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TABLE OF CONTENTS

CHAPTER 3 GHG MITIGATION MEASURES...................................................................... 2

3.1 Heat Rate Improvement at Existing Coal-fired EGUs (Building Block 1)........................ 2

3.1.1 Factors that Impact Heat Rate of Coal-Fired EGUs........................................................ 3

3.1.2 Technologies to improve existing coal-fired EGU heat rate .......................................... 30

3.1.3 Previous studies on heat rate improvement..................................................................... 78

3.1.4 EPA's heat rate improvement assessment..................................................................... 110

3.1.5 Heat rate improvement - economics............................................................................... 476

3.1.6 Miscellaneous Issues about Heat Rate Improvement at Existing Coal-fired EGUs.. 517
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CHAPTER 3 GHG MITIGATION MEASURES

This chapter addresses comments received on the EPA’s proposed GHG mitigation measures, or 

"building blocks." These proposed building blocks included: heat rate improvement at existing 

coal-fired EGUs (Section 3.1); generation shift (Section 3.2); cleaner generation sources (Section 

3.3); and demand-side energy efficiency (Section 3.4). Comments received on the following 

additional topics are also covered by this chapter: the alternative renewable energy approach 

(Section 3.5), the interaction of building blocks (Section 3.6), fuel switching (Section 3.7), 

carbon capture and storage (Section 3.8), new NGCC capacity (Section 3.9), heat rate 

improvement opportunities at other EGU types (Section 3.10), potential emission reduction 

measures not used to set proposed goals (Section 3.11), and comments received on other topics 

relevant to this chapter (Section 3.12). 

Commenters also raised issues on topics that are not covered by this chapter. Please refer to the 

following chapters for responses specific to those issues:

• Chapter 1: Legal

• Chapter 2: Applicability

• Chapter 4: State Goal Computation

• Chapter 5: State Plan Considerations

• Chapter 6: State Plans

• Chapter 7: Interactions With Other EPA Programs and Rules

• Chapter 8: Impacts and Cost Analysis

• Chapter 9: Statutory and Executive Orders

• Chapter 10: Rule Language Corrections

3.1 HEAT RATE IMPROVEMENT AT EXISTING COAL-FIRED EGUS (BUILDING

BLOCK 1)

This section addresses comments on Heat Rate Improvement at Existing Coal-fired EGUs 

(Building Block 1). Topics covered by this section include operating practices that influence 

efficiency, technologies to improve efficiency, previous studies estimating potential efficiency 

improvements, the proposed EPA approach to calculate efficiency improvements, and the 

estimated capital costs of those improvements.
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We have organized the comments in this section under six subsections, 3.1.1 to 3.1.6. Responses 

to the comment topics of these subsections are discussed below along with summaries the 

specific public comments.

We received a number of comments with suggestions for other rule formats and suggestions for 

exemptions and exceptions to the rule. As noted below, many of these suggestions can be 

accommodated in most cases as a result of the flexibility for states and EGUs afforded by the 

rule. 

3.1.1 Factors that Impact Heat Rate of Coal-Fired EGUs

This subsection discusses a variety of factors that commenters believed should be considered

when comparing the effectiveness of heat rate improvement technologies to increase the 

efficiency of a given coal-fired EGU.

Commenters have raised a number of issues related to this subsection which are organized by 

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

Comment 1: General or summary comments regarding factors affecting EGU efficiency, such as 

unit size, boiler type and siting, fuel type, full or reduced load, parasitic load from control 

technology, implementation of best available technologies 

Response 1: The response to these comments are addressed in section 3.1.4.

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

Commenters stated that power plants are designed for an optimal heat rate. Commenters stated

that while that heat rate may not be the lowest achievable at any given point in time, trade-offs 

occur with respect to capital and O&M costs, siting, and fuel. Commenters stated the average age 

of operating coal-fired power plants is 40 years. Commenters stated that over the course of the 

past four decades, these plants have been subject to physical modifications and repairs and 

suffered age-related degradation. Commenters stated that many of the modifications have been 

the addition of emissions controls, which typically have an adverse effect on heat rate. 

Commenters stated that since initial startup, many units have changed fuel supply and reduced 

staffing size, increasing operational challenges which create additional potential adverse heat rate 

effects. 

Commenters stated that achievable heat rate depends highly on the type and site of boiler and the

type of fuel and, in general, units can be categorized by boiler type (supercritical or subcritical), 

fuel type (lignite/subbituminous or bituminous), and nameplate unit size (large, medium, or 

small unit). Commenters stated that each of these categories within the electric cooperative coalfired fleet was explored to understand the impact on baseline CO2 emissions.
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Commenters stated that the units with the lowest CO2 emissions are the large supercritical units, 

which have the fewest opportunities to lower the plant heat rate. Commenters stated that 

supercritical units have a slight advantage in CO2 emissions, due to operating at higher load 

points throughout the year and overall more efficient cycle and it was expected that 

subbituminous and lignite fuels would have a higher CO2 emission rate, due to the lower boiler 

efficiency and higher auxiliary power consumption in comparison with bituminous fuel. 

Commenters stated that however, this was not noticed, potentially due to most bituminous coal 

units being equipped with wet FGDs and SCRs. Commenters stated that among the their fleet, 

there are no conclusions that can be drawn based on the fuel type, due potentially to the heat rate 

effects of other factors such as installation of AQCS equipment or plant locations.

Commenters stated that EPA must allow flexibility for existing coal fired units to operate at full

load in the State plans. Commenters stated that they have documented evidence that heat rate, 

and therefore GHG emissions, can increase by more than ten percent when their units are

operated below their designed full load capacity. Commenters stated that any State plans that are 

created in a way that requires coal fired units to operate at lower than the design capacity will 

result in higher GHG emissions per MWh produced by those units, than if the units operate at the 

full load efficiency they were designed to achieve. 

Commenters stated that EPA has assumed that coal-fired EGU's can reduce the amount of heat

required to generate electricity by 6% by 2030 through improved operation and equipment

upgrades, which would result in an equivalent reduction in carbon dioxide (CO2) emissions per 

megawatt hour of generation. Commenters stated that these assumptions reflect EPA's 

assessment of what each EGU is capable of achieving based on a review of emissions over the 

past eleven years.

Commenters stated that EPA should instead base this Building Block on heat and emission rates 

that the best performing coal-fired EGU's have already achieved. Commenters stated that for 

example, EIP obtained average annual heat rates and CO2 emission rates for 2009 through 2013 

from the Clean Air Markets data based 601 coal-fired EGU's with a capacity factor of at least 

30%. Commenters stated that twenty percent of the units with the lowest heat rates averaged 9.65 

MMbtu per net megawatt hour over the five year period, compared to the 10.69 MMBtu/MWh 

five year average for all units in the study group. Commenters stated that the top quintile also 

released an average of 1,997 CO2 pounds per net megawatt hour of electricity generated, about 

10 % lower than the five year annual average of 2,200 CO2 pounds per net megawatt hour for all 

units in the study.

Commenters stated that Building Block 1 should assume that by 2030, coal-fired EGU's could 

achieve the same emission rates that have already been realized by the best performing twenty 

percent of this sector today. Commenters stated that this approach assumes a ten percent 

improvement in industry-wide emission rates for coal-fired EGU's, and by 2030 would reduce 

CO2 emissions by an estimated 136 million tons per year, or by 41 million tons more than the 

Proposal.

Commenters listed several reasons why this projection is both reasonable and legally defensible:
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1. Commenters stated that the National Energy Technologies Laboratory (NETL) has 

already indicated that coal-fired power plants can achieve efficiency improvements in the 

range of 9% to 15%. 

2. Commenters stated that based on their analysis, the lowest emitting plants were not 

distinguished by age, boiler type, or capacity factors, suggesting that these variables are 

not major obstacles to improving efficiency at coal fired EGU's and that those findings 

are consistent with the NETL analysis. 

3. Commenters stated that state wide emission rates would be adjusted based on the revised 

assumption that coal-fired EGU's by 2030 will reduce their emission rates to levels 

already achieved by the best performers between 2009 and 2013. Commenters stated that 

States would retain the flexibility to meet their goals in the most cost-effective way 

possible.

4. Commenters stated that power companies are accelerating the retirement of some of the 

least efficient coal plants, which should make the targets easier to meet.

5. Commenters stated that the Commenter's proposal is based on long-term emission rates 

averaged over five years. Commenters stated that EPA has determined in New Source 

Review rules that five years is lengthy enough to accommodate any variations that may 

result from the normal "business cycle" for power plants.

6. Commenters stated that courts have made clear that industry wide standards under 111(d) 

of the Clean Air Act can look forward, i.e., EPA is not limited to setting limits based on 

what each plant within an industry sector has already achieved in practice. Commenters 

stated that the standards in this case would not take full effect for more than fifteen years, 

giving coal plants plenty of time to improve operation or upgrade equipment.

Commenters urged EPA to require that generating units upgrade to the best available

technologies for efficient operation. Commenters stated that this usually means upgrades to the 

plants controls and electro-mechanical auxiliary systems, as well as to the basic steam-water 

cycle equipment itself. 

Miscellaneous comments regarding EGU efficiency

Commenters stated that the Proposed Rule would penalize affected sources for continuing to

improve air quality independent of CO2 regulation. Commenters stated that the use of net 

generation does not adequately account for the parasitic load resulting from the installation and 

operation of pollution control equipment that is necessary to meet other Clear Air Act 

requirements and EPA regulations, such as Regional Haze. Commenters stated that for example, 

a unit that can produce a maximum generation capacity of 500 MW may be required to install 

selective catalytic reduction to reduce NOx emissions, which reduces the maximum capacity by 

5 MW and that the unit is now only capable of generating 495 MW at the maximum heat input. 

Commenters stated that in order to maintain the same CO2 emission rate, in pounds of CO2 per 

MWh, the unit will likely have to reduce the heat input to offset the capacity reduction of 5 MW. 

Commenters stated that the PSC commented further on this paradox that results in generating 

more CO2 emissions per MW because units may be required to run less efficiently at reduced 
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heat rates (PSC Letter). Commenters stated that additionally, other Federal Subparts like 40 CFR 

60 Subparts IIII, JJJJ, and KKKK already set emission limits and standards based on capacity 

and gross output. Commenters stated that EPA must maintain consistency with regulations that 

are already in place and not punish affected sources for other improvements to air quality.

Commenters stated that in 2008, the U.S. coal-fired power plant (CFPP) fleet had a generationweighted average efficiency of 32.5% while the top ten percent of the fleet had an efficiency of 

37.6%, five percentage points higher. Commenters stated that the generating units in the top ten 

percent are diverse (they are not all new, large, super critical plants), indicating an opportunity 

for fleet-wide efficiency improvement. Commenters stated that the National Energy Technology 

Laboratory (NETL) segmented the fleet into 13 groups based on characteristics that limit 

efficiency, and calculated the best-in-class efficiency within each group. Commenters stated that 

based on each group achieving an average efficiency equal to its 90th percentile, the overall 

CFPP fleet average efficiency would be 35.2%. Commenters stated that NETL sets forth a vision 

of 36% based on retirements of low efficiency units, and improvements within the best-in-class. 

Commenters stated that under a scenario where generation from coal is constant at the 2008 

level, increasing the average efficiency from 32.5% to 36% reduces U.S. GHG by 175 

MMmt/year or 2.5% of total U.S. GHG emissions in 2008. 

Commenters stated that technical heat rate improvements would not achieve their intended

emission reduction effects if the EGUs were operated inefficiently to address grid reliability and 

integration needs. Commenters stated that a specific BSER requirement to evaluate and address 

integration and reliability issues without operating EGUs in an inefficient manner is essential to 

capturing the potential emissions benefit of technical heat rate improvements at EGUs. 

Commenters noted that the retirement of aging, less efficient coal-fired plants alone would

reduce coal plant emissions during the rulemaking period

Commenters were concerned that the standards set for coal and the requirement for carbon

capture and utilization and storage (CCUS) will stop the development of cleaner coal 

technologies and that the proposed rule for existing sources offers so little potential for real coal 

efficiency improvements that it doubles down on EPA's misguided carbon path. Commenters 

stated that if the United States fails to develop incentives and opportunities to invest and deploy 

advanced supercritical and ultra-super critical plants, and continue research into next-generation 

coal technologies including CCUS, it would cede technology leadership to others and forego 

valuable innovation and job opportunities. 

Comment 2: Comments regarding the effect of existing state-level CO2 reduction programs on

heat rate

Response 2: We thank the commenters for this information. We agree that regulations can

motivate or incentivize heat rate improvements.

The following are summaries of the specific public comments under this comment:
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Commenters stated that Electricity generators in their states have already demonstrated that it is

possible to employ best operating practices and upgrade equipment to improve the efficiency of 

fossil fuel-fired electric generating units (EGUs) and reduce emissions. Commenters stated that 

such improvements have been driven by a number of state policies, including the Regional 

Greenhouse Gas Initiative (RGGI). Commenters stated that independent analysis has shown that 

coal-fired EGUs have historically been capable of making improvements in heat rate to respond 

to increases in operating costs (i.e., increases in the cost of fuel). Commenters stated that in 

RGGI, the requirement for units to hold allowances for each ton of CO2 emitted creates a similar 

financial incentive for units subject to the program to improve their efficiency, and some coalfired power plants in the region have performed such upgrades in recent years. Commenters 

stated that for example, the Public Service Company of New Hampshire upgraded a coal-fired 

unit at Merrimack Station by installing new energy-efficient turbine; the upgrade is estimated to 

avoid up to 150,000 tons of CO2 emissions per year. Commenters also stated that in another 

example, Minnesota's Metro Emission Reduction Project encourages utilities to make voluntary 

emissions reductions at qualifying units. Commenters stated that Xcel Energy completed a 

project under this program from 2007 to 2009 that included reducing carbon emissions from 

three Twin Cities-area power projects by 21 percent. Commenters stated that at one facility, 

reductions were achieved through rehabilitation of an existing coal unit with a new turbine, 

upgraded steam generator, and improved emissions control equipment.

Comment 3: Comments regarding efficiency gains from changes in dispatch order or carbon

intensity of fuel

Response 3: See sections V.A, V.C, and VIII of the final rule preamble of the CPP for the

EPA’s response to this comment. As discussed in those documents, the CO2 emission 

performance rate for fossil fuel-fired electric utility generating units does not itself require EGUs 

to reduce emissions by improving heat rate. Furthermore, the EPA’s assessment of potential heat 

rate is an average measure that is not intended to define the minimum (or maximum) that any 

individual EGU is capable of achieving. Finally, states have considerable flexibility to develop 

plans that meet the requirements of the emission guidelines and fully implement the BSER for 

the affected EGUs in each state.

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

Commenters suggested that additional emission reductions could be achieved by switching the

deployment order of units at a plant based on efficiency and/or carbon intensity of the fuel 

deployed. Commenters encouraged EPA to evaluate the opportunities for such reductions in the 

final rule. 

Comment 4: Comments regarding coal rank and quality

Response 4: We agree with the commenters that fuel choice is dictated by numerous variables,

including price, availability, boiler design and environmental controls, and we understand that 

fuel use can affect heat rate. However, this rule does not require individual EGUs to change fuels 
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as a means of improving heat rate. For the EPA’s response to the remainder of these comments, 

see section V.C of the final rule preamble of the CPP and Chapter 2 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 coal switching for heat rate improvement - although theoretically

possible - is an unlikely commercial option. Commenters stated that it is important to emphasize 

that fuel choice is dictated by numerous variables (e.g., price, availability, boiler design and 

environmental controls) so changing coal rank is likely not practical at many units.

Commenters also stated that in addition, many coal-fired generating units operate under consent 

decrees that mandate SO2 emission rates reflecting whatever coal the unit was firing at the time 

it agreed to the consent decree. Commenters stated that such units may be effectively precluded 

from changing that coal quality in any substantial way.

Commenters stated that treating coal to improve performance and emissions, via prior-tocombustion technologies such as wet coal cleaning to reduce ash; dry coal upgrading to increase 

BTU content; and the use of microbial agents as additives, is a focus of their Coal 2.0 Alliance 

Committee. Commenters stated that efficiency gains from cleaning and drying, especially lower 

rank coals, have been documented in EPRI reports and in operation and that cleaning also 

reduces the amount of impurities such as sulfur and mercury that enter the combustion chamber 

which results in overall fewer emissions to deal with downstream. Commenters stated that the 

propensity to use such coal technologies and treatments is highly dependent on the associated 

costs as well as the operating characteristics and location of the individual power generation unit, 

among other factors. 

Commenters stated that EPA's Block 1 approach fails to consider the efficiency reductions

resulting from switching to low-sulfur coals. Commenters stated that the efficiency of a coalfired EGU can be significantly decreased by switching from higher quality bituminous coals to 

low-sulfur subbituminous coals, such as those from the Powder River Basin (PRB) and that these 

reductions in generating efficiencies cannot be totally addressed by improved operation and 

maintenance (O&M) practices.

Commenters stated that this concern, which is not addressed by EPA in the Proposed Rule, is a 

major concern for their members. Commenters stated that for example, one of their members has 

a long history of utilizing a wide variety of coals in its power plants and most of the their coalfueled units were designed to burn higher quality bituminous coals, and as the EPA points out, 

EGUs burning these coals "tend to be more efficient than EGUs burning lower quality coals with 

higher moisture contents." Commenters stated that while there are efficiency advantages to 

burning design coal, many electric utilities have switched to PRB and other low-sulfur, high 

moisture coals as a technique for controlling emissions from their units.

Commenters stated that this is the case for one of their members. Commenters stated that all of 

their coal-fueled units (except those at Belle River Power Plant) were designed to burn higher 

sulfur eastern coals. Commenters stated that as environmental constraints tightened, switching to 

lower sulfur western PRB coals blends became an economical means of controlling sulfur 

dioxide (SO2) and these PRB coals also produce lower nitrogen oxide (NOx) emissions 
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compared to the eastern coals. Commenters stated that in addition to these environmental 

benefits, utilizing eastern-western blends provides substantial cost benefits for their customers.

Commenters stated that PRB coals are generally more economical than eastern coals in terms of 

cost per BTU and for example, their delivered price for PRB (dollars per MBTU) is typically 

20%-30% lower than eastern coals. Commenters stated that this price advantage more than 

overcomes the heat rate penalty associated with the combustion of PRB coals. Commenters 

stated that operating constraints can limit the PRB percentage to a unit, or the unit may burn 

higher percentages of PRB at reduced capacity. Commenters stated that as they have gained 

experience in the utilization of PRB, they have been able to mitigate these constraints to the 

point where all of or units are now capable of burning 100% PRB for the benefit of its 

customers.

Commenters stated that in addition to overcoming the technical challenges of burning the more 

economical PRB blends, they have developed processes to dynamically blend its units to 

maximize value to its customers. Commenters stated that the plants work with their Generation 

Optimization to monitor market conditions and adjust fuel blends to create the most value for 

customers in the wholesale electricity market and typically, lower market pricing results in 

higher PRB blends. Commenters stated that while this flexibility drives customer value, the 

higher PRB blends will drive increases in unit heat rate through the following impacts:

• Commenters stated that the physical properties of higher PRB blend result in 

higher heat rates at the same unit loading. Commenters stated that for a given load 

point there may be as much as a 40% difference in the PRB content of the fuel 

blend. Commenters stated that higher moisture content, lower BTU content, and 

higher slagging and plugging characteristics all tend to increase heat rate when 

using higher PRB blend percentages as compared to design (eastern) coals and the 

variation in these properties will lead to variations in heat rate, which the EPA 

uses as an indicator of heat rate improvement opportunities. Commenters stated 

that while there may be some ability to improve heat rates by lowering PRB 

blends, it would reduce the flexibility of the units and the value this flexibility 

drives for the customers.

• Commenters stated that to mitigate the impacts of higher PRB blends, boilers are 

operated to control temperatures and lessen the likelihood of furnace pluggage 

and this typically results in lower unit loading and higher average heat rates

because of the distribution of unit no-load heat input over fewer megawatts of 

generation.

• Commenters stated that the dynamic blending of eastern and PRB fuels provides 

benefits in lowering SO2 and NOx emissions as well as benefitting customers 

from a cost of generation perspective. Commenters stated that as recognized by 

the EPA, the higher low-sulfur western blends will result in higher heat rates. 

Commenters stated that furthermore, for many utilities including one of their 

members, the variability in heat rates (which the EPA mistakenly uses as an 

indicator of heat rate improvement opportunity) is magnified by the ability to 

dynamically blend to the market. Commenters stated that further analysis will 
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need to be performed to determine if constraining the units' ability to utilize PRB 

coal to improve heat rate is a cost effective means for controlling CO2 emissions.

Commenters stated that EPA needs to consider these impacts on the efficiency of many existing 

coal-fueled EGUs in developing its assumptions on heat rate improvements available under 

building block 1. 

Commenters stated that blending of PRB coal provides benefits both in reducing SO2 and NOx

emissions and in providing significant customer value during non-peak demand periods. 

Commenters stated that however, because of physical constraints, or to mitigate operational 

concerns, higher PRB blends generally result in limiting the maximum generation of a unit. 

Commenters provided a typical Average Heat Rate Curve showing that lower loading will result 

in a higher average heat rate. Commenters stated that the physical properties of a higher PRB 

blend and the dynamic blending we employ will tend to shift the average heat rate curve upward. 

Commenters stated that this impact is not reflected above, but is another impact that must be 

evaluated in determining the lowest cost options available to lower GHG emissions. 

Commenters stated that they have a long history of utilizing a wide variety of coals in their

power plants. Commenters stated that most of their units were designed to burn higher quality 

bituminous coals, and as the EPA points out, EGUs burning these coals "tend to be more 

efficient than EGUs burning lower quality coals with higher moisture contents". Commenters 

stated that while there are efficiency advantages to burning "design" coal, many utilities 

(including theirs) have switched fuels as a technique for controlling emissions from their units.

Commenters stated that all of their coal units (except those at Belle River Power Plant) were 

designed to burn higher sulfur eastern coals and as environmental constraints tightened, 

switching to lower sulfur western coal blends became an economical means of controlling SO2. 

Commenters stated that these western Powder River Basin (PRB) coals also produce lower NOx 

compared to the eastern coals; and in addition to these environmental benefits, utilizing eastern 

and western blends is an effective means to reduce costs to their customers.

Commenters stated that PRB coals are more economical than eastern coals in terms of cost per 

BTU. Commenters stated that their delivered price for PRB coal ($/MBTU) is typically twenty to 

thirty percent lower than for eastern coals. Commenters stated that this price advantage more 

than overcomes the heat rate penalty associated with the combustion of PRB coal during nonpeak power demand periods. Commenters stated that operating constraints can limit the PRB 

percentage to a unit, or the unit may burn higher percentages of PRB at reduced capacity. 

Commenters stated that as they have gained experience in the utilization of PRB, they have been 

able to mitigate these constraints to the point where most of the units are now capable of burning 

100 percent PRB for at least some lower demand periods of time for the benefit of their 

customers during non-peak power demand periods.

Commenters stated that in addition to overcoming the technical challenges of burning the more 

economical PRB blends, they have developed processes to blend their units dynamically to 

create value for their customers. Commenters stated that the plants work with their Generation 

Optimization organization to monitor market conditions and adjust fuel blends to create the most 

value for their customers in the Midcontinent Independent System Operator (MISO) market. 
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Commenters stated that typically, lower MISO market pricing results in higher PRB blends and 

while this flexibility drives customer value, the higher PRB blends will drive increases in unit 

heat rate through various impacts:

• Commenters stated that the physical properties of higher PRB blend result in 

higher heat rates at the same unit loading and for a given load point there may be 

as much as a forty percent difference in the PRB content of the fuel blend. 

Commenters stated that higher moisture content, lower BTU content, and higher 

boiler slagging and plugging characteristics all tend to increase heat rate when 

using higher PRB blend percentages as compared to design (bituminous) coals 

and the variation in these properties will lead to variations in heat rate, which the 

EPA uses as an indicator of heat rate improvement opportunities. Commenters 

stated that while there may be some ability to improve heat rates by lowering PRB 

blends, it would reduce the flexibility of their units and the value this flexibility 

drives for their customers.

• Commenters stated that to mitigate the impacts of higher PRB blends, boilers are 

operated to control temperatures and lessen the likelihood of furnace pluggage; 

and this typically results in lower unit loading and higher average heat rates 

because of operation at a less efficient point of the heat rate curve and the 

distribution of unit no-load heat input over fewer megawatt-hours of generation.

• Commenters stated that the dynamic blending of eastern and PRB fuels provide 

benefits in lowering SO2 and NOx emissions as well as benefitting their

customers from a cost of generation perspective and as recognized by the EPA, 

the higher western PRB blends will result in higher heat rates. Commenters stated 

that furthermore, for DTE, the variability in heat rates (which the EPA mistakenly 

uses as an indicator of a heat rate improvement opportunity) is magnified by their

ability to dynamically blend to the market. Commenters stated that further 

analysis will need to be performed to determine if constraining their units' ability 

to utilize PRB coal to improve heat rate is a cost effective means for controlling 

GHG emissions.

