of the unit." Commenters stated that 

Commissioner Moeller has also informed Congress 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 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) (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 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 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 beyond 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' statements that the EPA's proposal 

would involve a fundamental shift from an economic dispatch system to an environmental 

dispatch system that would engender considerable 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 

ensured 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 their 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 FERC-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 Commission, House Energy and 

Commerce Committee, Subcommittee on Energy & Power (July 29, 2014)]. 

Commenters stated that although EPA professes that any additional regional coordination under 

the Proposed Guidelines would be voluntary, it 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) 

("Initial 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 dispatch, 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 cost 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 providing 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 individual 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 extremely 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 by the proposal. Commenters said the first 

is the set of issues created when a state is served by more than one RTO/ISO, or even an 

RTO/ISO and non-RTO/ISO vertically-integrated 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. Commenters said at the very least, states might insist on a certain dispatch order within 

the state to be conducted by the RTO so that the state ensures that it can meet its obligations at 

the lowest possible cost. That leads to the question of whether and how RTOs 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 have 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-bystate 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 negotiate 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 stated 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 and 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 Transmission 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 enforcement.
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 this 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 place 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" because 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, including 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 dispatch 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 FERCjurisdictional 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 source 

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 redispatch 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 or 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 the 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 they 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 from 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. 

Commenters 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 may 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 multi-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 environmental dispatch, according to Hogan, "market structures 
540

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 

temptations 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 as 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 FTRs 

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 losers 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 NGCC plant owners to operate their plants at 

higher capacity factors? 

• Will NGCC owners demand higher payments to account for increased wear and 

tear? 

• And what about cases (described above) where there is no NGCC generation to 

turn to. 

• Who has the responsibility for ensuring gas supply so that the NGCC plants can 

increase their capacity factors? 
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 

their 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 signal 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 emission 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 longer 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 while 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 Proposed 

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 scrutiny 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 place 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 review.