Commenters stated that they have made a significant commitment to switch the fuel in their coalfired fleet from eastern bituminous coal (the original design basis for all of their coal units) to a 

dominant fuel mix of western sub-bituminous coal (often as 100% of the fuel burned). 

Commenters stated that this was done primarily as an effort to reduce SO2 emissions associated 

with higher-sulfur bituminous coal. Commenters stated that nonetheless, the sub-bituminous 

coal has lower heat content than bituminous coal and this decreases overall unit efficiency. 

Commenters stated that clearly, efforts to support Building Block #1 should not have been to 

include blending eastern coal at higher rates, or be penalized for not reverting back to eastern 

coals which have negative environmental impacts. 

Comment 5: Comments addressing parasitic load from pollution control technologies
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Response 5: For the EPA’s response to these comments, see section V.C of the final rule

preamble of the CPP and Chapter 2 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 air pollution control equipment added to comply with other rules, such 

as EPA's MATS rule, Clean Air Interstate Rule, regional haze rule and others, will increase 

parasitic load and cause plant heat rate efficiency to suffer and, therefore, make it difficult to 

reach the HRI goal of 6 percent.

Commenters stated that EPA ignores in its building block 1 analysis the ways in which EGUs' 

heat rates (and thus, CO2 emissions) are negatively impacted by operating load and by auxiliary 

power requirements needed to run associated equipment and emission controls and, in particular, 

has overlooked the negative impact on coal-fired EGU efficiency of an EGUs' obligations under 

the remaining components of its proposed BSER and under other CAA programs. Commenters 

stated that, for example, based on regional haze rule requirements, the operators of LRS are 

installing a selective catalytic reduction system and the fans associated with this system are 

expected to increase station power requirements by 22.5MW, or 7.5 MW per unit. Commenters 

stated that according to the commenter, based on generating capacities of 570MW per unit, this 

power increase means regional haze rule related compliance controls contribute to a 1.3 percent 

reduction of plant efficiency at full power and a 1.7 percent reduction in efficiency at 75 percent 

capacity. Commenters stated that EPA should adjust its modeling assumptions and allow states 

to adjust their targets based on compliance obligations that power plants have under other CAA 

programs. 

Commenters stated that the MATS rule requires coal plant operators to pay more attention to 

tuning and improving combustion performance, thus potentially improving plant heat rate. 

Commenters stated that if the installation and operation of additional emission controls are 

required, net heat rate - not gross heat rate - will typically suffer and because those controls 

increase the consumption of auxiliary power, less efficient plants may be required to operate to 

make up the difference consumed by the new controls. Commenters stated that the incremental 

increase in those plants' operation will increase the average heat rate of the affected fleets. 

Commenters stated that the existing coal fleet is being retrofitted for MATS compliance, which 

may include investments in efficiency improvements and also may lead to increased heat rates at 

many units due to the retrofit of scrubbers, sorbent injection, and other technologies.

Commenters stated that in the coming years, many EGUs will be required to implement 

additional pollution controls to achieve compliance with rules already promulgated, including the 

Regional Haze Rule, the Mercury Air Toxics Rule, the Cross-State Air Pollution Rule, the Coal 

Combustion Residuals Rule, and the new effluent limitation guidelines. Commenters stated that 

therefore, even if an existing EGU's heat rate can be reduced slightly with capital-intensive 

improvements, those efficiency enhancements may be lowered or negated entirely by the energy 

needs of the additional pollution controls.
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Commenters stated that a factor in the decline of heat rate improvements at coal-fired power

plants over time is the installation of emissions control technologies. Commenters stated that 

existing coal power plants will need to install control technologies before and during the 

performance period to comply with EPA regulations. Commenters stated that these control 

technologies almost always increase the net heat rate at power plants unless the parasitic power 

required for the controls is offset by the types of upgrades that EPA anticipates in its Proposed 

Rule. Commenters stated that for example, installing flue gas desulfurization to comply with the 

National Ambient Air Quality Standards for sulfur dioxide can increase auxiliary power 

consumption by two percent thereby increasing a plant's heat rate. Commenters stated that EPA 

accounts for the "heat rate penalty" of installation of parasitic control technology in its IPM 

model through a reduction in electricity sales, but fails to incorporate the "heat rate penalty" into 

its calculation of state emission reduction goals. Commenters stated that in calculating state 

goals, EPA takes the state coal-fired power plant average CO2 emissions rate in 2012 and 

reduces the emission rate by six percent based on the assumption that a six percent heat rate 

improvement will directly translate to a six percent reduction in the CO2 emissions rate and that 

the heat rate at coal-fired power plants will remain constant over the performance period. 

Commenters stated that the 2012 CO2 emissions rate was not adjusted for the "heat rate penalty" 

from parasitic control technology. Commenters stated that as a consequence, a state must not 

only achieve the six percent heat rate improvement EPA explicitly includes in the calculation but 

also an additional heat rate improvement to offset lost generation from parasitic control 

technology. Commenters stated thus, EPA is requiring coal power plants to achieve net heat rate 

improvements at coal power plants greater than six percent.

Commenters stated that the retrofit of environmental controls has significantly impacted net plant 

heat rate. Commenters stated that the discussion in this section so far has concerned gross heat 

rate - the only data available on an hourly basis to generate a heat rate versus load curve. 

Commenters stated that however, the proposed CO2 limit is on a net generation (and thus net 

heat rate) basis. Commenters stated the owners' operation and actions that affect net output must 

be considered.

Commenters stated that the change in net auxiliary power consumption due to retrofit of FGD 

and SCR was calculated for the twenty-eight retrofit units described previously. Commenters 

stated these data were determined by examining the EIA-reported auxiliary power consumption 

in the years preceding and following the environmental control system retrofits. Commenters 

referred to Figure 2-7 (titled: “Increase in Auxiliary Power Due to Retrofit of SCR or FGD”),

which presents the results defining the increase in auxiliary power required by a unit after 

retrofitting SCR and FGD. Commenters stated the data for SCR reflects units firing any coal; 

data for FGD reflects units firing (a) subbituminous coal, and (b) bituminous or a blend of 

subbituminous and bituminous coals. Commenters stated the retrofit of SCR consumes auxiliary

power of about 1.5% of gross output, greater than predicted by a calculation of process demand. 

Commenters stated the retrofit of FGD to units fired by subbituminous coals increases auxiliary 

power by about 1%, with retrofit to units firing bituminous or a blend of these fuels increasing 

auxiliary power about 2%. Commenters stated the units firing subbituminous coals to which 

FGD is retrofit employ either dry or wet FGD; whereas units firing bituminous are all wet FGD. 

Commenters stated that the change in net plant heat rate is another means to measure the role of 

environmental controls on production and referred to Figure 2-8 (titled: “Change in Net Plant 

Heat Rate: CEMS vs. EIA-Based Calculations”), which is depicting a timeline of net plant heat 
14

rate for a large Midwest unit that in 2007 retrofit both wet FGD and a dedicated, wet stack within 

the same outage. Commenters stated that the net plant heat rate data are calculated based on fuel 

use records. Commenters presented the net plant heat rate increases significantly when 

comparing the pre-FGD and post-FGD period of spring 2007 in Figure 2-8. Commenters stated 

that gross heat rate data for this unit are compromised by the change in gas handling approach 

and the new stack, and - with the retrofit of wet FGD - the introduction of CO2 into the process 

gas due to the dissolution of limestone. Commenters stated that this latter factor can affect the 

CO2 content of the gas stream by several percentage points. Commenters referred to data in 

Figures 2-7 and 2-8 which show that retrofit of FGD and SCR environmental controls can 

increase net heat rate by up to 3.5% for retrofit of both SCR and wet FGD to bituminous coal. 

Commenters stated this net heat rate increase approaches the EPA's target for heat rate reduction. 

Commenters stated the amount of net heat rate increase in Figure 2-8 attributable to the retrofit 

of wet FGD is unclear, but likely is of the same magnitude (about 2-3%). 

Commenters stated that environmental controls such as selective catalytic reduction (SCR)

actually reduce plant efficiency by creating additional parasitic load. Commenters stated Utah's 

affected EGUs already have environmental controls that reduce their efficiency, and face 

additional controls under current and future environmental requirements, including PM 2.5, 

mercury and ozone rules. Commenters stated that it is important that proposed power plant 

improvements for carbon dioxide emissions do not conflict with or penalize power plants for 

compliance with other environmental regulations and that EPA should recognize that existing 

and pending environmental controls can decrease coal unit efficiency and should adjust targets to 

reflect this reality

Commenters stated that many units will be required to install additional environmental controls

under other regulations (MATS, NSR, 316b, etc.) and these controls generally increase a unit's 

net heat rate and therefore its net CO2 emission rate. Commenters asked why EPA did not 

account for this. 

Commenters stated that parasitic load at an EGU lowers heat rate because it reduces the amount

of gross plant generation that can be supplied to the grid; for example, the installation of 

scrubbers, selective catalytic reduction ("SCR"), and baghouses significantly degrade the net heat 

rates of coal-fired EGUs because of the associated parasitic power. Commenters stated that the 

retrofit of SCR increases auxiliary power by about 1.5 percent of gross output, while flue gas 

desulfurization ("FGD") retrofit may increase auxiliary power by 1-2 percent, depending on coal 

type and that since 2002, about 140,000 MW of SCR and 120,000 MW of FGD have been 

installed on EGUs. Commenters stated that Dominion installed seven of their eight SCRs and 

four of their seven wet scrubbers post 2002.

Commenters discussed net heat rate sensitivity to additional plant auxiliary power consumption.

Commenters stated that historically each set of emissions control regulation increases auxiliary 

power consumption by about 1% of gross generation (EPRI report 1024651 "Program on 

Technology Innovation: Electricity Use in the Electric Sector", 2011). Commenters stated that if 

the trend (observed over 20 years) continues, additional air emissions control technologies will 

likely be required and as a consequence, additional auxiliary power consumption will result. 

Commenters stated that all EPRI and other referenced estimates of heat rate improvements are 

reported on a net basis. Commenters stated that net heat rate reflects the cost of generating 
15

electricity including the cost of auxiliary power consumed as part of the process and thus net heat 

rates are affected by the addition of emissions controls. Commenters stated that the use of gross 

heat rate data for determination of heat rate improvement-related CO2 mitigation potential in 

Building Block 1 is inconsistent with the use of the net emission accounting used in the state 

goals computation. Commenters stated that this may lead to inconsistencies, confusion, and 

possible overestimation of the mitigation potential. Commenters recommended that EPA use a 

consistent approach for net heat rate estimation and accounting through the proposed rule.

Commenters stated that a plant such as Hoosier Energy's Merom generating station,

approximately 56 percent of the power that is auxiliary power, is used for pollution control 

equipment. 

Commenters stated that they have made significant investments in environmental controls to

comply with other EPA regulations, such as MATS. Commenters stated that adding 

environmental controls has a negative effect on net heat rates due to the large station service (or 

parasitic load) from the controls. Commenters stated that EPA has ignored the impact 

environmental controls have on net heat rates and the sustainability of net heat rate 

improvements and EPA has also arbitrarily used 2012 as a baseline for net heat rates from coalfired EGUs. Commenters stated any changes to affected units after 2012 to comply with other 

EPA regulations will hinder a unit's ability to achieve and sustain any net heat rate improvement, 

much less a six percent improvement; for example, during or after 2012, Plant Scherer Units 1, 2, 

and 4 installed Flue Gas Desulfurization Systems ("FGDs") and SCRs. Commenters stated that

the FGDs installed at Scherer Units 1, 2, and 4 have a per unit parasitic load of approximately 17 

to 18 MW; and the SCRs installed at the same units have an additional per unit parasitic load of 

approximately four to seven MW. Commenters stated that the corresponding net emission rate 

impacts from the installation of environmental controls at Plant Scherer Unit 4 are shown in 

Figure 2. 

Commenters stated parasitic loads at other units installing environmental controls will increase, 

undoubtedly impacting the units' net heat rates. Commenters stated Plant Daniel Units 1 and 2 

are currently installing an FGD, and currently, Plant Bowen Units 3 and 4, Plant Gorgas Units 8, 

9, and 10, and Plant Gaston Unit 5 are installing baghouses to be completed in 2016. 

Commenters stated that based on their coal-fired generation fleet, the parasitic load requirement 

of individual air emission controls can be significant. Commenters stated the approximate 

parasitic load impacts of some environmental controls across their coal-fired EGUs are shown in 

Table 2. 

Commenters stated, as Table 2 indicates, the total parasitic load from one air emission control, an 

FGD, can be as much as 20 MW. Commenters stated that the total parasitic load of air emission 

controls at a well-controlled coal-fired EGU could be as much as 34 MW and as a result of the 

installation of these environmental controls, these units' net heat rates have trended higher after 

the controls were installed. Commenters stated that in addition, some units are switching 

available coal sources in order to comply with regulations for economic reasons. Commenters 

stated these changes can impact net heat rate; for example, Powder River Basin ("PRB") coal has 

a lower heating value, which results in a higher net heat rate for units burning PRB. Commenters 

stated it is not apparent that EPA considered coal type in its analyses. Commenters stated that for 

a given unit burning PRB, (or any other coal with similar lower heating values) the net heat rate 
16

of the unit will suffer one to two percent as compared to a unit burning bituminous coals with 

higher heating values and no collection of best practices or upgrades can abate this result.

Commenters stated that it is also anticipated that additional controls such as FGDs, SCRs, and

fuel switches may be required in the future to implement new, more stringent NAAQS and other 

air regulations. Commenters also stated that water regulations such as Para 316(b) and the 

proposed Effluent Limitation Guidelines ("ELG") may require controls such as cooling towers 

and water treatment systems that also utilize station services. Commenters stated the station 

services needed to operate a cooling tower for a large coal or gas unit can be as high as four MW 

for mechanical draft fans and an additional two MW for pumping requirements. Commenters 

stated the station services required for physical, chemical, biological treatment, and thermal zero 

liquid discharge systems used to treat scrubber wastewater for ELG compliance could range 

from one to four MW. Commenters stated that as additional environmental regulations become 

effective in the future, units' parasitic load requirements will likely increase, making it even less 

feasible for coal-fired EGUs to achieve and sustain any level of net heat rate improvement.

Commenters stated that as required by the South Dakota Regional Haze State Implementation

Plan approved by EPA on April 26, 2012, Commenters Big Stone Plant is required to install an 

SCR, dry scrubber, and baghouse to remedy visibility impairment at certain Class I areas. 

Commenters stated that this project - currently estimated to cost $384 million - will equip Big 

Stone Plant with a state-of-the-art AQCS that is projected to reduce emissions of NOx and SO2 

by approximately 90%. Commenters stated that when paired with an activated carbon injection 

system, these controls will also enable Big Stone Plant to comply with EPA's MATS rule.

Commenters stated that the AQCS will itself consume energy that would otherwise be 

transmitted and distributed to consumers and this will degrade Big Stone Plant's overall heat rate. 

Commenters stated that as described in the Statement of Basis to the Big Stone Air Quality 

Construction Permit that was reviewed by EPA and issued to their facility on January 6, 2012, an

estimated 8 to 9 MW of station service may be attributable to the project. Commenters stated 

that project engineers are diligently working to minimize this parasitic load and the final station 

service requirements will not be known until project completion. Commenters stated that this 

degradation will be offset somewhat by the economizer and induced draft fan projects described 

previously, but even with those offsets Big Stone Plant will likely experience degradation in heat 

rate in 2015 due to operation of the AQCS required by other EPA rules.

Comment 6: Comment regarding additional release of CO2 from FGDs

Response 6: For the EPA’s response to these comments, see section V.C of the final rule

preamble of the CPP and Chapter 2 of the GHG Mitigation Measures TSD supporting the final 

CPP.

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

Commenters made reference to a May 2014 report for the Secretary of Energy by the National

Coal Council that cited an increase in heat rate of two to three percent for the addition of a flue 

gas desulfurization (FGD) system, and cited other operational factors that would also lead to 
17

higher heat rates (operation at reduced load, variable load operation, changing to a coal with a

higher moisture content). Commenters added that the addition of FGD systems presents a special 

case with respect to increased CO2 emissions because, in addition to the increase in heat rate, the 

chemicals used by most FGD systems release CO2 as part of the reaction that captures sulfur 

dioxide. See 79 Fed. Reg. at 34,859, n.113. 

Comment 7: Comments regarding factors that impact efficiency - O&M practices

Response 7: For the EPA’s response to these comments, see section V.C of the final rule

preamble of the CPP and Chapter 2 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 EPA's proposal is based on a complex web of assumptions, many of

them implausible about future energy demand, dramatic shifts in generation sources, adding 

more intermittent sources for generation, and reducing energy use. Commenters stated that each 

of these assumptions, what EPA calls building blocks, rests upon a weak foundation. 

Commenters stated that, with regards to increased efficiency of coal based load power plants, 

most of the six percent efficiency gain EPA assumes comes from the deployment of 

recommended operation and maintenance practices. Commenters stated that for all practical 

purposes these practices are already routine and taking place since they make the power plants 

more economic and therefore more profitable. Commenters stated that at the same time earlier 

rules EPA issued two years ago require extensive retrofits of existing plants that will make them 

less efficient and the present proposal will force many of those coal plants to run at reduced and 

suboptimal levels which in turn will also make them less efficient. 

Commenters stated that in order to analyze the true extent of the heat rate improvements

available through operation and maintenance practices, the Sierra Club conducted a preliminary 

review of the detailed operating records for individual coal-fired EGUs maintained in EPA's Air 

Markets Program Database ("AMPD"). Commenters stated that AMPD data revealed a number 

of occasions where there was a significant and sudden unexplained change in plant operating

efficiency that did not appear to be related to boiler load or a gradual degradation of performance 

with age and that accordingly, the Sierra Club conducted additional comprehensive research -

"the 52-Unit Study" - to determine whether the initially observed characteristics are common 

throughout the coal-fired fleet and to quantify the adverse impact on GHG emissions associated 

with the observed efficiency variances.

Commenters stated that plant performance assessments would help asset owners optimize O&M

strategies, and identify gaps in instrumentation. Commenters stated that performance 

assessments may share some common ground with baseline testing, but they focus instead on 

determining the most cost effective means for recovering performance. Commenters stated that 

this may involve more effective O&M, better plant optimization through operational or 

configuration changes, or major equipment upgrades or retrofits that can be implemented 

through minor and major maintenance outages.
18

Commenters stated that performance assessments can help drive process improvements that lead 

to cost-effective heat rate improvements and the assessments can identify expected return-oninvestment for various performance recovery and improvement options. Commenters stated that 

they can also identify gaps in current instrumentation and measurements that can in turn be used 

to support monitoring programs that improve the ability of plant O&M personnel to detect and 

respond to negative changes in plant performance. Commenters stated that engineering studies 

can provide options for expanding operational flexibility to optimize plant performance on a fleet 

basis, allowing plants to meet load demand with more efficient units instead of increasing load 

on less efficient plants. 

Commenters stated that detecting degradation or decay in plant performance is critical to 

sustaining heat rate improvements. Commenters stated that better detection allows asset owners 

and operators to undertake more timely and cost-effective corrective actions. Commenters stated 

that performance monitoring systems can be calibrated against periodic performance testing to 

ensure the accuracy of the systems and the analytics used by the system. 

Commenters stated that continued advances in smart sensors and software analytics are likely to 

continue to improve the fidelity of monitoring programs, and will result in increased 

effectiveness for plant O&M planning and finally, monitoring programs can and should be 

inclusive of non-performance-related operational data that support the ability of owners and 

operators to detect and address other potential problems that may arise during the operation of a 

power plant (e.g. improved reliability of the system which also supports improved performance).

Commenters stated that it should be noted that a unit's heat rate is not a constant value and that it

can vary widely due to multiple factors including unit loading and fuel characteristics. 

Commenters stated that operating a unit at full load at steady state will result in better heat rate 

than cycling a unit and stated that this dynamic can be seen in a typical Average Heat Rate Curve 

(provided on pg.19 of comment letter). Commenters stated that as a unit is loaded closer to the 

top end of its design capacity, the average heat rate will be substantially lower (i.e. energy 

efficiency higher) than the heat rate of the same unit performing at a lower loading point. 

Commenters stated that for their facility, this is a major consideration in examining two areas. 

Commenters stated that EPA assumes that, although operators must be highly sophisticated in

order to safely and profitably operate complex EGU technology and participate in the elaborate 

electrical grid system, they nonetheless are poor operators who are incapable of competently 

managing their facilities and choose to ignore opportunities for increased efficiency and reduced 

costs. Commenters stated that this false and paradoxical assumption defies logic and ignores the 

economic incentives for efficient operation. Commenters stated that EPA lists a small handful of 

practices that it hypothesizes might improve heat rate performance: turning off unneeded pumps 

at reduced loads; installation of digital control systems; more frequent tuning of existing control 

systems; or earlier replacement of worn components. 79 Fed. Reg. at 34860. Commenters stated 

that however, there is no data supporting this claim, which ignores the fact that operators may 

already have undertaken such measures or that such measures may not be feasible or practicable. 
19

Comment 8: Comments regarding the impact of geographic location and ambient conditions on 

efficiency

Response 8: The response to this comment is addressed in section 3.1.4, as well as in section

V.C of the final rule preamble of the CPP and Chapter 2 of the GHG Mitigation Measures TSD 

supporting the final CPP. Furthermore, as discussed in those documents, the final rule assesses 

potential heat rate improvement on an interconnection basis and thus further obviates 

commenters’ concerns regarding comparisons between EGUs in the Southwest and Northeast.

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

Commenters stated that heat rates are dependent on parameters such as humidity, elevation and

temperature and the same type of unit operating in the Northeast will have a very different heat 

rate from one operating in the Southwest due to the differences in elevation and climate, even if 

operation and maintenance are similar, and further, a lack of available water can reduce heat rate 

in that dry cooling is less efficient than wet cooling. Commenters stated that some coal-fired 

steam generators in New Mexico have water restrictions imposed by the federal government due 

to international compacts.

Comment 9: Comments regarding efficiency impacts from part-load conditions in general

Response 9: For the EPA’s response to these comments, see section V.C of the final rule 

preamble of the CPP and Chapter 2 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 EPA mentions a number of heat rate improvements in its 111(d) analysis 

that are less efficient at part load. Commenters stated that the Agency should factor part-load 

conditions into its analysis, because the coal fleet faces a number of future market conditions that 

will likely cause it to cycle and operate at part-load more frequently. Commenters stated that 

these conditions include low natural gas prices, increasing renewables penetration, and limits on 

total carbon emitted from EGUs (for example, RGGI, AB32, and 111d). Commenters stated that 

accounting for part-load operations and cycling will lower estimates for technical, economic, and 

market potential for heat rate improvements. Commenters stated that if grid balancing 

mechanisms were put in place such that plants did not cycle and/or run significant periods of 

time at part load, and a solution were developed as a part of the final rule that allowed coal plants 

to operate at or near base load when economical to do so, the overall benefit in emissions rate 

would likely exceed the benefits resulting from the heat rate improvements of building block 1. 

Commenters stated that baseload coal stations are designed to operate most efficiently near their

capacity output and at near-steady-state conditions and deviations reduce carbon efficiency for a 

number of reasons: 1) Parasitic loads from required ancillary equipment, including pollution 

control equipment, have a lower per-unit-generation impact when the generator is producing 

more power. 2) Plant operators have more opportunity to optimize operating conditions when 

steady state operations are maintained for longer periods. 3) When starting up a large generating 
20

unit, a portion of energy input must go towards overcoming thermal and kinetic inertia (in other 

words, heating components of the system and initiating mechanical movement within moving 

parts). 4) Increasing operational cycling increases exposure to high thermal stresses and so 

results in increased maintenance and repair requirements with attendant tendencies toward suboptimal performance. 

Commenters stated that load-following units experience much higher heat rate as is evident by

their typical heat rate curves (e.g. the best heat rate is at the top end of a unit's output). 

Commenters stated that cycling of coal power plants reduces the efficiency of coal power plants, 

thereby increasing the heat rate, and increasing equipment wear and tear and coal-fired power 

plants are more efficient when run at steady, high capacities than when cycled at low capacities. 

Commenters stated that one reason that coal-fired power plants are more efficient running at high 

loads is the same amount of electricity is required to run auxiliary equipment at high loads as low 

loads. Commenters stated that another major reason that coal-fired power plants are more 

efficient at steady, high capacities than when cycled is that plant operators have the opportunity 

to balance and optimize the equipment when the plant remains at a steady capacity. Commenters 

stated that operators must adjust the oxygen, temperature and pressure to achieve optimal heat 

rates and finally, coal-fired power plant equipment was not designed to handle the stress of the 

large temperature swings that occur during cold starts. Commenters stated that cycling at low 

capacities can lead to fatigue, creep, and fatigue-creep interaction, resulting in increased 

maintenance and repair. Commenters stated that load-following operation also creates more 

opportunities for component failure because of the thermal, mechanical, and electrical cycling of 

equipment and systems. Commenters stated that for these reasons, the increase in heat rate cause 

by cycling will likely offset any heat rate improvement from equipment upgrades and best 

operating practices. 

Commenters stated the impact of load following operations has significant impacts on heat rate 

performance as recognized in the TSD. Commenters said in Kentucky, with multiple steel 

manufacturing operations, sudden load ramping requirements are a fact of life. Commenters said 

the magnitude of the load changes are such that a single EGU cannot follow the load on a given 

day or season and many units are involved in load following operations. Commenters said the 

EPA's statistical analytics seem to suggest each and every unit should be able to shift operation 

away from load following toward base load, which is not practical.

Commenters stated EPA acknowledges the possible need for a separate standard for loadfollowing units since these are inherently less efficient than base load units. Commenters said 

they understand these concepts to be true for most fossil-fuel-fired generators, not just NGCC 

units. Commenters found it difficult to rationalize why such considerations would potentially be 

given to natural gas units and not coal-fired boilers. Commenters said this is particularly 

perplexing when some coal-fired units may choose to modify or reconstruct to achieve 

compliance with the section 111(d) requirements. Commenters said coal-fired generators were 

largely engineered to operate at high capacity factors. Commenters said these proposed rules will 

force many coal-fired units to operate as load following units, outside of their design parameters 

and at the expense of efficiency. Commenters urged EPA to extend those considerations offered 

to NGCC units to coal-fired units.
21

Comment 10: Comments regarding load changes due to redispatch to NGCC. Commenters 

stated that operating at reduced loads (from cycling or load following) negatively impacts 

efficiency thereby increasing heat rate. Commenters also stated that thermal cycling of the 

components can lead to fatigue, creep, and fatigue-creep interaction, resulting in increased 

maintenance and repair

Response 10: For the EPA’s response to these comments, see section V.C of the final rule

preamble of the CPP and Chapter 2 of the GHG Mitigation Measures TSD supporting the final 

CPP. As stated therein, we acknowledge that some heat rate improvement measures—like most 

power plant components—require maintenance in order to sustain their efficacy over time. 

Accordingly, EGU owners and operators will need to diligently apply best practices in order to 

mitigate this degradation, and may need to more frequently replace components.

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

Commenters stated that EPA's own Proposed Rule would cause existing coal-fired power plants 

to operate less efficiently and that for example, EPA's Proposed Rule would require under 

Building Block 2 that many coal-fired power plants would drop from base-load operation to load 

following, intermediate cycling or even peaking service. Commenters stated that type of service 

change will have a significant and deleterious impact on the immediate and long-term 

efficiency/heat rate of coal-fired power plants and operating coal-fired power plants as cycling, 

or load-following generation will hurt heat rate and increase CO2 emissions rates. Commenters 

stated that the Proposed Rule proposes using NGCC to meet base load and if that happens, coalfired power plants will shift from providing baseload generation and operate more in cycling 

and/or increased load following mode (operating at lower capacities and with intermittent 

increases to meet peak demand) which will result in much higher heat rate than previously, as is 

evident by their typical heat rate curves (e.g. the best heat rate is at the top end of a unit's output). 

Commenters stated that the increase in heat rate caused by load following will likely offset any 

heat rate improvement from equipment upgrades and best operating practices.

Commenters stated that increased penetration of renewable power and greater use of natural gas

combined-cycle (NGCC) units will lead to potential heat rate increases in coal units associated 

with lower utilization of these units, and the need for these units to engage more often in flexible 

operations (e.g., load following, extended low output generation, cycling), rather than "baseload" 

operations. Commenters made reference to their study in 2011 titled "Cycling and Load 

Following Effects on Heat Rate", to determine the extent of the efficiency losses associated with 

increased load following. Commenters stated the report confirmed a substantial loss and 

identified the areas in the plant that suffered with the decreased load stability. Commenters also 

stated that based on those results, both hardware and control systems were unable to maintain 

design operating values during portions of transient operation/non-steady state operation (e.g. 

lower steam temperatures),thus, the time that a unit spends operating at off-design conditions 

causes poorer heat rates.

Commenters stated that the EPA's proposed rule also fails to consider the impact of its Building

Blocks upon one another - for instance, the aim of Building Block 2 is to increase the dispatch of 

NGCCs, thereby decreasing the base-load usage of coal-fired units. Commenters stated that what 

the EPA does not consider in its analysis is that this change in dispatch of coal-fired EGUs is 
22

likely to have a negative effect on the efficiency of coal-fired EGUs. Commenters stated that 

coal-fired units are designed to operate as base-load units, running continuously at a steady load 

and changing the dispatch of these units to cycle up and down, or run at minimum loads will 

reduce its thermal efficiencies (i.e., increase the unit's heat rate) thereby requiring more, not less 

thermal input per unit of generation. Commenters stated that the relationship of unit load to heat 

rate is shown in Figure 6. Commenters stated that Sargent & Lundy identified this problem in 

their summary of study conclusions upon which EPA purports to base its proposed thermal 

efficiency improvement building block:

"Heat rate is increased when plants operate at lower loads, and the benefit of a heat rate 

improvement strategy is reduced at lower loads. Therefore, if an existing EGU is 

currently base-loaded 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 as compared 

to base-load operation. In some cases any HRI improvements achieved by undertaking 

the relevant options described in S&L's 2009 Report could, in some cases, be negated by 

HRI losses associated with load-cycling." 

Commenters stated a recent NERC review of the EPA's Proposed CPP Rule also reaches a 

similar conclusion regarding coal-fired capacity factors and increased heat rates:

"Lower-capacity factors will cause an increase in heat rates, particularly if the lowercapacity factors are due to the cycling of the coal units. As a result of Building Block 2, 

coal units will cycle more often; therefore, assumed heat rate improvements across the 

entire coal fleet are unlikely. While recognizing capacity effects in the regression 

analysis, the EPA did not evaluate the effects of lower-capacity factors resulting from the 

dispatching of natural gas generation before coal generation".

Commenters stated that coal-fired units are most efficient when operated at full load in steady

state conditions, as opposed either to cycling up and down to follow load or running at minimum 

loads. Commenters stated that the relationship of unit load to heat rate is shown for a typical unit 

in a graphic (provided on pg. 10 of comment letter, Heat Rate Impacts versus Part Load 

Operation for a Coal-Fired Power Plant).

Commenters stated that EPA's proposal encourages the minimization of coal unit operation by 

promoting a shift to other generation sources, primarily NGCCs and renewables and this shift 

will result in coal units operating more frequently at lower loads, which will make them less 

efficient-reducing the kilowatt hours generated for every Btu of input. Commenters stated that 

this required cycling operation will result in greater CO2 emissions and that coal-fired power 

plants play a critical role in the overall stability of the bulk electric system by providing reliable, 

base load generation. Commenters stated that they cannot be easily turned off and on to 

accommodate forced dispatch requirements favoring NGCCs and intermittent renewables, as 

envisioned under Building Blocks 2 and 3. Commenters stated that arbitrarily operating all 

existing NGCCs at historically elevated capacity factors while accommodating renewables will 

cause increased cycling, part-load operation, and more startups on the part of the existing coalfired power plant fleet. Commenters stated that cycling coal units will negatively impact the 
23

overall efficiency of the coal-fired fleet thus resulting in heat rate impacts not considered by EPA 

in assuming an overall HRI of 6 percent for Building Block 1 as possible. 

Commenters stated that the current economics of the electricity generation industry, and

particularly in the future under the Clean Power Plan, further complicate the ability to achieve 

and maintain heat rate improvements at affected EGUs. Commenters stated that one of the 

primary reasons for this difficulty under the Clean Power Plan resulting from the down-dispatch 

forced under Block 2 of the BSER model. Commenters stated that EPA recognizes in its GHG 

Abatement TSD that "[o]perating an EGU as a baseload unit is more efficient than operating an 

EGU as a load following unit to respond to fluctuations in customer electricity demand," but still 

despite its own requirements to reduce load, believes that these same units will be able to make 

significant heat rate improvements. This is, almost by definition, an arbitrary and capricious 

rulemaking design. 

Commenters stated that EPA failed to take into account that operational changes intended for

coal-fired units under the building blocks are likely to increase heat rates and that many coalfired EGUs operate less efficiently (i.e., increased heat rate) at lower capacity factors. 

Commenters stated that because the purpose of Building Block 2 is to substitute natural gas 

generation for coal-fired generation, it is likely that coal-fired EGUs will be operating at lower 

capacity factors and thus will be less efficient when they do operate than EPA assumed in its 

projections. Commenters stated if coal-fired EGUs become load-following rather than base load 

units, and endure more frequent ramps, startups, and shutdowns, operations will be less efficient, 

yet EPA did not consider these operational issues when determining what heat rate 

improvements may be possible under state plans. 

Commenters stated that coal-fired EGUs are more efficient when run at steady, high capacities

because the same amount of electricity is required to run auxiliary equipment at high capacities 

as at low capacities, and because plant operators have the opportunity to balance and optimize 

the equipment when the EGU operates at a steady capacity. Commenters stated for example, 

operators must adjust the oxygen, temperature and pressure to achieve optimal heat rates, and 

coal-fired power plant equipment was not designed to handle the stress of the large temperature 

swings that occur during cold starts. Commenters stated 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 stated that load-following operation also creates more opportunities for component 

failure because of the thermal, mechanical, and electrical cycling of equipment and systems. 

Commenters stated that as the North American Electric Reliability Corporation ("NERC") has 

explained, Building Block Two will cause "coal units [to] cycle more often; therefore, assumed 

heat rate improvements across the entire coal fleet are unlikely” and ironically, cycling also leads 

to less efficient operation and higher CO2 emissions per MWh.

Commenters stated that there is uncertainty that Building Block 1 would have a role in Arizona's

compliance plan under 111(d) because of the aggressive assumptions for redispatch applied by 

EPA to Arizona's goals under Building Block 2. Commenters stated that EPA has not accounted 

for the impacts other aspects of this Proposed Rule will have on an EGU's ability to achieve the 

level of heat rate improvements contemplated by EPA and for example, using NGCC generation 

in place of coal generation will further degrade heat rate performance of remaining coal units 
24

because it is expected these units will operate at lower loads, which has a negative impact on 

heat rate 

Commenters stated that Building Block 2 of the proposal calls for significant increases in the

utilization of Natural Gas Combined Cycle (NGCC) units, which will have a detrimental impact 

on a coal unit's ability to improve heat rates. Commenters further stated that EPA's building 

block 2 assumes that Natural Gas Combined Cycle units can be dispatched to a 70 percent 

Capacity Factor. Commenters stated that EEI commentary points out many inconsistencies, 

omissions and flaws in the assumptions used in this building block. Commenters stated that those 

will not be discussed in detail here; rather, the impact of the increased dispatch of NGCC units 

on coal fired units' heat rates will be explored. 

Commenters summarized that the proposed rule includes increased dispatch of NGCC plants

which will force coal units to adjust output to follow load changes thereby reducing their 

efficiency.

Comment 11: Comments regarding load changes due to a combination of multiple building

blocks, including comments on the unit specific impacts of low load factor on net heat rate.

Response 11: For the EPA’s response to these comments, see section V.C of the final rule

preamble of the CPP and Chapter 2 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 EPA fails to recognize that the growth of renewable energy generation in 

Texas has also impacted the heat rate of power plants in Texas, and will increasingly make it 

difficult to maintain even the current heat rates. Commenters presented a graph (Figure 4) 

showing the ERCOT generation fleet stack for a week in April 2014, which illustrates that 

Texas's 11,000 MW of wind power has substantial impacts on the operations of coal plants, 

particularly in the spring. Commenters stated that this result occurs during days with relatively 

low load, gas-fired generation is often curtailed as much as can feasibly be done (while still 

ensuring adequate ancillary services and reserves on the grid), necessitating ramping of the coal 

fleet in order to maintain system reliability. Commenters stated that this ramping naturally results 

in coal plants running in a less than optimally efficient manner, and consequently a higher heat 

rate, and that EPA's method of calculating state emissions rates does not take into account this 

unavoidable consequence of the introduction of large amounts of renewable energy into power 

systems, and further illustrates the flaws in Rule 111(d).

Commenters stated that the thermal efficiency of an EGU decreases sharply when operated at

loads below 60 percent and that this reduction in efficiency increases the emissions rate per unit 

of electricity for oxides of nitrogen (NOx), sulfur oxides (SOx), volatile organic compounds 

(VOCs), hazardous air pollutants (HAPs), and CO2. Commenters pointed out that, by applying 

Building Blocks 2, 3, and 4, coal-fired units would be forced to be dispatched at lower loads and 

that EPA is in effect reducing the thermal efficiency of those coal-fired units which is counter to 

the intent to reduce emissions. Commenters stated that, in fact, by running an existing coal-fired 
25

plant at less than a 60 percent load, the heat rate of the plant increases exponentially. 

Commenters referred to both the NERC Initial Reliability Review and a 2014 Electric Power 

Research Institute (EPRI) study which confirmed a substantial loss in heat rate with the 

decreased loads. Commenters stated that additionally, when coal-fired 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 stated that in addition to building block #1 (heat rate improvements), EPA's section

111(d) building block approach includes strategies to re-dispatch a certain percentage of 

generation from coal-fired power plants to natural gas combined cycle power plants (building 

block #2), promote renewable energy (building.1 block #3), and promote demand-side energy 

efficiency to reduce generation (building block #4). Commenters stated that EPA's second, third, 

and fourth building blocks will likely result in coal-fired units cycling more frequently and 

running more frequently at lower loads and, although EPA acknowledged that "[o]perating an 

EGU as a baseload unit is more efficient than operating an EGU as a load following unit to 

respond to fluctuations in customer electricity demand," EPA did not account for decreased 

dispatch or load profile changes in its heat rate improvement evaluation or economic analysis.

Commenters stated that the 2009 S&L Report did not analyze the impacts of load cycling on HRI 

method performance. Commenters stated however, if an existing base-load EGU changes to a 

load-following profile in the future, that unit's annual average heat rate will increase, and HRI 

methods implemented at the unit may not off-set heat rate increases due to load-cycling. 

Commenters further stated that in fact, HRI improvements could be negated by HRI losses 

associated with load-cycling.

Commenters concluded that EPA has not sufficiently accounted for equipment performance 

evaluated over long periods with increased load cycling, especially given the potential impact of 

building blocks #2, #3, and #4, and that by excluding the impacts of shifting load production 

away from coal-fired power, EPA has overestimated the efficiency improvements that can be 

achieved and sustained, and has underestimated the economic impact of potential HRI gains.

Commenters stated that the EPA did not take into account that the reduced capacity factors and

increased load variability resulting from implementing Building Blocks 2, 3, and 4 will also 

degrade the value of HRI. Commenters stated that as the heat rate benefits in the S&L report 

were specific to full load, increased flexible operations will move the actual benefits towards or 

even below the low end of the estimated ranges. Commenters stated that the effects of cycling on 

coal-fired EGUs will also lead to accelerated equipment wear and maintenance needs, further 

degrading average EGU efficiency across all loads and increasing operating costs.

Commenters stated that subsequently, in failing to recognize and address the competing 

requirements of Building Blocks 2, 3, and 4 against the goal of improving coal-fired EGU heat 

rates in Building Block 1, the EPA has overestimated the HRI benefits and fuel cost savings 

from its implementation and this has resulted in the calculation of state goals that are 

unreasonable and unjustified. In reality, the Proposed Guidelines will cause average coal-fired 

EGU efficiency and thus their CO2 lb./MWh emissions to increase regardless of the number of 

HRIs implemented, which will only serve to increase overall operating costs. 
26

Commenters stated that EPA ignores in the Building Block 1 analysis the ways in which EGUs'

heat rates (and thus, CO2 emissions) are negatively impacted by operating load and by auxiliary 

power requirements needed to run associated equipment and emission controls. Commenters 

stated that in particular, EPA has overlooked the negative impact on coal-fired EGU efficiency 

of EGUs' obligations under the remaining components of its proposed BSER and under other 

EPA programs which require pollution controls (CAA) or equipment changes (CWA) requiring 

additional house load to operate. Commenters stated that full application of Building Blocks 2, 3 

and 4 as well as the marginal dispatch of newer units will serve to reduce the future capacity 

factor of the existing coal-based EGU fleet, which tends to result in higher (degraded) heat rates. 

Commenters stated that under Building Block 2 of the Proposed Guidelines, EPA is requiring 

states to re-dispatch generation from coal-fired EGUs to NGCC units, which will result in more 

coal-fired EGUs being dispatched as load-following units rather than providing base load at high 

capacity factors and as EPA itself acknowledges, EGUs have higher heat rates when operating as 

load following units and during periods of startup and shutdown.

Commenters stated that a unit's heat rate is substantially affected by its load duty and that EGUs 

generally operate more efficiently at high capacity factors, with heat rate increasing dramatically 

at capacity factors below 50 percent. Commenters stated that operation at partial load can 

increase net plant heat rate (and CO2 emissions) by 4 to 8 percent, depending on boiler design 

and coal rank and in addition, changes in loading order can result from variations in the price of 

natural gas, the availability or unavailability of other units in a system, and in the amount of 

renewable energy serving the grid. Commenters stated that the changes in coal-fired EGU 

capacity factor required under Building Block 2 could very well eliminate any gains in efficiency 

achieved through Building Block 1.

Commenters stated that both a coal-fired EGU's heat rate and heat rate variability are negatively

affected by the operating load and auxiliary power requirements needed to run pollution controls 

and associated equipment. Commenters stated that in particular, the EPA has overlooked the 

negative impact on coal-fired EGU efficiency as units will see significant increases in cycling 

due to the implementation of Building Blocks 2, 3, and 4. Commenters stated that these negative 

heat rate impacts are not reflected in the 2012 generation data that are the baseline for the EPA's 

proposed state goals and that the impacts of implementing Building Blocks 2, 3, and 4 as EPA 

has proposed will very likely reduce or completely eliminate the potential for any overall heat 

rate improvement for coal-fired EGUs.

Commenters stated that NRG has reviewed the Sargent and Lundy study and related material on

available heat rate reductions at coal plants, and believes the EPA's Proposal materially 

overstates the amount of CO2 emission reductions that can be achieved from heat rate 

improvements at existing coal plants because greater cycling of coal units due to greater use of 

intermittent resources negatively affects efficiency and heat rate.

Commenters stated that heat rate is generally measured at optimum conditions and full load and

when the fossil units are run at partial load as proposed by EPA for coal units due to preferential 

dispatch of NGCC and renewables, these heat rate improvements will no longer be effective and 

thus the carbon reductions will not be achieved- in fact carbon will increase. Commenters stated 

the lower the load the less efficient the unit will be with respect to heat rate yielding potentially 

more carbon emitted.
27

Commenters stated that EPA fails to consider the impact that the other building blocks would

have on heat rate improvements. Commenters stated that the reduction in utilization of coalbased units resulting from Building Blocks 2, 3, and 4 will lower the potential for heat-rate 

improvements, but EPA fails to take this into account. 

Commenters stated that EPA's other Building Blocks completely undermine the ability of the

industry to achieve any real improvements in net heat rate and that EPA explicitly indicates the 

purposes of Building Block 2 (increased dispatch of NGCCs), Building Block 3 (increased 

renewables), and Building Block 4 (increased DSEE measures) are to encourage lower 

utilization of coal-fired EGUs. Commenters stated that reduced loads at coal-fired EGUs 

increase heat rates and that reduced loads also undermine the economics of any proposed heat 

rate improvement projects and, if done regardless, simply increases costs to the customer without 

achieving any efficiency benefits.

Commenters stated that coal-fired EGUs are most efficient when operating at high load factors 

and by shifting generation to NGCCs and renewable energy sources, and by reducing electricity 

demand through DSEE measures, coal-fired EGUs will operate more frequently at lower loads, 

which will make them less efficient. Commenters stated that this proposal will likely require 

coal-fired EGUs to startup and shutdown as well as to ramp up and down more frequently, 

further decreasing the units' efficiency.

Commenters stated that the resulting lower load factors, however, will cause higher net heat rates 

because net heat rate is inversely proportional to load factor and coal-fired EGUs would be 

relegated to load following and peaking service resulting in more operating hours at lower loads 

and more startup and shutdown events thus increasing net heat rate and offsetting any possible 

heat rate improvements obtained from best practices and equipment upgrades. Commenters 

presented a figure (Figure 3) depicting a generic heat rate curve illustrating the impact to the 

overall net heat rate from partial load operation.

Commenters stated that Mississippi Power and Gulf Power Company's Plant Daniel Units 1 and 

2 exemplify the result of a low load factor on net heat rate. Commenters stated that the rated net 

full load net heat rate at these units is about 0.4 percent worse when those units operate at 75 

percent of rated net full load. Commenters stated that reducing the operations at Plant Daniel 

Units 1 and 2 to 50 percent of rated net full load makes the net heat rate about six percent worse. 

Commenters stated that further reducing load to 30 percent of rated net full load negatively 

impacts net heat rate by approximately 22 percent of the rated net full load net heat rate. 

Commenters stated that because the implementation of EPA's Building Blocks will most 

certainly involve coal-fired EGUs running at lower loading levels (and starting and stopping 

more frequently), it is inconceivable that EPA's proposed heat rate improvements can be 

achieved.

Commenters stated that EGUs are likely to be required to operate below maximum unit loads,

potentially varying loads and, for significant stretches of time, operating at minimum load if care 

is not taken to avoid this outcome by planning for, and addressing, integration and reliability 

concerns. Commenters stated that carbon emissions in Germany, for example, have increased 

despite the growth of renewables in its energy supply, partially as a result of cycling coal plants. 

Commenters stated that in the United States, NREL has shown that cycling coal in a high-
28

renewables scenario would not reverse emissions reductions overall, but would cause some 

lessening of carbon emissions reductions-and could cause increases in criteria pollutant 

emissions. Commenters stated that as noted above, technical heat rate improvements cannot 

achieve EPA's projected emission reduction effects if the EGUs are operated inefficiently in 

order to address grid reliability and integration needs. Commenters stated that a specific BSER 

requirement to evaluate and address integration and reliability issues is essential to capturing the 

potential benefit of technical heat rate improvements at EGUs. 

Commenters stated that EPA fails to consider that the CO2 emission rate of certain coal-fired

units may actually increase as a result of the Proposed Rule and other recent environmental 

regulations. Commenters stated that significant redispatch from coal to natural gas units, 

additional zero-carbon generation, and increased EE will result in many coal-fired units 

operating well below their design capacity. Commenters stated that the need to operate below 

full capacity on a continuous basis will have a direct, negative impact on these facilities' 

emission rates, because the ratio of emissions to electrical output typically goes up as a unit's 

capacity factor goes down. Commenters stated that furthermore, parasitic power losses from the 

additional pollution control equipment that will be necessary to comply with the Mercury and 

Air Toxics Rule, the Cross-State Air Pollution Rule, and other recent and forthcoming 

regulations will further increase the CO2 emission rates of some EGUs. Commenters stated that 

thus, the net effect of the other BSER building blocks and EPA's other environmental regulations 

could be an increased in many coal-fired EGUs' emission rates. 

Commenters stated that regardless of EGU type, technical heat rate improvements will not

achieve their intended emission reduction effects if the EGUs are operated inefficiently to 

address grid reliability and integration needs. Commenters stated that a specific BSER 

requirement to evaluate and address integration and reliability issues without operating EGUs in 

an inefficient manner is essential to capturing the potential emissions benefit of technical heat 

rate improvements at EGUs.

Commenters stated that there is inherent incompatibility between improving the efficiency of

Gibbons Creek while changing its generation output (cycling the unit) to allow for renewable 

energy to enter the electric grid. Commenters stated that Gibbons Creek runs most efficiently 

when it is "base-loaded" - running at full capacity with no cycling. Commenters stated that if the 

unit has to be cycled down (e.g., to give preference to renewable energy sources, such as wind 

power) it runs less efficiently. Commenters stated that this is clearly demonstrated for Gibbons 

Creek with the historical data for carbon dioxide (CO2) emissions over the last nine years. 

Commenters stated that the lowest rates of emissions (pounds of CO2 per megawatt-hour of 

generation) were in the years 2005 through 2010 when the plant was running evenly at full 

capacity and since that time the plant has been cycled up and down in response to economic 

dispatch of cheaper gas plants and sources of renewable energy. Commenters stated that the 

resulting less efficient operation of Gibbons Creek is reflected in the increased CO2 emission 

rates.

Commenters stated that there is a complex relationship between fossil-fuel fired generation and

RE generation. Commenters stated that because the output of RE is highly variable, it requires 

balancing and backup services from other energy sources in order for the electric power grid to 

remain stable. Commenters stated that natural gas-based electrical generating units (EGU), 
29

including NGCC and simple cycle turbines (CT), are more flexible than other types of EGUs and 

they typically provide the balancing and backup services for the RE sources. Commenters stated 

that in addition, the operation of coal-fired EGUs are impacted by the RE availability. 

Commenters stated that when NGCC and coal-fired EGUs are needed to backup variable RE 

they must operate at lower, less efficient capacity at any given time. Commenters stated that also, 

when CTs are called on to support RE they need to operate at higher utilization rates and are 

subjected to frequent starts and stops. Commenters stated that under these operating constraints, 

RE actually causes an increase in lb. CO2/MWh as the backup units are not operating in their 

most efficient manner. Commenters stated that the potential increase in CO2 emissions as a 

result of the use of more RE is not fully represented in the Proposed Rule. 

Commenters said load following service will also lead to an increase in the number of startups 

and shutdowns experienced by the coal-fired fleet. Commenters said coal-fired unit startups are 

lengthy and inefficient operating regimes that will further increase coal-fired EGU heat rates and 

CO2 emissions. Commenters said efficiency is poor for low generation levels (a connected plant 

that is operating at zero MW output still has to supply station loads) and increases with the level 

of generation, but at some optimum level it begins to diminish. Commenters said most power 

plants are designed so that the optimum level is close to the rated output

Comment 12: Comments regarding coal utilization.

Response 12: For the EPA’s response to these comments, see section V.C of the final rule

preamble of the CPP and Chapter 2 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 competitive wholesale electricity markets generally operate using

security constrained economic dispatch (SCED), that is, every electricity generator will bid into 

the market, and the grid operator will select the lowest set of the bids that meets demand. 

Commenters stated that in well-functioning markets, generators are motivated to bid at or near 

their marginal cost of operation and therefore, these markets provide strong incentives for every 

generator to maximize their efficiency through measures to reduce their heat rates and fuel 

consumption. Commenters stated that failure to do so will cause power plants to be dispatched 

less frequently, ultimately leaving them undispatched for a large portion of the year, or forced 

from the market entirely. Commenters stated that, since 2002, over 13,000 MW of old thermal 

generation plants have been retired in ERCOT. 

Commenters stated that they can attempt to reduce utilization of their highest carbon intensity

sources, but it must also meet their members' load requirements and reduced utilization thus must 

be undertaken in conjunction with another alternative, purchase or construction of another 

generation asset, or market power purchases. Commenters stated that in addition, reduced 

utilization also adversely affects the heat rate of the EGU compared to full utilization.

Commenters stated that the EPA recognizes that operating a unit as a base-loaded unit results in

better efficiency and a lower emission rate. Commenters stated analysis that O&M 
30

improvements can lower variability and improve heat rate addresses improvements that would 

change the shape of the heat rate curve (supposedly lowering the heat rate at the same loading). 

Commenters stated that however, EPA ignores the fact that market dynamics determine a unit's 

loading profile and that O&M improvements will not likely have a significant impact on this 

important factor. 

3.1.2 Technologies to improve existing coal-fired EGU heat rate

This subsection discusses potential efficiency improvement techniques which commenters 

believe are applicable to existing coal-fired EGUs. 

Commenters have raised a number of issues related to this subsection which are organized by 

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

Comment 1: Comments regarding equipment-specific heat rate losses, including from the 

effects of normal wear. 

Response 1: As an initial matter, the EPA decided not to include a 2-percent average heat rate

improvement achievable solely through equipment upgrades, for the reasons stated in section 

V.C of the final rule preamble of the CPP and Chapter 2 of the GHG Mitigation Measures TSD 

supporting the final CPP. Nevertheless, we appreciate the generally applicable information 

regarding technologies that can improve heat rate at fossil fuel-fired EGUs. With respect to the 

anecdotal or unit-specific information provided by some commenters, we note that the feasibility 

of implementing a specific heat rate improvement measure at a specific EGU will always depend 

on unit-specific conditions. We also acknowledge that some heat rate improvement 

technologies—like most power plant components—require maintenance in order to sustain their 

efficacy over time. Accordingly, EGU owners and operators will need to diligently apply best 

practices in order to mitigate this degradation, and may need to more frequently replace 

components. For the EPA’s further responses to these comments, see section V.C of the final 

rule preamble of the CPP and Chapter 2 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 they operate an efficient coal-fired generating fleet but that some heat

rate losses, however, are unavoidable - for example, high exit gas temperatures, condenser 

performance, and turbine degradation.

• Exit gas temperatures can be reduced by replacing air heater (A/H) baskets and 

seals plus improved sootblowing. But, as soon as A/H baskets and seals are 

replaced the heat rate improvement begins to degrade. The present loss in their

system for high exit gas temperature is approximately 13 BTUs/kWh.
31

• Detriments to condenser performance include fouling, air in leakage, and perhaps 

poor vacuum pump performance which represent an approximate loss of 25 

BTUs/kWh across their system. This loss is seasonal and is not represented in 

heat rates during the winter months. As stated by S&L, tube cleaning systems can 

improve condenser performance; however, most of their large units already have 

cleaning systems installed.

• Turbines degrade during operation and are renewed during planned maintenance 

outages. Across their system there are units in various stages of repair at any 

given time. After maintenance outages, the heat rate improvement, however, 

begins to degrade as soon as the unit begins to operate. Presently, the losses are 

24 BTUs/kWh. 

Commenters stated that many projects implemented to improve heat rate depend on clean, close

tolerance machine parts that are subject to wear and corrosion. Commenters stated that this 

equipment must be periodically taken out of service for maintenance to remove corrosion 

products and restore tolerances. Commenters stated that EPA did not provide an efficiency 

range, for any heat rate improvement, to consider normal wear. 

Commenters stated that it is possible that a steam path upgrade/retrofit with advanced steam path 

technology could provide some improvement in unit heat rate for each of the Big Bend units. 

Commenters stated that however, the potential benefit is not as impactful as EPA assumes and 

the cost of this upgrade may not be prudent compared to other completed reduction opportunities 

and due to EPA's proposed Block 2 limitations on coal plant dispatch. Commenters stated that 

they implemented many heat rate improvement projects while installing emission controls as part 

of the agreement with EPA. Commenters stated that these emission controls introduce significant 

parasitic loads that offset the heat rate improvements to a significant degree and minimize the 

potential for additional heat rate improvement. Commenters stated they reported the 

implementation of these projects to EPA on a quarterly basis as part of the aforementioned 

consent decree agreement, therefore, EPA has access to the information necessary to verify the 

details and provide them with appropriate credit and other utilities that have made similar 

accomplishments. 

Commenters stated that they already undertake significant efforts to operate efficiently and the

goal of their business model is to provide reliable electric service to their member-owners at the 

lowest reasonable cost. Commenters stated that in addition to the extensive capital investment 

recently made to ensure compliance with forthcoming air regulations, they also expend 

considerable effort and resources to maintain peak boiler efficiency at all times. Commenters

stated that specific maintenance activities are scheduled on annual, three-year, and nine-year 

timelines and annual maintenance outages allow for the inspection, cleaning, and repair of 

equipment, including air heaters, precipitator, fans, dampers, coal mills, boiler feed pumps, 

condensate pumps, low pressure and high pressure heaters, condenser, duct work, environmental 

equipment, burners, coal prep equipment, and electrical and instrumentation equipment. 

Commenters stated that turbine valves are inspected and brought back into specification on a 

three-year schedule, and major turbine outages, performed every nine years, include the full 

disassembly of the turbine and generator during which time the equipment is returned to its 

original specifications, which allows for peak performance of the turbine. Commenters stated 
32

that moreover, the plant staff continuously monitors and controls oxygen levels in the 

combustion process to maintain maximum combustion of the coal; exit gas temperatures to 

prevent the wasting of available heat energy to the atmosphere; and coal pulverizers to ensure 

complete utilization of the fuel. 

Comment 2: Comments regarding the ratio of usable electricity versus waste heat

Response 2: We thank the commenters for their support. We agree that a significant amount of

the energy released from burning fossil fuel is not directly converted to electricity.

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

Commenters stated that they support the actions expressed in the regulation but point out that the

existing fossil fueled electric generating system only converts 30 percent of the fossil fuel that's 

burned into usable electricity. Commenters stated 66 is lost as waste heat. 

Comment 3: Comments regarding “advanced technologies”

Response 3: EPA thanks the commenters for the information they have provided on these

technologies. The response to this comment is addressed by the response to Comment 1 in this 

section.

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

Commenters stated that uncertainty in how a plant will operate may limit the adoption of some

advanced technologies that could be supplied to the market, as the investor or buyer needs to 

have confidence in the return on investment. Commenters stated that similarly, the manufacturers 

and suppliers of the advanced technology will depend on the potential that exists in the market in 

order to invest in bringing the advanced technologies to the existing fleet.

Commenters stated that advanced heat rate improvement strategies leverage technological

improvements from new units. Commenters stated that new steam turbine units use advanced 3D 

airfoil and blade technology, enhanced sealing technology to reduce leakages, and improved 

moisture removal from low pressure turbines. Commenters stated that experience with new units 

indicates that these advanced technologies could offer up to an additional 2.0% gross heat rate 

improvement, where feasible in existing units. 

Commenters stated that several options described by EPA - converting subcritical boilers to

supercritical conditions; drying of coal on a large-scale; injecting alkali into the gas stream 

preceding the air heater - are not yet commercially demonstrated. 

Comment 4: Comments regarding the impact of material handling on heat rate
33

Response 4: The response to this comment is addressed by the response to Comment 1 in this

section. 

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

Commenters listed limitations that should be accounted for and a site specific analysis may

reveal additional limitations:

Coal transport, conveying, and grinding:

• Minimal efficiency gain compared to total retrofit work required.

• Spatial constraints may limit applicability.

Commenters presented information with regard to STATION A - Material Handling. 

Commenters stated that material handling systems include coal, bottom ash, and fly ash handling 

and that the bottom ash (BA) and fly ash (FA) systems at Station A are wet handling systems and 

have not been converted to dry handling. Commenters stated that Unit A2 alone has 23 pumps in 

the BA/FA handling systems and that although all pumps are not operating at once, there is a 

significant amount of auxiliary (aux) power required to operate the ash handling systems. 

Commenters stated that with respect to ash handling systems, heat rate improvements can often 

be realized by converting wet handling systems to dry handling systems by eliminating 

equipment and auxiliary power loads associated with the transport of water. Commenters stated 

that both units at Station A are equipped with wet FA and BA handling systems, and therefore 

could benefit from conversion to dry handling systems. Commenters stated that fly ash handling 

conversion would reduce the total amount of pumps required, but would increase the vacuum 

system power requirements and that conversion to drag chain conveyance system for BA 

handling could reduce pump power requirement; however, site constraints must be considered 

when evaluating the feasibility of this improvement from a technical and economic standpoint. 

Commenters stated that typical wet-to-dry conversions cost in the range of $20-30/kW; however, 

due to these site constraints, it may be determined that the constraints would make this 

economically infeasible for heat rate improvement. Commenters noted that additionally, CO2 

emissions due to truck hauling the ash are not considered in this report. Commenters stated that 

Unit A1 is currently in the process of converting a second coal mill to a Fat Boy tire systems, 

which will increase the capacity and fineness of the milled coal product and that the increase in 

mill capacity will provide more reliability and maintainability and will allow full load generation 

if one mill is down for routine maintenance. Commenters stated that while the increased capacity 

could potentially allow the unit to operate one less mill for the same design throughput, the unit 

maintains all mills in operation to increase reliability - therefore, no heat rate improvement is 

possible. Commenters stated that in recent years, Unit A2 installed soft-starts on their coal 

conveyor motors and that the soft starts provided slight aux power improvement, but due to 

intermittent fuel loading, no heat rate improvement was seen. Commenters stated that the unit is 

designed with a 6th "spare" mill, but they are often forced to run on all 6 mills due to pulverizer 

performance.

Commenters presented information with regard to STATION B - BOILER ISLAND, 

MATERIAL HANDLING. Commenters stated that material handling systems include coal, 
34

bottom ash, and fly ash handling. Commenters stated that with respect to ash handling systems, 

heat rate improvements can often be realized by converting wet handling systems to dry handling 

systems by eliminating equipment and auxiliary power loads associated with the transport of 

water. Commenters stated that the bottom ash systems on Units B1 and B2 are wet sluicing 

systems and have not been converted to dry handling. Commenters stated that the bottom ash is 

sent to hydrobins (not ponds) and finally sent offsite dewatered. Commenters stated that Unit B3 

was originally equipped with the same type of wet sluicing system, but the system was later 

retrofitted to a submerged flight conveyor and that this provided the unit approximately an 11 

Btu/kWh heat rate reduction. Commenters stated that a similar retrofit is possible on the existing 

wet sluicing systems at Station B. Commenters also stated that retrofit projects were incorporated

into the 20-year plans for Units B1 and B2; however, the station has not found an economic way 

to convert to dry handling, due to the predicted installed cost today being more than three times 

the cost per unit of the Unit B3 improvement. Commenters stated that in addition, these 

improvements would require back-to-back outages on Units B1 and B2, due to the bottom ash 

systems being common, resulting in additional financial impacts due to outage scheduling. 

Commenters stated that all three units are equipped with dry FA handling systems. Commenters

stated that fly ash from Units B1 and B2 are sold for concrete, while the fly ash from Unit B3 is 

sent offsite for disposal. Commenters stated that the dry FA handling systems are already 

considered an efficient handling system, and would not achieve any further heat rate reduction 

with improvements. Commenters stated that only like-kind replacements of coal mill motors 

have been made at Station B. Commenters stated that the plant employs best operating and 

maintenance practices with coal motors; no additional heat rate improvement is predicted. 

Commenters stated that the pulverizers are providing a product that gets 80% through 200 mesh

and that this has helped provide the units with very low unburned carbon levels.

Commenters stated that the inherent moisture of their coal is below 10% and since higher rank

coal are burned, drying does not provide a significant benefit. 

Commenters stated that material handling systems include coal, bottom ash, economizer ash, and 

fly ash handling. Commenters stated that with respect to coal handling systems, the use of more 

efficient motors can improve overall plant efficiency. Commenters stated that with respect to ash 

handling systems, heat rate improvements may often be realized by converting sluiced material 

handling systems to conveyor type material handling systems and eliminating equipment and 

auxiliary power loads associated with the transport of high pressure water. Commenters stated 

that the original bottom ash and economizer ash systems at the Springerville Units 1 & 2 were 

water sluiced material handling systems. Commenters stated that the Unit 1 bottom ash handling 

system could potentially be converted to a submerged flight conveyor (SFC). Commenters stated 

that as part of the SFC conversion, it is assumed that the economizer ash handling system would 

be converted to a dry flight conveyor (DFC) system, including a collection hopper and low 

pressure water pumps to transport the economizer ash from the collection hopper to the SFC. 

Commenters stated that the auxiliary power savings from the conversion were reviewed and used 

to estimate heat rate improvements. Commenters stated that the auxiliary power consumption of 

the wet ash handling system was estimated to be 1.0 MW while auxiliary power consumption for 

the dry ash handling system was estimated to be 0.08 MW. Commenters stated that based on the 

net load rate of the units, the reduction in heat rate was estimated to be approximately 0.26% per 

unit. Commenters stated that discussions with one of their members indicated that this SFC 

conversion for Unit 1 is estimated to cost approximately $13.3MM ($36 per kW).
35

Commenters stated that Unit 2 was converted to a SFC in 2010 and Units 3 and 4 were originally 

equipped with SFC ash handling systems; therefore, no further improvements to these systems 

can be made to reduce heat rate beyond utilizing more efficient motors.

Commenters stated that all four SGS units were originally equipped with dry, fly ash handling 

systems, which are considered efficient material handling systems; therefore, no further 

improvements to these systems can be made to improve heat rate beyond utilizing more efficient 

motors. 

Commenters stated that as an example, they have developed a lignite fuel enhancement system,

DryFiningTM, which refines lignite coal through a drying and segregation process. Commenters

stated that the drying component utilizes waste process heat to raise the heating value of the coal. 

Commenters stated that the refining component segregates the lignite stream and removes the 

higher density compounds that contain higher levels of sulfur and mercury. Commenters stated 

that their Coal Creek Station has used DryFinedTM lignite since 2009. Commenters stated that 

this enhanced coal has improved efficiency and overall emissions performance, including a 4 

percent reduction in CO2 emissions. Commenters stated that DryFinedTM lignite is also used at 

their Spiritwood Station CHP facility. 

Comment 5: Comments regarding heat rate improvements from changes to the boiler heat

absorbing surface

Response 5: The response to this comment is addressed by the response to Comment 1 in this

section. 

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

Commenters stated that changes to the boiler heat absorbing surface are possible. Commenters

stated that typically, any such changes do not elevate boiler heat absorption beyond the initial 

design but restore thermal efficiency approaching the initial design state. Commenters stated that 

actions to improve heat removal by changes to the boiler produce highly variable results, with 

their members citing from 20-40 Btu/kWh payoff, noticeably less than the 70 Btu/kWh cited by 

EPA's reference study. Commenters stated that as previously noted, in many cases these changes 

do not fully restore boiler performance to initial design conditions. Commenters presented a 

table (Table 3-1) which reports intelligent cleaning can reduce heat rate by 30 to 100 Btu/kWh 

for capital cost less than $1M - but it must be recognized that benefits vary with boiler design, 

fuel, and the state of the control system (upgrade to digital controls required). Commenters stated 

that the improvements in heat rate with intelligent cleaning can appear particularly attractive -

but can be misleading, because such systems are usually applied to atypical boilers that are 

plagued with excessive surface fouling and deposits. Commenters stated that frequently these 

problems are induced by firing subbituminous coals - so at best, these systems restore heat 

absorption to original design values. Commenters stated that in summary, changes to boiler heat 

absorbing surface are possible, but at best restore performance rather than improve performance 

beyond the original design. Commenters stated that intelligent or aggressive cleaning to maintain 

original heat rate can be high payoff particularly for boilers with slagging/fouling issues induced 

by switching to PRB coals.
36

Commenters stated that S&L identifies boiler overhaul with a new heat transfer surface as a

possible method to decrease a power plant's heat rate but that however, S&L warns that such 

extensive overhauls are fraught with potential design problems that may actually increase the 

heat rate. Commenters stated that because of this, the study ironically advises EGU owners that a 

better approach would be to construct a new power plant. Commenters stated that such a solution 

would then make the unit subject to CAA section 111(b). Commenters stated that this portion of 

the study also suggests that EGUs with Selective Catalytic Reduction (SCR) have already 

upgraded the economizer in order to lower the exit gas temperature and that a 50-100 BTU/kWh 

reduction in heat rate is possible with such an upgrade. Commenters stated that all but one EGU 

in West Virginia not slated to permanently shut down has installed SCR (Fort Martin utilizes 

selective non-catalytic reduction) and therefore, any reduction in heat rate from upgrading the 

economizer is generally not feasible for West Virginia EGUs because the available reduction has 

already been achieved. 

Commenters listed limitations that should be accounted for and a site specific analysis may 

reveal additional limitations: Boiler operation/overhaul with new heat transfer surface:

• Increasing heat transfer surface area in the boiler could increase steam generation 

to beyond the steam turbine design which could require additional changes.

• Any increase in steam flow may also require increase in coal flow thus possibly 

triggering NSR under some circumstances.

• Periodic replacement to recover the steam generation capacity of the unit does not 

yield any increase in efficiency.

• Units (limited number) required to add economizer surface area to lower 

temperatures at full load to prevent sintering of SCR catalyst must frequently also 

raise temperatures at lower loads to prevent ammonium salt deactivation of the 

catalyst. These competing goals limit the HRI at full load.

Commenters presented information with regard to STATION A - BOILER ISLAND, BOILER 

OPERATION/OVERHAUL WITH NEW HEAT TRANSFER SURFACE. Commenters stated 

that adding heat transfer area to boiler surfaces is a possible methodology for reducing plant heat 

rate. Commenters stated that a portion of the reheat surfaces were replaced in 2010 on Unit A1 to 

balance temperatures and that during the installation of the SCR on Unit A2, the economizer 

surface area was split in half; half remained in place and the other half was relocated downstream 

of the SCR. Commenters stated that the split of surface area was completed to increase flue gas 

temperature at the SCR inlets, while maintaining overall steam temperatures at low load 

operation. Commenters stated that due to the same heat transfer surface area being maintained, 

the improvements did not have an impact on the unit's heat rate, but the split economizer 

configuration prevented a heat rate penalty that would have been incurred by pegging the top 

heaters from a higher pressure alternate steam source at low loads. Commenters stated that in 

addition, both units were re-rated after the installation of the FGDs on each unit between 2005-

2012 and that the FGD project on Unit A1 also included conversion to a balanced draft system. 

Commenters stated that adding surface to improve the steam temperatures beyond the original 

design values would require a major evaluation of all affected pressure parts and typically is not 
37

economical. Commenters stated that because no improvements to surface area were included, the 

replacement of these surfaces allows the units to maintain heat rate, or 0% reduction as compared 

to the original design. Commenters stated that no further improvements to the superheater or 

reheater tubes can be made to reduce the heat rate.

Commenters presented information with regard to STATION B - BOILER ISLAND, BOILER 

OPERATION/OVERHAUL WITH NEW HEAT TRANSFER SURFACE. Commenters stated 

that adding heat transfer area to boiler surfaces is a possible methodology for reducing plant heat 

rate. Commenters stated that no additional heat transfer surface area has been added to any of the 

three units since its original design. Commenters stated that the reheaters are still the original on 

all three units. Commenters stated that some sections of the superheater have been replaced likekind on all three units after 30 years of operation and that no additional heat transfer surface was 

added during this process; therefore, the unit did not experience any heat rate improvement. 

Commenters stated that adding surface to improve the steam temperatures beyond the original 

design values would require a major evaluation of all affected pressure parts and typically is not 

economical. Commenters stated that the units at Station B have the original heat transfer surface 

area that was designed for the units and that the station personnel employ the best operating and 

maintenance practices in regards to the boiler heat transfer surface area and are not predicted to 

gain any benefit from additional surface area.

Commenters stated that adding heat transfer area to boiler surfaces is a possible methodology for 

reducing plant heat rate. Commenters stated that the replacement of superheater and reheater 

tubes is part of a general maintenance practice that can recover heat transfer performance that 

has been lost over time. Commenters stated that adding surface area to improve the steam 

temperatures beyond the original design values would require a major evaluation of all affected 

pressure parts and is typically not economical.

Commenters stated that the Unit 1 and 2 boilers are currently on a 3-year outage cycle where the 

owner performs replacements of the water wall tubes. Commenters stated that in general, routine 

inspections and maintenance is performed to replace boiler components in-kind to maintain the 

original boiler performance. Commenters stated that for Units 1 and 2, no improvements to 

surface area have been made, the in-kind replacements of these surfaces allows the units to 

maintain heat rate, or 0% reduction as compared to the original design. Commenters stated that 

no further improvements to the superheater or reheater tubes can be reasonably implemented to 

improve heat rate beyond best operating and maintenance programs. Commenters stated that 

Units 3 and 4 are on the same 3-year outage cycle but the necessity for tube replacements is 

minimal due to the boilers being relatively new. 

Comment 6: Comments regarding efficiency gains from economizer replacements

Response 6: The response to this comment is addressed by the response to Comment 1 in this 

section. 

The following are summaries of the specific public comments under this comment:
38

Commenters stated that regarding economizer replacement (S&L 2.2), the Black Hills plants are

generally too new for the problem described by Sargent & Lundy to apply, and the issue has 

been deferred for a more nuanced engineering review. Commenters stated that at Wyodak, the 

plant needs the heat for winter operations, so the modification is not suitable and that at 

Naughton 1 and 2, the modification would not be economic within the plant's remaining book 

life ending 2029. Commenters stated that Naughton 3 will be converted to gas in 2018. 

Commenters stated that at Dave Johnston 1 and 2, the change would not yield substantial 

benefits due to the quality of coal being burned, and replacement is not necessary or appropriate 

due to the operation of new emissions control equipment. Commenters stated that the S&L 

replacement already occurred at Dave Johnston 4 in 2009 and that Dave Johnston 3 is 

considering the improvement based on a 2014 study which did not find direct heat rate benefit, 

but indicated indirect potential for improvement by addressing existing problems with plugging 

and fouling. Commenters stated that the improvement is under consideration but not budgeted. 

Commenters stated that modification is planned for the four units of Jim Bridger from 2015 

through 2018, with an anticipated improvement of 21 Btu/kWh at each unit, that is, less than the 

range anticipated by S&L.

Commenters stated that as noted in the 2009 Sargent & Lundy Report, "economizer

replacements do occur during some selective catalytic reduction (SCR) retrofit projects. 

Commenters stated that because the SCR design is dependent on the temperature of the flue gas 

being controlled below a specific temperature, a specific plant may be operating with a higher 

economizer exit gas temperature, which would require a new or upgraded economizer section to 

lower the gas temperature for an SCR retrofit project. Commenters stated that the temperature 

reduction may range from 20-40 degrees F...." and that they agree with this statement. 

Commenters stated that in fact, Big Stone Plant will be replacing the economizer in 2015 during 

the planned AQCS outage for the very reason given by Sargent & Lundy: lowering the exit gas 

temperature by a minimum of 20 degrees for the SCR catalyst. Commenters stated that if the 

economizer project were undertaken on its own, and notwithstanding the fact that the long-term 

payoff of this project may be significantly smaller than the immediate reduction in heat rate 

observed after implementation, the median heat rate improvement suggested by Sargent & 

Lundy report is approximately 0.7% for Big Stone Plant.

Comment 7: Comments regarding the impact of neural networks on heat rate

Response 7: The response to this comment is addressed by the response to Comment 1 in this 

section.

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

Commenters addressed neural networks and stated that S&L indicates that EGUs can improve

boiler efficiency from 0-1.5 percent by installing hardware and software that models and predicts 

EGU performance. Commenters stated that the study notes that for larger EGUs, the potential 

heat rate reduction by installing a neural network is only 0-50 BTU/kWh, which translates to a 

maximum of only 0.48 percent decrease in heat rate. Commenters stated that most large EGUs in 

West Virginia have already installed such hardware and software during the installation of SCR 
39

and FGD devices, or to comply with the MATS and therefore, any future reduction in heat rate 

with respect to installation of a neural network is generally not achievable for West Virginia 

EGUs.

Commenters listed limitations that should be accounted for and a site specific analysis may

reveal additional limitations:

• Neural network (NN) control System:

• Units using NN for NOx control have generally achieved HRI through lower 

excess air and optimized air to fuel ratio and cannot further optimize the boiler 

operation for heat rate improvement without sacrificing NOx reduction.

• Units not already equipped with distributed control system (DCS) controls will 

have a harder time implementing the intricate system.

Commenters stated that Black Hills and PacifiCorp both characterize the neural network issue

(S&L 2.3) as a matter of boiler controls. Commenters stated that Black Hills agreed that a 

potential modification could be made for an improvement of 8 Btu/kWh over its four plants, i.e., 

in the low end of the range anticipated by S&L. Commenters stated that PacifiCorp has planned 

neural network upgrades for the four units of Jim Bridger from 2019 through 2022, and is 

contemplating further upgrades from 2023 through 2026. Commenters stated that no change is 

possible at Dave Johnston 1 and 2 because these units do not utilize a distributive control system, 

so a complete change of the control system would be required, which is not economical. 

Commenters stated that PacifiCorp recognizes the potential for a neural network improvement on 

Dave Johnston Units 3 and 4, at Naughton Units 1, 2, and 3, and at Wyodak, although the 

modifications are not currently planned. 

Commenters stated that computer models, known as neural networks (NNs) simulate the power 

plants at various static and dynamic loads, with the predicted performance results correlated to 

several real-time process measurements and that neural network control systems can be used to 

optimize emissions such as NOX and CO, as well as help optimize boiler efficiency. 

Commenters stated that no unit at Station A has NN installed and that he utility that operates the 

units at Station A has previous experience with NN among their fleet, but has not experienced 

the advertised boiler operation benefits associated with the switch. Commenters stated that 

presently, rather than installing NN on additional units among its fleet, the utility has a 

burner/boiler management team that travels around their fleet to optimize and maintain the units. 

Commenters stated that the team focuses on optimizing CO emissions, rather than NOx 

emissions, due mainly to the fact that the units are equipped with SCRs for NOx reduction. 

Commenters stated that the frequent tuning of the combustion system to optimize CO and fuel to 

air ratio also results in reduced unburned carbon, lower excess air, lower heat rate, and mitigates 

excessive slagging. Commenters stated that when the FGDs were installed, the Station also 

improved their controls to a DCS system which allowed for the implementation of NN in the 

future to automate a portion of the work performed by the "tuning team", if necessary. 

Commenters stated that however, since the operating utility regularly has a burner management 

team optimize the boiler operation, it is not expected that NN would provide any further heat rate 

benefit. 
40

Commenters presented information with regard to STATION B - BOILER ISLAND, NEURAL 

NETWORK. Commenters stated that computer models, known as neural network (NNs) 

simulate the power plants at various static and dynamic loads, with the predicted performance 

results correlated to several real-time process measurements and that neural network control 

systems can be used to optimize emissions such as NOX and CO, as well as help optimize boiler 

efficiency. Commenters stated that no unit at Station B has NN installed but that the current 

group of burner/boiler engineers has OEM experience. Commenters stated that these engineers 

have completed parametric testing that has helped optimize boiler operation. Commenters stated 

that the boiler optimization has also helped provide consistent unburned carbon levels which are 

required for ash sales. Commenters stated that Unit B1 and B2 typically have only 1% unburned 

carbon. Commenters stated that the frequent tuning of the combustion system to optimize CO 

and fuel to air ratio results in these unburned carbon levels and a lower heat rate. Commenters

stated that Unit B3 does not sell fly ash. Commenters stated that due to the station's employment 

of best operational and maintenance practices, it is not expected that any heat rate benefit would 

be achieved with the installation and operation of a NN system. 

Commenters stated that we need to have new fuels, not just the ones that have been around and

we also need to have engines that are modified. Commenters stated the only thing you need to 

change in an internal combustion engine is the controls, electronic controls -- we have them. 

Commenters stated that they've had the space program with a lot of technology but it's not 

implemented and it needs to be implemented. 

Commenters stated that Big Stone Plant made DCS upgrades in 1996 and 2011. Commenters

stated that specific reasons for performing the 2011 upgrade included obsolescence of the 

previous controls, the knowledge that additional emissions controls requiring advanced DCS 

would likely be needed in the future, the ability to better optimize plant performance, and the 

ability to better respond to system load demand in the face of today's changing energy supply 

market (largely driven by increased renewables in the region). Commenters stated that improved 

ability to respond to system load allows Big Stone Plant to move the unit to different set points at 

higher ramp rates and to maximize the ability to control emissions during these periods. 

Commenters stated that combustion neural networks were installed on all the Big Bend Station

coal units (multiple types and manufacturers) as part of a U. S. Department of Energy NETL 

project during 2002 through 2004. Commenters stated that after implementation of the 

automated systems, operator training was found to be more effective. Commenters stated that 

controls on all Big Bend Station unit boilers have been upgraded to Distributed Controls Systems 

and these DCS systems have sophisticated control schemes that help optimize boiler combustion. 

Commenters stated that computer models, known as neural networks (NN's) control the power

plants' operation at various static and dynamic loads, with the performance results correlated to 

several real-time process measurements. Commenters stated that neural network control systems 

can be used to optimize emissions such as NOX and CO, as well as help optimize boiler 

efficiency. Commenters stated that Units 1 and 2 were converted to a Foxboro DCS system in 

2004 and 2005 from an L&N control system and since then, component replacements have been 

made to keep the system up to date. Commenters stated that these two units are regularly tuned 

for NOx and CO using the DCS and available CEMS readings for excess air, O2, CO, and CO2. 

Commenters stated that the low NOx burners and secondary overfire air systems on Units 1 and 
41

2 are adjusted accordingly for NOx control. Commenters stated that TEP is currently operating 

their Foxboro DCS systems for optimizing their NOx and CO emissions and maintaining boiler 

efficiency. Commenters stated that Units 3 and 4 are also equipped with Foxboro DCS system 

but utilize SCR technology for NOx control. Commenters stated that TEP currently has an active 

plan in place for information adjusted, automated fine-tuning of the boilers and is currently using 

best operating and maintenance practices for controlling NOx and CO using the existing system 

and available CEMS readings for excess air, O2, CO, and CO2; as such, no additional heat rate 

improvements can be achieved. 

Comment 8: Comments regarding efficiency gains from intelligent sootblowers (ISBs)

Response 8: The response to this comment is addressed by the response to Comment 1 in this

section. 

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

Commenters addressed Intelligent Sootblowers (ISB) and stated that S&L reports that ISB

systems may improve boiler efficiency by 0.3-0.9 percent but however, the study notes that heat 

rate reductions from neural networks and ISB are not necessarily cumulative. Commenters stated 

that because ISB systems are used primarily with lower rank sub-bituminous coal, such as 

Wyoming Powder River Basin (PRB) coal, and lignite fuels, ISBs are not applicable to the 

boilers that combust pulverized bituminous coal in West Virginia and therefore, any future 

reduction in heat rate with respect to the installation of ISB systems is not achievable for West 

Virginia EGUs.

Commenters listed limitations that should be accounted for and a site specific analysis may

reveal additional limitations:

Intelligent sootblower (ISB) system

• Many units are forced to continuously use their sootblowers to keep the back end 

of the boiler from slagging. Operation in intelligent mode will provide little HRI 

benefit on these units.

• The benefits from ISB and NN are not additive.

Commenters stated that Black Hills agreed to the potential for intelligent soot blowers (S&L 2.4) 

at all four of its plants, with anticipated savings of 35 to 41 Btu/kWh (the lower end of the S&L 

range). Commenters stated that PacifiCorp has scheduled this improvement at Wyodak for 2022. 

Commenters stated that at Naughton 1, the boiler is cleaned using existing procedures and there 

is no room for improvement; similarly, at Dave Johnston 1 and 2 there is not a significant 

problem. Commenters stated that intelligent soot blowers are scheduled for installation in Dave 

Johnston 3 in 2018 and Dave Johnston 4 in 2016. Commenters stated that intelligent soot 

blowers were installed in all four units of Jim Bridger in 2006; and that Naughton 2 installed a 

soot blower in 2009 which was re-commissioned in 2013. Commenters stated that Naughton 3 

will be converted to gas in 2018.
42

Commenters stated that the use of intelligent soot blower (ISB) systems for improving system 

efficiency also enhances the performance of the furnace and longevity of the tubing material, 

while minimizing cycling effects to the steam turbine and that the ISB system functions by 

monitoring both furnace exhaust gas temperatures and steam temperatures to identify affected 

areas that require soot blowing. Commenters stated that the units at Station A are also not 

equipped with ISB systems but that Unit A1 is currently equipped with water cannons and 

sootblowers in their boiler; however, there is no intelligent portion to either. Commenters stated 

that the sootblowers are operated on a continuous cycle due to the heavy slagging/fouling that is 

experienced. Commenters stated that Unit A2 is also equipped with sootblowers and water 

cannons and that Six Diamond Power sootblowers were added during the FGD installation. 

Commenters stated that the water cannons that are installed have an integrated intelligent 

operation option, but they do not operate in the intelligent mode, due to the heavy slagging that is 

experienced and that therefore, the addition of intelligent cleaning systems resulted in no heat 

rate improvement on Unit A2. Commenters stated that the current non-intelligent and intelligent 

sootblowing systems at Station A are required to operate on a consistent frequency to keep the 

back end tubes from fouling/slagging too much and that because of this, no additional benefit is 

predicted if the units were to install and regularly operate the intelligence feature.

Commenters presented information with regard to STATION B - BOILER ISLAND -

INTELLIGENT SOOTBLOWER SYSTEM. Commenters stated that the use of intelligent soot 

blower (ISB) systems for improving system efficiency enhance the performance of the furnace 

and longevity of the tubing material, while minimizing cycling effects to the steam turbine. 

Commenters stated that the ISB system functions by monitoring both furnace exhaust gas 

temperatures and steam temperatures to identify affected areas that require soot 

blowing. Commenters stated that the units at Station B are not equipped with ISB systems but 

are equipped with compressed air sootblowers, which are used almost constantly at full load. 

Commenters stated that the low NOx burners (LNB) and over fire air (OFA) are the causes of 

heavy slagging/fouling of the backend. Commenters stated that the units are already equipped 

with sootblowers that operate almost continuously at full load operation and it is not predicted 

that the incorporation of an intelligence portion would provide heat rate reduction.

Commenters stated that in 2011 Big Stone Plant installed an intelligent soot blower system in

conjunction with a DCS upgrade. Commenters stated that efficiency improvement from this 

project was small, primarily because Big Stone Plant's boiler was originally designed for lignite 

coal. Commenters stated that lignite boilers are designed to handle greater quantities of ash and 

ash slagging is not a major issue at Big Stone Plant, particularly after a fuel switch to 

subbituminous coal in 1995. 

Commenters stated that Tampa Electric has implemented soot blower optimization technology

on all units at Big Bend Station. 

Commenters stated that the use of intelligent soot blower (ISB) systems for improving system

efficiency also enhances the performance of the furnace and longevity of the tubing material, 

while minimizing cycling effects to the steam turbine. Commenters stated that the ISB system 

functions by monitoring both the furnace exhaust gas temperatures and steam temperatures to 

identify affected areas that require soot blowing. Commenters stated that in order to attempt 

knowledge-based soot blowing, they first installed strain gauges, which ultimately did not 
43

provide any benefit. Commenters stated that following that, they explored the use of water 

cannons with smart flux sensors for the system to teach itself when to operate, the duration of 

operation, and to determine appropriate water pressures. Commenters stated that these were 

taken out of service once the operators observed that the water cannon system had detrimental 

effects on the tubing. Commenters stated that the current soot blowing systems are separate PLCdriven control systems, which were provided by Clyde-Bergemann for Units 1 & 2 and Diamond 

Power for Units 3 & 4. Commenters stated that attempts were made to implement an ISB system 

in addition to exploring an alternate water cannon method. Commenters stated that however, due 

to the ISB system providing no operational benefit and the water cannons damaging tubing, they

currently utilize operator-driven retractable soot blowers, when heat trends and observed buildup 

deems them necessary. Commenters stated that they are currently employing best operating and 

maintenance practices so no additional heat rate improvements can be achieved. 

Comment 9: Comments regarding thermal efficiency increase from air heaters 

Response 9: The response to this comment is addressed by the response to Comment 1 in this 

section. 

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

Commenters stated that one of the most effective ways to reduce fuel consumption in the EGU

process is the pre-heating of combustion air, that the primary objective of the process is to 

increase thermal efficiency and that small increments of efficiency improvements in the APH 

result in substantial reductions of net fuel consumption and parasitic loads. Commenters stated 

that in the context of the EGU, the purpose of the APH is to recover the heat from boiler flue gas 

to increase the thermal efficiency of the boiler. Commenters also stated that the system serves as 

the last 'heat trap' in the boiler system and accounts between 5% to 10% of a plant's thermal 

efficiency. Commenters stated that while APH designs vary, combustion air typically passes over 

or through metal tubes or plates that have been heated by the exhaust flue gas created during the 

combustion process and transfers heat and energy that would otherwise be wasted. Commenters 

stated that APH are utilized in a variety of boiler systems including those relying on natural gas, 

oil, waste to energy, and biomass as a fuel source. 

Commenters stated that by increasing the temperature of combustion air through the pre-heating 

process, the boiler requires less heat and less fuel to obtain the desired combustion and 

production. Commenters stated that increasing the temperature of the combustion air also results 

in higher temperatures at the top of the boiler. Commenters stated that as a result, steam 

contacting the turbine contains additional energy which reduces the fuel required to achieve 

desired production.

Commenters stated that a properly maintained APH assists in the process of ensuring that gas

and particulate matter entering pollution control systems fall within their designed temperature, 

velocity, and volumetric parameters. Commenters stated that this not only improves the 

efficiency of the individual systems but also reduces failure rates and maintenance costs.
44

Comment 10: Comments regarding efficiency increase from acid dew point control

Response 10: The response to this comment is addressed by the response to Comment 1 in this 

section. 

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

Commenters addressed Air Pre-Heaters and stated that S&L reports that regenerative air preheaters that receive improvements to seals may decrease heat rate by 10-40 BTU/kWh, which 

translates to a maximum 0.38 percent improvement in boiler efficiency. Commenters stated that 

the study also suggests that controlling acid dew point may improve heat rate by 50-120 

BTU/kWh, which equals a maximum of 1.15 percent increase in boiler efficiency. Commenters

stated that most EGUs in West Virginia have upgraded or replaced regenerative air pre-heaters 

during recent installation of pollution control devices and similarly, because West Virginia 

EGUs have ammonia injection systems through the installation of SCR, these sources also 

control the acid dew point. Commenters stated that therefore, EGUs in West Virginia have 

already achieved available increases in boiler efficiency from these heat rate reduction methods. 

Commenters listed limitations that should be accounted for and a site specific analysis may

reveal additional limitations:

Air heater acid dew point reduction

• Units with DSI already installed downstream of the air heater, due potentially to 

avoiding plugging, cannot implement this technology.

• Most of the high sulfur bituminous coal with SCRs already have installed this 

technology and those systems are optimized for SO3 emission rather than HRI

• Units burning PRB coal or lignite will have sufficient alkali in the form of CaO 

which allows absorption of SO3 before and in the air heater thus permitting 

operator to operate at lower dew point. Acid dew point reduction technology is 

therefore not applicable for units burning PRB and lignite.

Commenters addressed Lower Air Pre-Heater Outlet Temperature by Controlling Acid Dew 

Point. Commenters stated that the air heater outlet temperature typically is controlled at 20-30 

degrees F above the sulfuric acid dew point to minimize corrosion of cold-end baskets and that to 

enable lower air heater outlet temperatures, dry sorbent injection (DSI) can be installed in order 

to remove SO3 and lower the acid dew point temperature. Commenters stated that this 

technology is generally applied to medium- to high- sulfur fuel applications and that the units at 

Station A used to fire a low-sulfur PRB blend; however, during the integration of the WFGD 

systems, the design incorporated a large range of medium- to high- sulfur fuels. Commenters

stated that because of this, both units are equipped with dry sorbent injection for sulfuric acid 

mist (SAM) reduction prior to the FGD. Commenters stated that prior to 2005, some of the air 

heater baskets were removed from Unit A2, due to unit performance issues. Commenters stated 

that they were later reinstalled to lower the APH outlet temperature and are now back to design 

capacity. Commenters stated that Unit A1 uses APH steam coils and Unit A2 uses glycol heaters 
45

to get the air side temperatures back up to design and that the steam coils and the glycol heater 

were replaced in kind during the FGD project. Commenters stated that air heater baskets were 

also removed in Unit A2 prior to 2005 due to the high oxidation across the SCR and that the 

elimination of the baskets helped increase the outlet flue gas temperature to above the acid dew 

point when high SO2 and SO3 concentrations were present. Commenters stated that the SCR 

catalyst was eventually replaced with low oxidation catalyst that limits the amount of SO2 to 

SO3 oxidation that occurs over each catalyst layer. Commenters stated that most of the baskets 

were eventually reinstalled before 2012, due to having insufficient heat transfer after the 

economizer surface was split before 2005; the unit is now close to original design temperatures. 

Commenters stated that at the high sulfuric acid dew point associated with the fuel fired, air 

heater outlet temperatures are typically controlled to stay above 305 degrees F. Commenters

stated that operators have a dew point curve that they use for guidance to optimize boiler 

performance, while maintaining sufficient margin above the dew point. Commenters stated that 

there is also a cap on air heater outlet flue gas temperature due to the injection of Trona 

downstream of the air heater. Commenters stated that temperatures above 350 degrees F could 

result in the formation of sodium bisulfate which is difficult to remove from downstream 

surfaces as well as collecting plates, thus impacting ESP performance; therefore, the maximum 

air heater gas outlet temperature is set at 350 degrees F. Commenters stated that sorbents can 

sometimes be injected upstream of the air heaters, which would eliminate the need to monitor air 

heater temperatures from an acid dew point standpoint; however, the DSI testing completed on 

the units concluded that Trona injection downstream of the air heaters was optimal for those 

units, due to air heater pluggage concerns. Commenters stated that the injection of Trona 

upstream of the air heater would have the potential to lower acid gas concentrations through the 

air heater enough to lower the outlet temperature; however, it comes with the potential risk of 

plugging the air heater baskets due to sodium bisulfate. Commenters stated that the reduction in 

flue gas temperature would increase the combustion air temperature, which increases boiler 

efficiency, but any pluggage/fouling in the APH has the potential to adversely affect operation. 

Commenters stated that since Trona injection on Unit A1 and A2 occurs downstream of the 

APH, air heater outlet temperatures cannot be reduced further. Commenters stated that the unit 

cannot take advantage of reduced acid dew point temperatures unless the Trona was injected 

upstream of the APH. Commenters stated that previous testing experience by various utilities 

suggests that the downstream location is preferred to avoid any APH plugging as well as 

provided lower reagent cost for SO3 reduction and that additionally, pre-APH injection was 

tested on the units and determined to cause detrimental pluggage after short term testing. 

Commenters stated that at this time, it is not feasible to incorporate lower air heater outlet 

temperatures by controlling acid dew point at the APH inlet; therefore, no heat rate reduction is 

feasible.

Commenters stated that the second method is lowering air pre-heater outlet temperatures by 

controlling sulfuric acid dew point with alkali injection, allows for recovery of additional heat 

into the combustion air with added heat transfer surface. Commenters stated that the air heater 

outlet temperature typically is controlled at 20-30 degrees F above the sulfuric acid dew point to 

minimize corrosion of cold-end baskets. Commenters stated that to enable lower air heater outlet 

temperatures, dry sorbent injection (DSI) can be installed in order to remove SO3 and lower the 

acid dew point temperature. Commenters stated that this technology is generally applied to 

medium- to high- sulfur fuel applications; however, the units at Station B fire low-sulfur western 

bituminous coal (sulfur content typically below 0.5 wt%). Commenters stated that since the 
46

units fire a low-sulfur fuel and are not equipped with and SCR, very low SO3 concentrations are 

present at the air heater inlet. Commenters stated that DSI equipment vendors typically do not 

guarantee SO3 emissions below 5 ppmvd at 3% O2; therefore, this technology is not 

feasible. Commenters stated that the potential for a future SCR retrofit would likely preclude 

the unit from reducing the APH outlet temperature, thereby preventing additional heat recovery.

Commenters stated that PacifiCorp generally characterized the acid dew point control (S&L

2.5.2) issue by reference to S&L's suggested remedy, which focuses on lowering outlet 

temperature by air heater modifications. Commenters stated that for Dave Johnston 3 and 4, and 

Wyodak, the modification is not feasible because the plant needs existing exit temperatures to 

operate its scrubber during winter operations. Commenters stated that for Dave Johnston 1 and 2, 

the change was uneconomical due to extensive changes that would be required for existing 

structures. Commenters stated that heaters have already been implemented in Bridger Unit 4, and 

are scheduled for the other three units from 2019 to 2022, during annual scheduled maintenance 

of individual units. Commenters stated that for Naughton Units 1 and 2, and the four Black Hills 

plants, are already operated near the acid dew point.

Commenters stated that acid dew point control is a measure designed to address an SO3

formation issue that is not applicable to Big Stone Plant because of the low sulfur subbituminous 

coal fuel source combined with the type of FGD that will be used at Big Stone Plant. 

Commenters stated that the air heater gas outlet temperatures are typically, at a minimum, 20-30

degrees F above the sulfuric acid dew point to minimize corrosion of cold-end baskets. 

Commenters stated that APH gas outlet temperature data obtained from one of their members

indicates that they operate within the margin to avoid sulfuric acid condensation. Commenters

stated that to enable lower air heater outlet temperatures, dry sorbent injection (DSI) could be 

installed in order to remove SO3 and lower the acid dew point temperature. Commenters stated 

that this technology is generally applied to medium- to high- sulfur fuel applications. 

Commenters stated that their units fire low sulfur western subbituminous coal; so both the SO3 

concentration and the acid dew point are low compared to higher sulfur bituminous coals.

Commenters stated that Units 1 and 2 do not have an SCR; as such, SO3 is formed only by 

oxidizing SO2 in the boiler. Commenters stated that testing conducted on Unit 1 in 2014 

indicated that the SO3 levels at the APH averaged below 5 ppmvd. Commenters stated that this 

data is also indicative of SO3 levels expected on Unit 2 because of identical designs of the two 

units. Commenters stated that typically, DSI vendors do not guarantee SO3 emissions below 5 

ppmvd at 3% O2; therefore, this technology is not feasible for either Springerville Units 1 or 2.

Commenters stated that the oxidative properties of SCR catalysts on Units 3 and 4 result in 

slightly higher SO3 concentrations due to SO2 to SO3 oxidation that occurs across the SCR 

catalyst. Commenters stated that based on the catalyst design of 2% SO2 oxidation across the 

SCR, and assuming all catalyst layers installed, flue gas concentrations of SO3 upstream of the 

air pre-heaters are estimated to be about 5 ppmvd at 3% O2. Commenters stated that DSI 

vendors do not guarantee SO3 emissions below 5 ppmvd at 3% O2; therefore, this technology is 

not feasible for either Springerville Units 3 or 4.

Commenters stated that it is important to note that all four units at SGS are equipped with DFGD 

technologies, which require a minimum flue gas temperature for proper operation and SO2 
47

control. Commenters stated that as a result, the inlet temperature to the DFGD vessels should not 

be reduced.

Commenters stated that in summary, lowering air pre-heater outlet temperatures at the SGS units 

is not technically feasible to avoid SO3 and HBr condensation and to maintain the operating 

efficiency of the downstream DFGD systems. 

Comment 11: Comments regarding efficiency increase controlling air heater leakage and/or 

fouling 

Response 11: We appreciate the commenters’ point about the importance of the air preheater 

(APH) to boiler thermal efficiency, and thus heat rate. Where appropriate, EGUs can improve 

thermal efficiency (and thus reduce heat rate) by identifying and repairing leaks to the APH. The 

response to the remainder of these comments is addressed by the response to Comment 1 in this 

section.

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

Commenters discussed the importance of the air preheater (APH) to recover heat from boiler flue

gas so that the boiler requires less heat and less fuel and thereby increases the thermal efficiency 

of the boiler. Commenters stated that the APH accounts for over 10% of a power plant's thermal 

efficiency. Commenters cited studies that show that a 1% increase in boiler heat rate results 

when 12% of the APH is leaking and/or blocked. Commenters recommended a rule requirement 

that APH leakage be restricted to less than 5%. Commenters also recommended that new boilers 

be required to only use recuperative (or tubular) APH which, due to their design, inherently have 

no air leakage. 

Commenters listed limitations that should be accounted for and a site specific analysis may

reveal additional limitations:

Air heater leakage Mitigation

• Many units already employ best operation and maintenance practices (BP)*, 

thereby negating further heat rate improvement.

• Some types of air heaters - rotating hood structures are more susceptible to 

warping over time, increasing air heater leakage. Even with seal replacement, 

units with this problem are unable to achieve design leakage.

• Location of air heater typically does not allow replacement with a larger low 

leakage air heater with seal-air control.

Commenters presented information with regard to STATION A- BOILER ISLAND, AIR PREHEATERS. Commenters stated that air pre-heaters are an important component of maintaining 

efficiency at a power plant and that such systems provide heat recovery to the unit by cooling the 

flue gas counter-currently with incoming pre-combustion air. Commenters stated that cooling of 
48

the flue gas transfers contributes to increased efficiency by recovering heat that raises 

combustion air temperatures and minimizes moisture in the coal prior to its combustion. 

Commenters stated that with respect to air pre-heaters' contributions to plant heat rate, two 

possible methods to improve their performance are as follows:

• Minimizing air pre-heater leakages from the air-side to the flue-gas side. High air 

pre-heater leakage raises auxiliary power requirements due to processing higher 

volumes of gas in downstream equipment, such as ID fans, and upstream 

equipment, such as FD fans.

• Lowering air pre-heater outlet temperatures by controlling sulfuric acid dew point 

with alkali injection, allows for recovery of additional heat into the combustion 

air with added heat transfer surface.

Commenters continued with minimizing Air Pre-Heater Leakage. Commenters stated that Unit 

A1 is equipped with Ljungstrom style air pre-heaters (APH) with duplex seals and that the 

current leakage rate is approximately 5-8%, which is very close to design values. Commenters 

stated that the operators inspect the APHs every 18 months and repair any problem areas along 

with replacing the seals when needed. Commenters stated that during every outage, the air 

heaters are washed to remove any particle pluggage. Commenters stated that the Unit A1 air preheater currently adds only a few Btu/kWh to the design heat rate and that it consistently achieves 

design rates after the seals are replaced and other repairs are conducted every 18 months. 

Commenters stated that with the best maintenance practices conducted on a regular basis, it is 

not expected that any further improvements would be possible to reduce unit heat rate without 

excessive capital or maintenance cost expenditure. Commenters stated that Unit A2 is equipped 

with Rothemuhle style air heaters and that this type of APH, at the time, was designed to have a 

leakage rate of around 10%; however, Unit A2 was never able to achieve this rate and generally 

operated close to 40-50% in-leakage at the end of a three-year cycle. Commenters stated that 

after APH rebuilds, the unit would only achieve approximately 20% in-leakage. Commenters 

stated that since 2012, the air heaters have been improved to include a duplex seal design, which 

results in lower in-leakage levels. Commenters stated that maximum in-leakage rates are 

approximately 30% and are as low as 10% immediately after rebuild. Commenters stated that 

similarly to Unit A1, the APHs on Unit A2 are inspected and repaired, to the best of the 

operators' ability, every 18 months. Commenters stated that rebuilds only happen during a long 

maintenance outage that occurs every three years. Commenters stated that to estimate the heat 

rate improvement achieved on Unit A2 since the incorporation of the duplex air seals, S&L 

estimated the aux power consumption prior to and after the duplex seal improvement. 

Commenters stated that S&L calculated the change in flue gas volume from the maximum air inleakage reported by station personnel down to the minimum in-leakage reported just after an air 

heater rebuild, prior to and after the improvement. Commenters stated that the decrease in flue 

gas volume reduces the FD and ID fan auxiliary power consumption rates and improves the unit 

heat rate based on a three-year average basis. Commenters pointed to Table 2-1 which compares 

the estimated flue gas volume, auxiliary power consumption, and heat rate due to the APH inleakage. 
49

Commenters stated that Station B includes a compilation of three units that were audited as part 

of this study. Unit B1, B2, and B3 are subcritical pulverized coal units that are between 300-600 

MWNET. Commenters stated that all three units are equipped with FGDs and baghouses.

Commenters stated that the first method is minimizing air pre-heater leakages from the air-side 

to the flue-gas side. Commenters stated that high air pre-heater leakage raises auxiliary power 

requirements due to processing higher volumes of gas in downstream equipment, such as ID 

fans, and upstream equipment, such as FD fans. Commenters stated that all units at Station B are 

equipped with Rothemuhle style air heaters. Commenters stated that with the discontinued use of 

the HESP on Units B1 and B2, the air heaters operate under high ash conditions, so 

improvements were made. Commenters stated that no improvements were made to the air heater 

on Unit B3. Commenters stated that the air heaters were designed for 10% in-leakage, but the 

units operate closer to 11% typically. Commenters stated that in-leakage can get up to 15% after 

three years of operation, but the rates are returned to design conditions coming out of the 

maintenance outage. Commenters stated that every three years the air heaters are maintained by 

inspection and change as required. Commenters stated that the Rothemuhle style air pre-heaters 

at Station B typically operate only a few percentages above their design rate. Commenters stated 

that after approximately three years, the leakage rate can increase to 5% above design values; 

however, these leakage rates are far below many utilities experience with this style of air heater. 

Commenters stated that the station personnel employ the best possible maintenance and 

operating practices to mitigate leakage rates on this type of air pre-heater. Commenters stated 

that the idea of converting to a low-leakage Ljungstrom air pre-heater is not necessary on this 

unit. Commenters stated that continued repair to APH components and inspection and 

replacement of seals as required will help maintain their current average in-leakage rates. 

Commenters stated that as a measure related to S&L's air heater and duct leakage control issue

(S&L 2.5.1), Black Hills recognizes the potential for an air heater sealing system upgrade, at a 

collective improvement of 11 Btu/kWh for its four units, once more toward the lower end of the 

S&L range. Commenters stated that PacifiCorp has scheduled the installation of duplex seals on 

the four units of Dave Johnston from 2015 through 2018. PacifiCorp has upgraded the seals at 

Naughton 1, but Naughton 2 and 3 were designed for low leakage and have been maintained at 

that level. Commenters stated that due to the design of air cooled Wyodak, no possible 

modification is economical. Commenters stated that pertinent modifications to Jim Bridger's four 

units are scheduled from 2015 through 2018.

Commenters stated that coal-fired EGUs use air heaters to pre-heat the combustion air for

improved combustion and overall unit efficiency. Commenters stated that Big Stone Plant air 

heater is a regenerative Ljungstrom air heater, which rotates a cylindrical shell and basketpacked rotor through counterflowing air and flue gas streams. Commenters stated that Big Stone 

Plant personnel recognize the importance of air heaters for unit efficiency and have been 

proactively replacing rotor baskets and seals every 5-10 years. Commenters stated that in 1994, 

Big Stone Plant installed an adjustable sector plate sealing system. Commenters stated that the 

seal replacement example demonstrates the fallacy in EPA's assumptions that HRIs are 

sustainable and can be performed at any time. Commenters stated that although small heat rate 

gains can be achieved by installing new seals in air heaters, those gains are unsustainable 

because the seals begin to wear from the first day of operation. Commenters stated that 
50

furthermore, contrary to EPA's assumption that seals can be replaced at any time, in reality they 

can only be replaced during major outages that typically occur every three to six years.

Commenters stated that the air heater gas outlet temperatures are typically, at a minimum, 20-30

degrees F above the sulfuric acid dew point to minimize corrosion of cold-end baskets. 

Commenters stated that APH gas outlet temperature data obtained from one of their subsidiaries 

indicates that they operate within the margin to avoid sulfuric acid condensation. Commenters 

stated that to enable lower air heater outlet temperatures, dry sorbent injection (DSI) can be 

installed in order to remove SO3 and lower the acid dew point temperature. Commenters stated 

that this technology is generally applied to medium- to high- sulfur fuel applications. 

Commenters stated that their units fire low sulfur western subbituminous coal; so both the SO3 

concentration and the acid dew point are low compared to higher sulfur bituminous coals.

Commenters stated that Units 1 and 2 do not have an SCR; as such, SO3 is formed only by 

oxidizing SO2 in the boiler. Commenters stated that testing conducted on Unit 1 in 2014 

indicated that the SO3 levels at the APH averaged below 5 ppmvd. Commenters stated that this 

data is also indicative of SO3 levels expected on Unit 2 because of identical designs of the two 

units. Commenters stated that typically, DSI vendors do not guarantee SO3 emissions below 5 

ppmvd at 3% O2; therefore, this technology is not feasible for either Springerville Units 1 or 2.

Commenters stated that the oxidative properties of SCR catalysts on Units 3 and 4 result in 

slightly higher SO3 concentrations due to SO2 to SO3 oxidation that occurs across the SCR 

catalyst. Commenters stated that based on the catalyst design of 2% SO2 oxidation across the 

SCR, and assuming all catalyst layers installed, flue gas concentrations of SO3 upstream of the 

air pre-heaters are estimated to be about 5 ppmvd at 3% O2. Commenters stated that DSI 

vendors do not guarantee SO3 emissions below 5 ppmvd at 3% O2; therefore, this technology is 

not feasible for either Springerville Units 3 or 4.

Commenters stated that it is important to note that all four units at SGS are equipped with DFGD 

technologies, which require a minimum flue gas temperature for proper operation and SO2 

control. Commenters stated that as a result, the inlet temperature to the DFGD vessels should not 

be reduced.

Commenters stated that in summary, lowering air pre-heater outlet temperatures at the SGS units 

is not technically feasible to avoid SO3 and HBr condensation and to maintain the operating 

efficiency of the downstream DFGD systems. 

Comment 12: Comments regarding efficiency improvements from burner technology 

improvements

Response 12: The response to this comment is addressed by the response to Comment 1 in this 

section. 

The following are summaries of the specific public comments under this comment:
51

Commenters stated that improved burner technology could reduce power plant emission by as

much as 80% (Web site for TKEnergizer, a supplier of heat transfer technology for various 

industry sectors, including power generation). Commenters stated that this technology is 

presently under feasibility evaluation by a source located in Waupaca County, WI. Commenters 

also stated that this source is not an operation that will be affected by regulated EPA carbon 

emission reductions. Commenters stated that however, the operation is a major CO2 emission 

source (300 K TPY) and that improved fuel burner technology at Waupaca's facility would leave 

a residual 20% CO2 emission (60 K TPY) for reclamation.

Comment 13: Comments regarding turbine overhauls, retrofits and/or upgrades

Response 13: The response to this comment is addressed by the response to Comment 1 in this

section. 

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

Commenters stated that turbine overhauls are referenced as a major heat rate improvement

method in an EPA Clean Power Plan technical support document. [Coal-Fired Power Plant Heat 

Rate Reductions (January 2009).] Commenters stated that regular turbine overhauls are generally 

not practical or economical, because these procedures require the unit to be out of service for an 

extended period of time. Commenters also stated that the power industry already has multiple 

incentives to operate units at peak efficiency (i.e., profit maximization and competitive 

advantage).

Commenters stated that steam turbine upgrades are likely the most commonly deployed heat rate

improving method, but the existing, legacy turbine can only be upgraded once. Commenters 

stated that it is unlikely a second upgrade is feasible; even if the payoff were to be smaller (as 

further evolution in blade technology is not anticipated). Commenters stated that consequently, 

many eligible units have already received steam turbine upgrades and further efficiency 

improvements for the proposed rule are unlikely.

Commenters stated that the thermal efficiency of generating power from fossil fuel plants

degrades with time, both due to component wear and changes in plant operation. Commenters 

stated that component wear is inevitable - critical tolerances increase between key components 

such as the blades of a steam turbine, and wear within pulverizers affects the distribution of fuel 

within the boiler. Commenters stated that deposits on heat transfer surfaces throughout the boiler 

and steam cycle restrict the removal of heat from combustion products and restrict the flow of 

air, water and/or flue gas through these devices. Commenters stated that for example, changes to 

the steam path can potentially provide high payoff in lowering heat rate. Commenters stated 

however, the magnitude of the benefits does not stay constant, with payoff decreasing with time 

from the "new" state, and that field data back up this assertion. Commenters presented Figure 4-1 

which depicts turbine efficiency of the H-P section of a steam turbine retrofit to a generating unit 

located in the Southeast. Commenters stated that Figure 4-1 describes the steam turbine H-P 

section extraction efficiency and the payoff in terms of the unit's heat rate may not necessarily be 

realized (depending on other impacts and/or how the unit is operated). Commenters noted that in 
52

the first 6 months the efficiency drops by about 0.5% (10 Btu/kWh), after 5 years by about 2% 

(40 Btu/kWh), and after 10 years by about 4% (80 Btu/kWh). Commenters stated that the payoff 

still persists - but decreases with time, and stated that Figure 4-1 is believed to be indicative of 

typical degradation in heat rate performance with time.

Commenters also stated that improving heat rejection can be an effective means to lower heat

rate but that results are site-specific and depend on cooling system design - particularly if cooling 

towers are employed. Commenters stated that repair or the "retubing" condensers is an option -

but this action is costly as condensers are typically located where access for construction is 

limited - elevating the cost of even simple changes. 

Commenters stated that changes to the steam path - perhaps the heat rate improving option most

frequently applied by owners - can provide attractive payoff, but the results are site-specific. 

Commenters stated that many plant owners have already deployed these retrofits to exploit stateof-art extraction technology to lower heat rate, and thus CO2 emissions and fuel cost. 

Commenters also stated that accordingly, the efficiency gains from these deployments are 

already in the "baseline" of the proposed rule.

Commenters addressed Turbine Overhaul and stated that S&L indicates that 30 year old,

degraded turbines that are upgraded with improved components can increase power generation 

by two to three percent and decrease heat rate by 10-300 BTU/kWh, which equals a significant 

2.89 percent increase in boiler efficiency. Commenters stated that most EGUs in West Virginia 

that are not scheduled to permanently shut down have, through scheduled overhauls, already 

replaced or upgraded their turbines with improved components and that therefore, any substantial 

future reduction in heat rate with respect to upgraded turbines is generally not achievable for 

West Virginia EGUs.

Commenters stated EPA has assumed that projects to improve heat rate, once complete, can be

sustained through 2029, which is improbable. Commenters stated that one example is 

replacement of original turbine steam path components with state of the art technology (turbine 

replacement). Commenters stated that the Sargent & Lundy report identifies this measure as the 

one which offers the greatest potential benefit, in the range of 100 to 300 Btu/kWh. TSD, p. 2-8. 

Commenters stated that a General Electric technical document, "Steam Turbine Sustained 

Efficiency," GER-37 50C, includes a figure depicting the typical progression of heat rates 

following installation; that best results will be achieved when the turbine is brand new and must 

meet manufacturer specifications on commissioning; that heat rate rises thereafter with use, with 

partial recovery of the original rate after first overhaul; that the pattern recurs with subsequent 

use and overhaul, each time recovering only partially from the preceding overhaul.

Commenters stated that the illustrated five-year cycle is not the same for all plants and that for 

practical and economic reasons, turbine overhauls are integrated into unit major maintenance 

overhaul cycles and return only a fraction of the heat rate improvement that a turbine 

replacement project (i.e., new technology) does. Commenters stated that as an example, the four 

units at PacifiCorp's Jim Bridger EGU undergo plant-wide major maintenance overhauls in four 

year cycles, with turbine overhauls being made at 8 or 12 year intervals, depending on turbine 

performance and the economics of the specific measures.
53

Commenters stated that turbine replacement projects for individual units of the type that Sargent 

& Lundy refers to are justified on a case by case basis, as they entail extended planning, detailed 

design, long lead-time component manufacture, and significant expenditures. Commenters stated 

that PacifiCorp completed turbine steam path replacement projects at Jim Bridger Units 1 and 2 

in 2010 and 2013, respectively. Commenters stated that turbine replacement projects at Units 3 

and 4 are not currently planned. Commenters stated that it is worthwhile noting that in 2015 and 

2016, Units 3 and 4 are being retrofitted with SCRs for regional haze compliance. Commenters 

stated that the problem of heat rate degradation during the fifteen year cycle of the proposed rule 

is in the very nature of operating a coal-fired EGU and that it is a problem EPA seems to have 

either overlooked or ignored

Commenters stated that for this particular fleet of coal fired steam turbine units they offer 80+

years of experience designing, servicing, and upgrading fossil units and over the past 10-15 years 

one of the major upgrade offerings they developed is the DensePackTM technology which 

improves the thermal performance of the units in the HP and IP turbine steam paths by 

minimizing aerodynamic losses and leakages. Commenters stated that given the maturity of this 

technology there are a large number of their units today which already have this technology 

installed. Commenters stated that it's estimated that >75% of their large fossil steam turbine fleet 

already has this technology through either them or similar technology from other OEMs. 

Commenters stated that in some cases customers have opted to not upgrade existing plants using 

DensePackTM technology. Commenters stated that also, they offer Advanced Steam Path 

(ADSP) retrofits for the HP/IP and LP sections of the steam turbine as a lower cost alternative to 

the DensePackTM, but with lower performance improvement entitlement. Commenters stated 

that given the high number of units with existing heat rate improvement technology installed the 

average value remaining in the fleet for improvement is estimated at 1%. Commenters stated that 

the US coal fleet began HP/IP section upgrades in 2000 and that these early upgrades have aged 

and might have additional HRI potential today.

Commenters stated that in addition to the current upgrade technology they are taking steps to 

apply advanced technology to the existing fleet that would offer an estimated 1- 2% heat rate 

improvement. Commenters stated that most of this technology has been deployed with new 

designs and given that the technology is new to the existing fleet, a significant portion of the fleet 

would be eligible for the advanced technology however the application would be heavily 

weighted on the required capital investment. Commenters stated that because of this, the age of 

the assets and the useful remaining life in the equipment/plant will be a critical factor in 

determining the potential for this type of investment.

Commenters further stated that only two turbines (Sargent & Lundy, Section 3.1, hereafter S&L

3.1) in the Wyoming fleet may satisfy the economic criterion for replacement between now and 

2020, and neither is currently planned. Commenters stated that in all other cases, the plants are 

new; the turbines have recently been replaced; or the plant is too old to replace or refurbish the 

turbines and recover costs. Commenters stated that the replacement of those two turbines - again, 

the highest impact item on the Sargent & Lundy list - has already been accounted for in their

estimate.

Commenters listed limitations that should be accounted for and a site specific analysis may

reveal additional limitations:
54

Turbine overhaul and upgrade

• Units that have been upgraded or commissioned after 1995 generally have 

modern turbine packing/technology, thus limited benefit would be gained from 

further improvement.

• Due to large size of LP turbine section, and limited impact in comparison with the 

HP section, improvement is typically outweighed by performance payoff. 

Therefore, this improvement is not typically performed for heat rate purposes.

Commenters presented information with regard to STATION A - TURBINE ISLAND, 

TURBINE OVERHAUL. Commenters stated that technological advancements have improved 

the efficiency and longevity of steam turbines compared to the turbines that were originally 

installed in many older units. Commenters stated that advanced design tools, such as CFD have 

significantly enhanced turbine design capabilities that have led to increases in turbine efficiency 

and that additionally, the fabrication of increasingly complex geometric components has been 

developed to streamline design and efficiency. Commenters stated that the turbines at Units A1 

and A2 are both unique turbines because Unit A1 was built originally as a double reheat unit to 

enhance its efficiency above the standard single reheat design and Unit A2 was designed to be 

exactly half the size of the turbine sections of a large supercritical unit. Commenters stated that 

due to the complexity of a retrofit, neither unit has undergone significant turbine improvements 

to date. Commenters stated that Unit A1's double reheat cycle was modified in the early 1990s to 

remove the stops and intercepts, but no heat rate improvement was reported. Commenters stated 

that the HP/IP section was rebuilt between 2005-2012, but it did not achieve the efficiency 

improvement claimed by the original equipment manufacturer (OEM). Commenters stated that 

actual improvement was approximately half that predicted by the OEM, or approximately 1.5%. 

Commenters stated that the LP section has not yet been improved on the unit, but the predicted 

future improvement is approximately 0.5%. Commenters stated that the Unit A2 turbine has 

experienced expansion issues and vibration problems and that due to leakage problems, the 

turbine's mid-span packing was modified to regain design performance. Commenters stated that 

the station has also planned an improvement of Unit A2 LP section in 2022 with a budgetary 

estimate in the range of $15 million. Commenters stated that the OEM has projected a maximum 

value of 2.5% heat rate improvement immediately after the project is completed and that in 

addition, station personnel have requested budgetary quotes for the improvement of the HP and 

IP sections of the Unit A2 turbine. Commenters stated that the OEM that was contacted for this 

project has estimated another 2.5% improvement immediately after the project at a budgetary 

estimate of $25 million. Commenters stated that while the total improvement could be as high as 

5% immediately after the upgrades, it is unlikely that this increase is sustainable. Commenters 

stated that due to the large difference in predicted efficiency improvement and actual efficiency 

improvement on Unit A1, it is assumed that, similar to Unit A1, approximately only 2% 

sustainable improvement is feasible.

Commenters presented information with regard to STATION B - TURBINE ISLAND, 

TURBINE OVERHAUL Commenters stated that technological advancements have improved 

the efficiency and longevity of steam turbines compared to the turbines that were originally 

installed in many older units and that advanced design tools, such as CFD modeling, have 

significantly enhanced turbine design capabilities that have led to increases in turbine efficiency. 
55

Commenters stated that additionally, the fabrication of increasingly complex geometric 

components has been developed to streamline design and efficiency. Commenters stated that as 

part of a large environmental improvement project, Units B1 and B2 completed turbine 

maintenance that helped improve unit efficiency slightly and that the improvement helped 

decrease the overall unit heat rate after the project by 214 and 183 Btu/kWh for Units B1 and B2, 

respectively. Commenters stated that all three units at Station B have made improvements to the 

HP/IP and LP turbine sections during the past 10 years. Commenters stated that based on 

monthly heat rate and unit efficiency historical data provided prior to and after the Unit B3 

turbine improvement, it was estimated that on average an approximate 180 Btu/kWh heat rate 

improvement was achieved per unit. Commenters stated that similar heat rate data was not 

provided for the Unit B1 and B2 improvements; however, gross load data was provided prior to 

and after the improvement, which estimates approximately 355 Btu/kWh heat rate reduction, per

unit. Commenters stated that these turbine improvements on all three units utilized the most 

technologically advanced turbine packing and no further improvements are expected for the 

units.

Commenters stated that as noted in the 2009 Sargent & Lundy Report, "[f]or the average unit

that has undergone an upgrade, and is approximately 500-MW and 30 years old, the typical 

performance improvements of the high-pressure (HP) and low-pressure (LP) units range from 2-

3%pt and the intermediate pressure (IP) units range from 1-2%pt, totaling 2-3% in overall power 

generation. Commenters stated that these upgrades take into account the loss in performance 

over time (degradation)" Commenters stated that again, Otter Tail agree with the Sargent & 

Lundy report. Commenters also stated that however, turbine overhauls have been performed 

proactively throughout the industry to improve plant efficiencies, and Big Stone Plant is no 

exception. Commenters stated that the LP portion of the Big Stone Plant turbine was replaced in 

1996, and the HP/IP portion was replaced in 2005 and therefore, this project is not available in 

the future at Big Stone Plant. 

Commenters stated that technological advancements have improved the efficiency of steam

turbines compared to the turbines that were originally installed in many older units. Commenters 

stated that advanced design tools, such as computational fluid dynamics (CFD) have 

significantly enhanced turbine design capabilities that have led to increases in turbine efficiency. 

Commenters stated that additionally, the fabrication of increasingly complex geometric 

components has been developed to streamline design and efficiency.

Commenters stated that they invested in new high pressure (HP) and intermediate pressure (IP) 

components, mainly new inner blocks and rotors, for Unit 1 in 2009 and by performing these 

turbine component replacements, they reported that the unit was able to improve its heat rate by 

approximately 7 MW, or 1.8%. Commenters stated that similarly, Unit 2 had new HP/IP 

components installed in 2007, also with new inner blocks and rotors. Commenters stated that in 

Q1 of 2014, they made improvements to the low pressure (LP) components on Unit 2. 

Commenters stated that they reported that the overall heat rate gain on Unit 2 from HP, IP, and 

LP component replacements was approximately 20 MW, or 5.2%. Commenters stated that it is 

expected that similar component replacements in the Unit 1 turbine LP section could offer an 

additional 10 MW, or 2.6% in heat rate improvements.
56

Commenters stated that Units 3 and 4 have commercial operating dates of 2006 and 2009, 

respectively. Commenters stated that as the units are fairly new, no heat rate gains can be 

expected from making improvements to the turbines on these two units. Commenters stated that 

they follow best operating and maintenance practices in performing turbine overhauls on an 8 to 

10 year cycle. 

Commenters stated that for Unit 2, changes to the LP sections yielded similar heat rate 

improvements following changes made to the HP/IP sections. Commenters stated that it was 

assumed that a similar trend would be observed following changes to turbine components on 

Unit 1. Commenters stated that this evaluation assumes that the heat rate improvements from LP 

section changes on Unit 1 would be the same as what was observed following the HP/IP section 

improvements. 

Comment 14: Comments regarding heat rate improvements from feedwater heaters

Response 14: The response to this comment is addressed by the response to Comment 1 in this 

section. 

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

Commenters addressed Feedwater Heaters and stated that the S&L study indicates that

increasing feedwater heating surface area in feedwater heaters can improve boiler efficiency but 

that the study also notes that such modifications are cost-prohibitive. 

Commenters listed limitations that should be accounted for and a site specific analysis may

reveal additional limitations:

Feedwater heater - Heating surface could be added to improve efficiency; however high capital 

cost is required for a relatively small incremental reduction in heat rate.

Commenters presented information with regard to STATION A - TURBINE ISLAND, 

FEEDWATER HEATERS. Commenters stated that feedwater heaters are used within a power 

plant's thermal cycle to improve overall efficiency by recovering as much heat as possible into 

the boiler feedwater. Commenters stated that the number and placement of feedwater heaters are 

determined during the original plant design and are highly integrated with the overall 

performance of the steam turbine and the heat used to increase the feedwater temperature is 

supplied directly from the thermal cycle in the form of steam extracted at various turbine 

sections. Commenters stated that in the case of Station A, the station replaces or retubes the 

feedwater heaters in order to maintain overall unit performance. Commenters stated that the Unit 

A1 feedwater heater was replaced in-kind in the 1990s and that the Unit A2 LP heater was 

retubed in-kind and the HP heater is due for replacement in 2019. Commenters stated that regular 

pluggage and/or corrosion have not been a concern for either unit. Commenters stated that 

replacement of the feedwater heaters maintains unit performance with the original design. 

Commenters stated that with no reduction or increase in duty, the change to heat rate is 

considered to be 0% and because the units already perform best operating and maintenance 

practices on the feedwater heaters, no other improvements are considered to be feasible for 

future heat rate reductions.
57

Commenters presented information with regard to STATION B - TURBINE ISLAND, 

FEEDWATER HEATERS. Commenters stated that feedwater heaters are used within a power 

plant's thermal cycle to improve overall efficiency by recovering as much heat as possible into 

the boiler feedwater. Commenters stated that the number and placement of feedwater heaters are 

determined during the original plant design and are highly integrated with the overall 

performance of the steam turbine. Commenters stated that the heat used to increase the feedwater 

temperature is supplied directly from the thermal cycle in the form of steam extracted at various 

turbine sections. Commenters stated that Unit B2's feedwater heater has been maintained through 

the replacement of like-kind components but no heat rate reduction was experienced and the 

units already perform best maintenance practices on the feedwater heaters, thus no other 

improvements are feasible for heat rate reductions.

Commenters stated that feedwater heaters are used within a power plant's thermal cycle to

improve overall efficiency by recovering as much heat as possible into the boiler feedwater. 

Commenters stated that the number and placement of feedwater heaters are determined during 

the original plant design and are highly integrated with the overall performance of the steam 

turbine. Commenters stated that the heat used to increase the feedwater temperature is supplied 

directly from the thermal cycle in the form of steam extracted at various turbine sections. 

Commenters stated that the Springerville units perform regular maintenance on feedwater heaters 

in order to maintain performance near the original design; note, no leaks have been observed 

throughout the life of the feedwater heaters. Commenters stated that with no reduction or 

increase in duty, the change to heat rate is considered to be 0%. 

Comment 15: Comments regarding heat rate improvements from condensers

Response 15: The response to this comment is addressed by the response to Comment 1 in this 

section. 

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

Commenters addressed condensers and stated that the S&L study notes that effective operation

of a steam surface condenser can provide a significant decrease in heat rate, and regular cleaning 

of the condenser can reduce the heat rate by 30-70 BTU/kWh, which translates to a maximum 

boiler efficiency increase of 0.67 percent. Commenters stated that diligent maintenance programs 

already in place measure condenser backpressure, and such programs ensure that all West 

Virginia EGUs adhere to a regular condenser cleaning schedule and that therefore, this method 

of heat rate reduction would not improve the heat rate for existing EGUs. 

Commenters stated that PacifiCorp implemented modifications to Wyodak's condenser (S&L

3.3) in 2011. Commenters stated that Black Hills considered adding five fans to its air cooled 

configuration, but found that doing so did not improve the heat rate. Commenters stated that 

PacifiCorp determined the condensers at Dave Johnston 1 and 2 were performing well, so no 

modifications were warranted. Commenters stated that it also determined that fouling in Dave 

Johnston 3 had been reduced by introducing stainless steel tubing in 1990, and concluded further 

changes were not economical. Commenters stated that in a similar situation at Dave Johnston 4, 
58

modified in 1987, PacifiCorp may clean more frequently, i.e., quarterly rather than biannually. 

Commenters stated that PacifiCorp replaced the original copper tubes of the four Jim Bridger 

units with titanium from 1996 through 1999, and no further changes are contemplated. 

Commenters stated that changes at Naughton 1 and 2 are not economical in view of its 2029 

retirement date, and Naughton 3 will be converted to gas in 2018.

Commenters listed limitations that should be accounted for and a site specific analysis may

reveal additional limitations:

Condenser

• Many units already employ BP*, thereby negating further heat rate improvement. 

(*Note: If a unit employs best operational and maintenance practices (BP) 

currently, the HRI method may not be applicable for further improvement. 

However, these practices must be continued for the life of the unit to maintain 

current heat rate levels)

• Units with recently improved mechanical cleaning systems will not significantly 

benefit from condenser cleaning.

Commenters presented information with regard to STATION A - TURBINE ISLAND, 

CONDENSER. Commenters stated that by lowering the condensing temperature, the 

backpressure on the turbine is lowered, which increases its efficiency. Commenters stated a 

condenser degrades primarily due to fouling of the tubes, plugs in failed or thin wall tubes, and 

air in-leakage and that tube fouling leads to reduced heat transfer rates, plugged tubes reduce 

circulating water flow and heat transfer surface, and air in-leakage directly degrades heat transfer 

through the tubes. Commenters stated that the Station A maintenance program consists of 

routinely inspecting and cleaning the condenser during outages on a three-year cycle, with 

touchups after 18 months in order to maintain condenser performance. Commenters stated that 

the condensers have been replaced with in-kind tubing and continue to use materials with copper. 

Commenters stated that Unit A1 has looked into material replacement in the future; however, 

they have not experienced debilitating problems with their once through cooling cycle. 

Commenters stated that Unit A2 completed a partial re-tube in the early 2000s, with the 

remaining re-tubing scheduled for 2019. Commenters stated that the copper has not been an issue 

on Unit A2, due to the closed loop cycle. Commenters stated that the Station also monitors air inleakage online to prevent unnecessary impairment of condenser performance and that their cycle 

chemistry on both units is run so tight, that small leaks could cause operating problems. 

Commenters stated that by including routine maintenance, monitoring for in-leakage online, and 

by controlling water quality to minimize fouling, Station A has incorporated all technologies that 

can improve and maintain system performance. Commenters stated that the personnel at the 

station know that good condenser operation is ideal for maintaining heat rate performance and 

therefore, no other improvements to the condenser will reduce plant heat rate at Station A.

Commenters presented information with regard to STATION B - TURBINE ISLAND, 

CONDENSER. Commenters stated that by lowering the condensing temperature, the 

backpressure on the turbine is lowered, which increases its efficiency. Commenters stated that a 

condenser degrades primarily due to fouling of the tubes and air in-leakage and then tube fouling 
59

leads to reduced heat transfer rates, while air in-leakage directly degrades the quality of the 

water, however, if a closed cooling system is used, cooling water quality can be controlled to a 

much higher degree. Commenters stated that the condenser tubing material on all three units has 

undergone improvements during the past 15 years and that since the improvements, the units 

experience the same performance, but all pluggage of tubes has been eliminated. Commenters 

stated that no heat rate reduction was experienced from the improvement. Commenters stated 

that one potential reason why the improvements did not provide any heat rate reduction is 

because of the regular condenser cleanings. Commenters stated that the station personnel use 

scrappers with water and air hydroblast as their method to clean the condenser tubes. 

Commenters stated that the cleaning and minor maintenance typically happens during an outage 

every three years. Commenters stated that the closed-loop cooling systems on all three of these 

units are monitored rigorously for tube leaks. Commenters stated that the chemistry is controlled 

tightly and the oxygen levels are monitored closely and when chemistry starts to deviate, helium 

leak detection is used. Commenters stated that the leaks are then repaired/addressed when they 

are found. Commenters stated that by including regular maintenance, improving materials of 

construction, monitoring leakage, and by controlling water chemistry, Station B has incorporated 

all technologies that can improve and maintain system performance, therefore, no other 

improvements to the condenser will reduce plant heat rate at Station B.

Commenters stated that Big Stone Plant personnel have always recognized the importance of

maintaining condenser efficiency because this is the largest heat exchanger in a coal-fired EGU. 

Commenters stated that plant engineers diligently monitor turbine cycle performance by tracking 

such parameters as cooling water temperature and backpressure for any indication of condenser 

plugging or fouling. Commenters stated that Big Stone Plant is unusual in that it uses a 340-acre 

closed-cycle cooling pond system to cool its condenser and this system enables Big Stone Plant 

to minimize condenser debris and control water chemistry so as to prevent tube fouling. 

Commenters stated that Big Stone Plant also proactively installed stainless steel condenser tubes 

in 2007. Commenters stated that compared to other commonly used metals, such as copper alloy, 

stainless steel tubes decrease the need for routine mechanical cleaning and offer optimum 

corrosion and biofouling resistance. Commenters stated that the Sargent & Lundy report 

recognizes this by stating: "Today's condensers are designed more efficiently to reduce 

circulating water pressure drop and to enhance the cooling and condensing of the steam turbine 

exhaust. Commenters stated that the materials of construction are more resilient towards erosion 

from cleaning and corrosion. Commenters stated that additionally, the newly designed 

condensers can reduce stress induced failure due to cycling service." No additional heat rate 

improvements can be achieved at Big Stone Plant through condenser cleaning measures. 

Commenters stated that by lowering the condensing temperature, the backpressure on the turbine 

is lowered, which increases its efficiency. Commenters stated that a condenser degrades 

primarily due to fouling of the tubes and air in-leakage. Commenters stated that tube fouling 

leads to reduced heat transfer rates, while air in-leakage directly degrades the quality of the 

water, however, Springerville operates using a closed cooling system, where cooling water 

quality can be controlled to a much higher degree.

Commenters stated that their maintenance program includes routinely inspecting and cleaning 

the condenser tubes during planned outages every three years in order to maintain condenser 

performance. Commenters stated that the condenser is cleaned with brushes as the Station has 
60

experienced good results from using this method. Commenters stated that the condenser tube 

material was changed in 2004 for Unit 1 and in 2005 for Unit 2 from 90/10 Cu-Ni to Sea-cure 

stainless to minimize corrosion; heat transfer capabilities are identical to the original design. 

Units 3 and 4 were originally designed with Sea-cure tubes. Commenters stated that they have

reported no major degradation inside the condensers outside of typical deposits on the condenser 

tubes.

Commenters stated that by including routine maintenance, appropriate materials to prevent 

corrosion, and by controlling water quality to minimize fouling, SGS has incorporated all 

technologies that can improve and maintain system performance. Commenters stated that a 

review of the recent plant data indicates the back-pressures are close to the original design 

values, and as such, any improvements made to the condenser will not produce appreciable heat 

rate improvements. 

Comment 16: Comments regarding boiler feed pumps

Response 16: The response to this comment is addressed by the response to Comment 1 in this 

section. 

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

Commenters addressed boiler feed pumps and stated that the S&L study notes that boiler feed

pumps require rigorous maintenance and consume significant auxiliary power. Commenters 

stated that the rebuild of a boiler feed pump can decrease heat rate by 25-50 BTU/kWh, which 

translates to a maximum boiler efficiency increase of 0.48 percent. Commenters stated that 

similar to the comment regarding condenser cleaning, all EGUs must generally adhere to regular 

feed pump maintenance and therefore, methods of heat rate reduction which involve regular 

scheduled maintenance would not significantly improve heat rate for existing EGUs.

Commenters stated that PacifiCorp has concluded that S&L's proposed boiler feed pump rebuild

(S&L 3.4) would not be economical at the Dave Johnston units due to the low value of the 

potential heat rate improvement. Commenters stated that they concluded the same for the four 

units of Jim Bridger. Commenters stated that PacifiCorp noted that boiler pump overhaul 

frequency is already optimized at Naughton by reliance on flow performance testing. 

Commenters stated that both boiler feed pumps are already overhauled at Wyodak. Commenters 

stated that somewhat in contrast, Black Hills identified an opportunity to add variable speed 

couplings that would reduce boiler feed pump auxiliary power consumption.

Commenters listed limitations that should be accounted for and a site specific analysis may

reveal additional limitations:

Boiler feed pump

• Units with recently rebuilt boiler feed pumps will not benefit from further 

improvement.
61

• Many units that already employ BP* will not achieve further improvement. 

(*Note: If a unit employs best operational and maintenance practices (BP) 

currently, the HRI method may not be applicable for further improvement. 

However, these practices must be continued for the life of the unit to maintain 

current heat rate levels.)

Commenters presented information with regard to STATION A - TURBINE ISLAND, BOILER 

FEED PUMPS. Commenters stated that boiler feed pumps consume a large quantity of the 

auxiliary power used internally within a power plant and that overhauling the boiler feed pumps 

can yield heat rate reductions depending on the size of the unit and the original design of the 

pumps. Commenters stated that Units A1 and A2 are equipped with turbine driven boiler feed 

pumps and that its steam turbine drive allows the pump to operate at variable speed which 

maintains the pump at its maximum efficiency. Commenters stated that the rotors were changed 

on the turbine drive for better efficiency to bring performance back to design level. Commenters 

stated that in general, Station A personnel refurbish pumps to like-new conditions every 10-12 

years. Commenters stated that because the units already perform best operating and maintenance 

practices on the boiler feed pumps, no other large improvements are considered to be feasible for 

future heat rate reductions.

Commenters presented information with regard to STATION B - TURBINE ISLAND, BOILER 

FEED PUMPS. Commenters stated that the existing boiler feed pumps on all units are turbine 

driven single pumps. Commenters stated that the pumps are considered to be slightly oversized, 

which provides robustness to the operational practices and improvements are made on a regular 

basis to restore the pumps to design conditions. Commenters stated that the main improvement 

program consists of swapping the pump rotor out every six years with a refurbished spare and in 

between these swaps, the pumps are inspected for damage. Commenters stated that the station 

personnel typically monitor vibration of the rotor and oil condition along with level. Commenters 

stated that the units already perform best operation and maintenance practices on the boiler feed 

pumps, thus no other improvements are feasible for heat rate reductions.

Commenters stated that Big Stone Plant has two high-pressure, steam turbine-driven boiler feed

pumps and these pumps are overhauled as warranted based on pump/turbine performance as 

outage schedules dictate. Commenters stated that the boiler feed pumps were last overhauled in 

2011. 

Commenters stated that boiler feed pumps consume a large portion of the auxiliary power used

internally within a power plant. Commenters stated that overhauling the boiler feed pumps can 

yield heat rate improvements depending on the size of the unit and the original design of the 

pumps.

Commenters stated that the existing boiler feed pumps at Springerville are all motor-driven feed 

pumps. Commenters stated that Units 1, 2, and 4 are motor-driven feed pumps with hydraulic 

couplings; Unit 3 has motor-driven boiler feed pumps with a direct drive. Commenters stated 

that their standard maintenance practice is to replace the feed pump barrels in kind every seven 

years, based on performance. Commenters stated that these pumps are already designed for a 

very high operating efficiency and are regularly maintained using best practices; therefore, no 
62

heat rate improvement is considered to be feasible. 

Comment 17: Comments regarding efficiency improvements from FD/ID fans

Response 17: The response to this comment is addressed by the response to Comment 1 in this 

section. 

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

Commenters addressed ID Fans and stated that S&L notes that SCR and FGD installations

increase the pressure drop across the flue gas system and that old centrifugal fans can be replaced 

by newer axial fans for a heat rate reduction of 10-50 BTU/kWh during installation of new 

emission control equipment. Commenters stated that this heat rate reduction equals a maximum 

of 0.48 percent increase in boiler efficiency. Commenters stated that the study also identifies 

variable inlet vanes, variable speed control, two speed motors, and variable pitch blades as 

methods to control fan motor speed, which in turn will increase efficiency. Commenters stated 

that because SCR and FGD devices require redesign of the ductwork at an EGU, older 

centrifugal fans have been replaced (and upgraded) as part of the pollution control device 

installation at West Virginia's remaining EGUs and that therefore, in as much as West Virginia's 

EGUs have already installed axial fans with these controls, no further reduction in heat rate can 

be achieved in this manner. 

Commenters listed limitations that should be accounted for and a site specific analysis may

reveal additional limitations:

Flue Gas System: Forced draft (FD) and induced draft (ID) fan improvement - Many units have 

already replaced their centrifugal fans with axial fans during projects with high pressure drop 

associated with air pollution control projects; therefore, this HRI has already been incorporated 

on a large number of units.

Commenters presented information with regard to STATION A - FLUE GAS SYSTEM, FD, ID, 

AND PA FAN IMPROVEMENTS. Commenters stated that when the FGD was installed on Unit 

A1, the SCR booster fans were replaced with larger axial ID fans to overcome the additional flue 

gas path pressure drop and conversion to a balanced draft system. Commenters stated that during 

the FGD project on UnitA2, the centrifugal ID fans were replaced with axial fans and it is 

estimated that the conversion of the centrifugal to axial fans on Unit A2, which occurred at the 

same time the FGD was installed, mitigated some of the heat rate penalty that otherwise would

have been experienced based on the overall aux power increase. Commenters stated that on Unit 

A2, the FGD project also incorporated a re-design of flue gas discharge from the FGD and that 

this provided a savings of approximately 1.5 in.wc. of draft pressure to the flue gas path. 

Commenters stated that this was estimated to provide 7 Btu/kWh savings due to the decreased 

amount of work required by the ID fan and that this savings, along with the axial fan conversion 

savings are far surpassed by the increased aux power loading associated with the FGD system. 

Commenters stated that the FD fan motors have two speeds on Unit A1, 4,500hp and 3,000hp 

and that fan motor speed settings can be changed on-line or during outages, and typically occurs 

between summer and winter months. Commenters stated that due to the change in atmospheric 

temperatures, the lower fan speed is sufficient during the winter months, saving approximately 
63

1MW of aux power with the speed switch; however, this is only a temporary change that 

provides savings for three to six months of the year. Commenters stated that the unit employs 

good operational practices by using a dual speed motor on this unit; however, the annual heat 

rate savings is minimal. The FD fans on Unit A2 do not have this feature. Commenters stated 

that there is no further potential heat rate reduction applicable to the ID fans on Unit A1 or A2 

since axial fans are operated very efficiently at lower flue gas volumes, unlike centrifugal fans. 

Commenters stated that the existing FD fans on Units A1 and A2 are all centrifugal; therefore 

there is the potential to convert the fans to axial configuration or install VFDs. Commenters 

stated that however, this may not yield any measurable benefit on Unit A1 as this unit already 

has a two-speed FD fan. Commenters also stated that it is possible to install a two-speed motor 

on the Unit A2 FD fans, similar to Unit A1. Commenters stated that this could provide a similar 

heat rate savings for less than half the year. Since these units are base loaded, these options have 

limited value and were not further explored for FD fans.

Commenters presented information with regard to STATION B - FLUE GAS SYSTEM, FD, ID, 

AND PA FAN IMPROVEMENTS. Commenters stated that the FD and ID fans on all three units 

are axial with variable pitch. Commenters stated that the ID fans were enlarged on B1 and B2 

when the station discontinued the use of their FGD bypasses and that these improvements were 

made prior to 2005 for Units B1 and B2. Commenters stated that the fans were updated as part of 

a large environmental project, which consisted of other plant improvements, as well as changing 

WFGD operation to scrub 100% of the flue gas and that the fan improvements were made at the 

same time as other improvements on the unit, which decreased the overall unit heat rate by 214 

and 183 Btu/kWh for Units B1 and B2, respectively. Commenters stated that while some of the 

heat rate reduction is likely due to the ID/FD fan improvements, the remainder can be attributed 

to turbine maintenance and the discontinued use of the ESP. Commenters stated that the variable 

pitch axial fans are operated very efficiently at lower flue gas volumes; therefore VFDs are not 

applicable to the drives of the variable pitch axial fans. Commenters stated that there is no 

further potential heat rate reduction applicable to the FD or ID fans on Unit B1, B2 or B3. 

Commenters stated that the primary air fans supply the air required to transport the pulverized 

coal to the burners and that no work has been done on these fans that would have increased their 

efficiency.

Commenters stated that for Springerville Units 1 and 2, the induced draft (ID) fans are

centrifugal type fans with variable inlet vanes for operation at various loads. Commenters stated 

that they are provided with two-speed, high efficiency Westinghouse motors, and that currently, 

no VFDs are installed on the ID fans. Commenters stated that their personnel stated that the fans 

run at the higher speed setting during base load operation to provide the necessary pressure and 

flow to exhaust the flue gas through the chimney. 

Commenters stated that the Unit 1 and 2 forced draft (FD) fans are centrifugal type fans with 

variable inlet vanes for operation at various loads and are not equipped with VFDs. Commenters 

stated that their personnel stated that the fans run at the lower speed setting during base load 

operation to provide the necessary pressure and flow to the unit. Commenters stated that during 

periods of air-preheater pluggage, the fans are required to operate at the higher speed setting. 

Commenters stated that Units 3 and 4 have variable inlet vane, centrifugal ID and FD fans. 

Commenters stated that currently, there are no VFDs on the ID or FD fans at Springerville Units 

3 and 4.
64

Commenters stated that all four units are currently base-loaded with capacity factors greater than 

85% in years where the unit did not take a minor or major outage. Commenters stated that for 

base-loaded units, VFDs on the ID or FD fan motors will not provide appreciable heat rate 

improvements. Commenters stated that the VFDs typically only provide heat rate performance 

optimization when the unit operates for prolonged periods at low loads. 

Comment 18: Comments regarding efficiency gains from Fan Variable Frequency Drives (VFD)

Response 18: The response to this comment is addressed by the response to Comment 1 in this 

section. 

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

Commenters addressed Fan Variable Frequency Drives (VFD) and stated that the S&L study 

notes that many EGUs no longer operate at base-load capacity, and fan VFDs can improve 

efficiency at off-peak loads. Commenters stated that they refer EPA to their previous comments 

regarding ID fans, and notes that VFDs have already been installed with recent emission control 

devices and that all EGUs in West Virginia that remain after 2015 will operate at base-load 

capacity, and therefore cannot realize the projected heat input reduction of 20-100 BTU/kWh 

S&L associates with VFDs.

Commenters addressed Slurry Variable Frequency Drives and stated that the S&L study notes 

that VFDs on FGD slurry pump operation can accommodate reduced pump loads due to spray 

cutbacks and provide a minor decrease in heat rate. Commenters stated that most - if not all -

EGUs in West Virginia already incorporate recent, engineered scrubber systems, which include 

VFDs for reduced slurry pump loads and because of this, VFDs for slurry pump operation cannot 

be considered for added improvements in heat rate. 

Commenters stated that S&L's cooling tower advanced packing (S&L 6.3) issue does not apply 

to Wyodak or the four Black Hills plants, all of which are air cooled. Commenters stated that 

modifications have been made and are in progress at Jim Bridger. Commenters stated that 

PacifiCorp replaced the Unit 1 cooling tower in 2014, and installed VFDs in 2006; replaced the 

Unit 2 cooling tower in 2013, and installed VFDs in 2005; has scheduled the replacement of the 

Unit 3 cooling tower in 2015, and installed VFDs in 2005; and has scheduled replacement of the 

Unit 4 cooling tower in 2016, and replaced the Unit 4 cooling tower and VFDs in 2004. 

Commenters stated that PacifiCorp modified Naughton Unit 1 prior to 2012, but does not plan 

modifications to Unit 2 or Unit 3 due to the pending retirement date of the plant. Commenters 

stated that the pertinent modifications have already been implemented at all Dave Johnston units.

Commenters stated that the installation of variable frequency drive (VFD) fans (S&L 4.2) is 

generally uneconomic unless the units are being operated at partial load, and most of the 

PacifiCorp units are base load. Commenters stated that the only identified PacifiCorp 

opportunity is Naughton Unit 3 in 2018, when that unit will be converted to gas firing and hence 

used for partial load. Commenters stated that the modifications to the induced draft fans at the 

four Black Hills units are included in their 2% estimate.
65

Commenters listed limitations that should be accounted for and a site specific analysis may 

reveal additional limitations: Variable frequency drive (VFD)

• Many units, that have replaced or improved their ID fans recently, have already 

incorporated VFDs on their centrifugal.

• Not applicable for use on axial fans.

• VFDs must be located close to the equipment, so appropriate access is required.

Commenters presented information with regard to STATION A - FLUE GAS SYSTEM, FAN 

VFDs. Commenters stated that the primary air (PA) fans supply the air required to transport the 

pulverized coal to the burners. Commenters stated that the PA fans at Station A are the original 

centrifugal fans. Commenters stated that the six PA fans on Unit A2 were retrofitted with VFDs 

and that these were installed in 2001 and have provided significant auxiliary power savings. 

Commenters stated that this aux power savings is equivalent to approximately 43 Btu/kWh in 

heat rate savings. Commenters stated that the Unit A1 PA fans do not have this feature. 

Commenters stated that Unit A1 currently operates around 77% capacity factor and Unit A2 near 

79% and since the units are currently base-loaded, the implementation of VFDs on the PA fans 

on Unit A1 would provide very little improvement in operation. Commenters stated that the 

reason why Unit A1 cannot achieve similar heat rate improvement with VFDs on the PA fans is 

due to the fans originally having a narrower design fuel range; therefore they are accurately sized 

for the fuel currently burned. Commenters stated that the centrifugal FD fans on either unit are 

not equipped with VFDs; therefore, the unit could experience some benefit if the FD fans were 

retrofitted with VFDs. Commenters stated that however, since the units are base loaded, it is 

unlikely that VFDs on the FD fans would improve heat rate with base-loaded operation. 

Commenters also stated that the high air pre-heater in-leakage currently occurring on Unit A2 

may be causing the fans to operate lower than their optimal efficiency point. Commenters stated 

that VFDs might be beneficial to implement on Unit A2's FD fans if air heater in-leakage 

continues to operate in a similar leakage range after the seal improvements, due to operation at 

non-optimal efficiency points.

Commenters presented information with regard to STATION B - FLUE GAS SYSTEM, FAN 

VFDs. Commenters stated that the FD and ID fans are not able to incorporate VFDs on their 

motors, due to being variable pitch axial configuration. Commenters stated that the PA fans are 

centrifugal, and therefore could potentially experience some benefit at varying loads if they were 

retrofitted with VFDs, however, it is likely that the addition of VFDs on the PA fan motors 

would not provide additional heat rate reduction, since the VFDs typically only provide heat rate 

performance optimization when the units often cycle or operate at low loads. Commenters stated 

that the current capacity factors of all three units are greater than 85% and are projected to 

maintain similar high levels of operation in the future; therefore, it is predicted that no heat rate 

reduction can be experienced from this potential retrofit.

Commenters stated that Big Stone Plant currently utilizes centrifugal fans with variable speed 

drive steam turbines on the forced draft fans, and electric motor drives with dampers for flow 

control on the induced draft fans. Commenters stated that Otter Tail agree with EPA and the 

Sargent & Lundy report that variable frequency drives (VFDs) are a more precise and energy-
66

efficient method of flue gas control, especially at reduced loads and in fact, the co-owners of Big 

Stone Plant had already recognized the potential benefits of VFDs, and as part of the AQCS 

project they will be installing new centrifugal induced draft fans and motors with VFD drives. 

Commenters stated that if this project were undertaken on its own, the median improvement 

suggested by Sargent & Lundy report is approximately 0.7% for Big Stone. 

Comment 19: Comments regarding primary air fans

Response 19: The response to this comment is addressed by the response to Comment 1 in this 

section. 

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

Commenters stated that the primary air fans supply the air required to transport the pulverized

coal to the burners. Commenters stated that the primary air fans at Springerville Units 1 and 2 are 

variable pitch axial flow fans equipped with 3500 HP high efficiency motors. Commenters stated 

that the PA fans on Units 3 and 4 are centrifugal fans. Commenters stated that there are currently 

no VFDs installed on the PA fan motors and no improvements to the centrifugal PA fans on 

Units 3 and 4 have been made during their operating life, however, it is likely that the addition of 

VFDs on the PA fan motors would not provide significant heat rate improvement because, as 

stated above, VFDs typically only provide heat rate performance optimization when the units 

operate at low loads. Commenters stated that furthermore, the addition of VFDs on variable pitch 

axial flow fans is not used. 

Comment 20: Comments regarding FGD performance improvements

Response 20: The response to this comment is addressed by the response to Comment 1 in this 

section. 

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

Commenters addressed Removal of FGD Venturi Throat and stated that S&L indicates that old 

FGD controls that incorporate a venturi design can be replaced by a co-current spray tower 

quencher to reduce pressure drop across the flue gas system. Commenters stated that such an 

upgrade can halve the pressure drop across the FGD and somewhat reduce the auxiliary power 

required by the ID fans and that all EGUs in West Virginia already incorporate improved design 

scrubbers in engineered redesigns of flue gas systems due to recent installations of emission 

control devices and that therefore, removal of FGD venturi throats is very unlikely to 

significantly decrease heat input rate on for existing EGUs. 

Commenters addressed Turning Vanes & Perforated Gas Plates and stated that S&L indicates

improvements to FGD gas flow distribution can increase FGD performance. Commenters stated 

that turning vanes installed in the ductwork and perforated gas plates in the inlet duct accomplish 

this in older FGD installations and that all or most EGUs in West Virginia already incorporate 
67

improved design scrubbers in engineered redesigns of flue gas systems due to recent installations 

of emission control devices. Commenters stated that turning vanes and perforated gas plates are 

inherent components of the improved and redesigned gas flow distribution and cannot be 

considered as remaining measures to decrease heat rate for existing EGUs. 

Commenters addressed Shutoff Spray Level and stated that the S&L study notes that multiple

sprays in FGD systems can be cut back to decrease auxiliary power requirements for slurry pump 

operation, if the source is meeting its permit limits for SO2. Commenters stated that this is 

already a well-established practice in the operation of West Virginia EGUs, and, thus cannot be 

considered for additional improvements in heat rate.

Commenters stated that none of the flue gas desulfurization system modifications (S&L 5.1) are 

applicable to the four Black Hills plants or Wyodak, all of which are air cooled. Commenters 

stated that none of the modifications are applicable at the Dave Johnston units, which do not 

have the supposed scrubber. Commenters stated that gas distribution devices have been 

implemented at Dave Johnston 3 and 4, and Naughton 1 and 2 and that the scrubber at Naughton 

1 and 2 is new and properly sized. Commenters stated that Naughton 3 will be converted to gas 

in 2018. Commenters stated that the proposed changes to the Jim Bridger are either inapplicable 

as the units are designed (removal of a non-venturi throat or shutoff spray level) or uneconomical 

(gas distribution devices).

Commenters listed limitations that should be accounted for and a site specific analysis may 

reveal additional limitations:

Flue gas desulfurization (FGD) system

• Minimal efficiency gain compared to total retrofit work required.

• Applicability is limited to WFGDs operating at lower than design sulfur or lower 

than full load.

• Plans reducing heat rate through FGD optimizations, such as operating bypasses 

or scrubbing the flue gas less efficiently, often risk emission increase.

• Not applicable to dry or semi-dry FGD, as well as jet bubbling reactor (JBR) or 

venturi scrubber WFGDs.

Commenters presented information with regard to STATION A - AIR POLLUTION CONTROL 

EQUIPMENT, FLUE GAS DESULFURIZATION (FGD) SYSTEM. Commenters stated that 

Station A is equipped with WFGD systems on the two units. Commenters stated that when the 

new FGD systems were installed (Unit A1 prior to 2012 and Unit A2 after 2012), they required 

absorber bleed pumps, gas cooling pumps, reclaim water pumps, and oxidation air blowers, 

which have increased the total auxiliary power loading on the units by 14 MW. Commenters 

stated that the increased aux power consumption was partially offset by other projects on each 

unit. Commenters stated that Unit A1 completed ESP improvement, turbine rebuild, and 

conversion to balanced draft during the FGD project, which led to a 17MW increase in auxiliary 

power and approximately 300 Btu/kWh net heat rate increase. Commenters stated that Unit A2 
68

installed VFDs on the PA fans, converted to axial style ID fans, and rearranged the flue gas path 

to minimize pressure drop during the FGD project, which lead to an 11 MW increase in aux 

power and approximately 190 Btu/kWh net heat rate increase.

Commenters presented information with regard to STATION B - AIR POLLUTION CONTROL 

EQUIPMENT, FLUE GAS DESULFURIZATION (FGD) SYSTEM. Commenters stated that all 

three units at Station B are equipped with FGD systems and Unit B1 and B2 are equipped with 

WFGD systems and Unit B3 is equipped with dry lime FGD. Commenters stated that the 

absorber towers on Unit B1 and B2 scrub 100% of the flue gas for SO2 reduction. Commenters 

stated that with typical spray-tower absorbers, slurry pumps can be turned down at lower loads or 

lower sulfur levels, however, the slurry spray levels of the Unit B1 and B2 systems cannot be 

turned down at lower loads. Commenters stated that this is likely due to the slurry pump 

manifold design between the various spray levels in the absorber. Commenters stated that if 

common pumps feed multiple spray headers, it is not possible to turn off a single level during 

low sulfur conditions or low load operation. Commenters stated that in addition, the unit operates 

close to design sulfur and load conditions and therefore, no pressure drop or aux power savings 

is possible and no heat rate improvement is feasible. Commenters stated that the dry FGD system 

on Unit B3 does not have any possible components for heat rate reduction.

Commenters stated that all four units at Springerville Station are equipped with spray dryer

absorber (SDA)-type dry FGD systems. Commenters stated that the potential heat rate 

improvements in DFGD systems are improved flow distribution to lower the pressure drop. 

Commenters stated that the auxiliary power consumption of the DFGD systems have been 

incorporated into the plant heat rate calculations as part of the base case. Commenters stated that 

currently, the DFGD systems are meeting the original design performance with all of the 

equipment in operation; therefore, it is not anticipated that improving flow distribution would 

have an impact on the heat rate. Commenters stated that there are no additional opportunities for 

heat rate reduction for all the DFGD systems on the four units. 

Comment 21: Comments regarding Electrostatic Precipitator performance improvements

Response 21: The response to this comment is addressed by the response to Comment 1 in this 

section. 

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

Commenters stated that the electrostatic precipitator modification (S&L 5.2) issue does not apply 

to Wyden or the four Black Hills plants as they are designed. Commenters stated that PacifiCorp 

has scheduled new ESP controls for the four units of Jim Bridger from 2014 through 2017, and 

new ESP transformers and reactors for 2018 through 2012, but no heat rate improvement is 

expected. Commenters stated that modifications to Dave Johnston Units 1 and 2 have already 

been implemented, and are inapplicable to Dave Johnston Units 3 and 4, which are equipped 

with bag houses. Commenters stated that modifications to Naughton Units 1 and 2 are 

uneconomic, since they are calculated to yield a maximum improvement of only 5 Btu/kWh, 

even though this is the upper end of the range anticipated by S&L.
69

Commenters listed limitations that should be accounted for and a site specific analysis may 

reveal additional limitations:

Particulate system

• Implementing EMS systems is likely not feasible while maintaining FPM 

emission limits established by MATS.

• Is not applicable for units with baghouses.

Commenters presented information with regard to STATION A - AIR POLLUTION CONTROL 

EQUIPMENT, PARTICULATE SYSTEM. Commenters stated that approximately 75% of the 

coal-fired electric generating units in the U.S. use ESPs to control particulate emissions. 

Commenters described that ESPs operate by routing the particulate laden flue gas through a 

vessel that is divided into multiple, vertical sections and that each section is energized with an 

applied voltage that creates an electric field between a discharge electrode (DE) and a collection 

electrode (CE). Commenters stated that the electric field ionizes the particles entrained in the 

flue gas and enables their capture on the CE plates and that at specific intervals, the plates are 

shaken and the particles are dislodged and fall into hoppers for collection and removal. 

Commenters stated that in order to improve the power utilization, utilities have increasingly 

made use of ESP energy management systems and that the EMS enables the ESP to be optimized 

for varying load conditions by adjusting T/R set operation to maintain the unit's required opacity 

limit. Commenters stated that Unit A1 is equipped with a cold-side ESP (CESP), while Unit A2 

is equipped with a hot-side ESP (HESP) and that the CESP does not include an EMS - instead, 

the unit employs the best plate design available. Commenters stated that this plate design works 

well in high sulfur environments. Commenters stated that in the mid-1990s, a partial plate 

replacement was completed to get the system back to design efficiency. Commenters stated that 

Unit A2 has EMS installed on the HESP, where the T/R sets' power increases or decreases based 

on measured opacity. Commenters stated that the system has also undergone an electrode 

improvement during the time the unit switched to firing a high-sulfur fuel. Commenters stated 

that Unit A2 is already equipped with an EMS system on its HESP to optimize power output of 

the electrodes. Commenters stated that theoretically, an EMS system could be installed on Unit 

A1 to reduce auxiliary power costs. Commenters stated that however, the MATS rule requires 

controlling non-mercury metals, for which most affected facilities, including Station A, will use 

filterable particulate matter (FPM) as a surrogate, as permitted by the rule. Commenters stated 

that because the FPM limits prescribed by the MATS rule are relatively low (0.03 lb/MMBtu), 

ESPs will be utilized to maximize their collection efficiency by operating all T-R sets; therefore, 

an EMS system may not result in any reduction in heat rate.

Commenters presented information with regard to STATION B - AIR POLLUTION CONTROL 

EQUIPOMENT, PARTICULATE SYSTEM. Commenters stated that the majority of 

improvements that can be made to the particulate collection system for heat rate reduction are 

applicable to ESPs only. Commenters stated that the original HESPs on Units B1 and B2 were 

discontinued during the large environmental improvement project and replaced with fabric filters 

for PM compliance. Commenters stated that Units B1 and B2 have pulse-jet fabric filters (PJFF) 

while Unit B3 is equipped with a reverse gas fabric filter. Commenters stated that the reverse gas 

system, when installed on Unit B3, was equipped with reverse gas fans which are periodically 
70

used to reverse the path of the flue gas flow to aid in bag cleaning and the reverse gas fans were 

eliminated. Commenters stated that the unit now completes the gas flow reversal through the bag 

compartments via the discharge of the ID fan with the help of dampers. Commenters stated that 

the project eliminated the use of two 200hp fans and motors; however, in doing so, the duty on 

the ID fan was increased, and overall, the unit still received a small heat rate improvement. 

Commenters stated that fabric filters typically are unable to make additional improvements to 

achieve heat rate reductions and that no future heat reduction is deemed feasible on any of the 

three units at Station B.

Commenters stated that ESP modification does not apply to Big Stone Plant because a baghouse, 

not an ESP, is used for control of particulate matter. 

Commenters stated that all four units at Springerville station operate using their original

mechanical draft cooling towers; the cooling tower fans are not equipped with VFDs. 

Commenters stated that the Unit 1 and 2 cooling tower fans are single speed with forward and 

reverse flow capabilities. Commenters stated that during the winter months, the fan rotations are 

reversed to de-ice the system and maintain proper operation. Commenters stated that Unit 3 and 

4 cooling tower fans have two speed functionality, which allows their facility to operate them at 

lower speeds should ambient temperatures require less cooling. Commenters stated that 

furthermore, individual cooling tower cells are taken out of service during periods of cool 

weather in order to minimize auxiliary power consumption by the cooling towers. Commenters 

stated that since the cooling tower and cooling system are already operating effectively for the 

balance of the year, there is no opportunity for further economical improvements to the cooling 

tower systems. Commenters stated that however, regular maintenance of the fill and water 

chemistry must be continued to reduce degradation of cooling tower performance. 

Comment 22: Comments regarding baghouses

Response 22: The response to this comment is addressed by the response to Comment 1 in this 

section. 

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

Commenters stated that all four units at Springerville are equipped with baghouses for collecting

the flue gas particulate matter and SDA byproducts. Commenters stated that baghouses operate 

by collecting dry particulate matter as the flue gas passes through filter membranes, which are 

bundled in tube sheets and enclosed in compartments. Commenters stated that similar to the 

SDA systems, these units were constructed with baghouses as part of their original design, with 

the fans having been sized for the expected pressure drop across the baghouse. Commenters 

stated that the existing baghouses are currently operating within the original design performance 

with all the equipment in operation. Commenters stated that in addition, their personnel have 

noted that all of the original flue gas distribution devices and flue gas turning vanes are intact. 

Commenters stated that fabric filters typically are unable to make additional improvements to 

achieve heat rate reductions and no future heat reduction is deemed feasible on any of the four 

units at Springerville Station. 
71

Comment 23: Comments regarding SCR improvements

Response 23: The response to this comment is addressed by the response to Comment 1 in this 

section. 

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

Commenters stated that PacifiCorp expects deterioration in heat rate, not improvement, with the

mandated installation SCRs (S&L 5.3) on Jim Bridger Units 3 and 4 in 2015 and 2016, and Units 

1 and 2 in 2021 and 2022, all related to regional haze compliance. Commenters stated that the 

modification does not apply to any of the Naughton, Dave Johnston or Wyodak units, since none 

are equipped with an SCR. Commenters stated that Black Hills also concluded this modification 

did not apply.

Commenters listed limitations that should be accounted for and a site specific analysis may

reveal additional limitations:

Selective catalytic reduction (SCR) system

• Minimal efficiency gain compared to total retrofit work required.

• Recently designed/installed SCRs already have completed rigorous computational 

fluid dynamics (CFD) modeling to optimize pressure drop.

• Applicability is limited to units with existing SCRs.

Commenters presented information with regard to STATION A - AIR POLLUTION CONTROL 

EQUIPMENT, SELECTIVE CATALYTIC REDUCTION SYSTEM. Commenters stated that 

SCR systems were installed on Units A1 and A2 before 2005 for increased NOx emissions 

reduction. Commenters stated that the system uses direct injection of ammonia into the flue gas 

path. Commenters stated that with the addition of the SCR reactor and ancillary equipment, the 

auxiliary power consumption increased and that the increase in auxiliary power consumption is 

due to (1) increased ID fan power due to the added pressure drop across the new ductwork and 

SCR reactor and (2) ancillary equipment including reagent preparation, catalyst cleaning 

equipment, and equipment associated with ammonia injection. Commenters stated that the added 

auxiliary power consumption due to the new SCR system has led to an overall increase in heat 

rate of approximately 100 Btu/kWh. Commenters stated that the units currently monitor catalyst 

life with test modules, rather than catalyst layer pressure drop as part of their catalyst 

management plan and to reduce pressure drop in the system, either ductwork improvements, a 

lower degree of mixing, or switching the type of catalyst management plan would be required. 

Commenters stated that the SCR ductwork and mixing were designed with state-of-the art 

modeling technologies to optimize pressure drop while providing the degree of mixing required 

to achieve sufficient NOX reduction. Commenters stated that because neither auxiliary power 

reductions nor pressure drop reductions are feasible at Station A, there are no further 

opportunities to lower heat rate associated with the SCR system.
72

Commenters presented information with regard to STATION B - AIR POLLUTION CONTROL 

EQUIPOMENT, SELECTIVE CATALYTIC REDUCTION SYSTEM. Commenters stated that 

the current NOx controls on the units consist of LNB and OFA; however, further NOx emissions 

reduction may be required in the future for all three units. Commenters stated that the addition of 

a selective catalytic reduction (SCR) system on Unit B1 or B2 could result in a future heat rate 

increase of approximately 1% for each unit. Commenters stated that the significant heat rate 

increase is due to the added pressure drop across the system and the auxiliary components 

required for catalyst cleaning and ammonia injection. Commenters stated that if selective noncatalytic reduction (SNCR) technology were to be incorporated on Unit B3, the installation 

would come with a heat rate penalty. Commenters stated that while the system does not add 

pressure drop to the flue gas path, it adds a significant amount of water into the boiler, which 

requires more heat to evaporate, thereby, increasing net unit heat rate. Commenters stated that 

the system also increases total auxiliary power consumption and that based on OEM information, 

the total amount of water and equipment added is likely to increase the heat rate by 0.3%.

Commenters stated that Big Stone Plant is currently installing an SCR and FGD using the most

advanced technology and controls currently available. Commenters stated that consequently, 

there are no SCR or FGD systems to modify. Commenters stated that one SCR technique 

suggested by the Sargent & Lundy report is the use of secondary air as dilution air for the 

ammonia vaporizer, which will be used for the Big Stone Plant SCR. 

Comment 24: Comments regarding the impact of water treatment systems on heat rate

Response 24: The response to this comment is addressed by the response to Comment 1 in this 

section. 

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

Commenters listed limitations that should be accounted for and a site specific analysis may

reveal additional limitations.

Boiler water treatment

• Many units already have a modern water treatment system to reduce scaling.

• Heat rate improvement is likely not better than BP* associated with condenser 

cleaning.

(*Note: If a unit employs best operational and maintenance practices (BP) currently, the HRI 

method may not be applicable for further improvement. However, these practices must be 

continued for the life of the unit to maintain current heat rate levels.)

Commenters presented information with regard to STATION A - WATER SYSTEMS, BOILER 

WATER TREATMENT. Commenters stated that reduction of power plant heat rate as related to 

water treatment primarily involves maintaining the proper water chemistry to reduce boiler scale 

and to control solids and impurities. Commenters stated that boiler scale lowers heat transfer by 
73

lowering thermal conductivity and that heat transfer may be reduced significantly by the 

presence of scale. Commenters stated that more important than the heat loss is that scale can 

cause overheating of the boiler tube metal and can result in subsequent tube failures, leading to 

costly repairs and boiler outages. Commenters stated that the plant practices careful monitoring 

and maintenance of the water treatment systems for optimal water quality. Commenters stated 

that the feedwater system was changed to oxygenated feed water in the 1990s to reduce scaling. 

Commenters stated that ammonia is currently used to maintain a high pH (8.8 minimum) which 

helps with the oxygenated system and reduces scaling. Commenters stated that the units have not 

reported any experience with scaling or overheating of the boiler tube material nor have they 

experienced any iron or copper deposition and that every three years, the station personnel take 

tube samples to check for thickness. Commenters stated that in addition, every 10-15 years, 

chemical cleaning is completed. Commenters stated that since the station already has advanced 

water treatment systems installed and high-quality water chemistry, there is no opportunity for 

further improvements regarding additional treatment technologies to reduce boiler scale and 

improve plant heat rate.

Commenters presented information with regard to STATION B - WATER SYSTEMS, BOILER 

WATER TREATMENT. Commenters stated that reduction of power plant heat rate as related to 

water treatment primarily involves maintaining the proper water chemistry to reduce boiler scale 

and the amount of boiler water blowdown needed to control solids and impurities. Commenters 

stated that boiler scale lowers heat transfer by lowering thermal conductivity. Commenters stated 

that heat transfer may be reduced significantly by the presence of scale. Commenters stated that 

more important than the heat loss is that scale can cause overheating of the boiler tube metal and 

can result in subsequent tube failures, leading to costly repairs and boiler outages. Commenters 

stated that high-purity water reduces water and energy losses because less scale is formed and 

less water must be discarded in the blow down. Commenters stated that by reducing the blow 

down amounts, more steam is available in the thermal cycle, thereby improving overall power 

plant efficiency and reducing heat rate. Commenters stated that normal oxide scaling has been 

found in the boiler tubes of Unit B1 and B2 along with copper oxide deposition. Commenters 

stated that the station personnel use hydrazine to raise the condensate pH. Commenters stated 

that the plant reportedly practices careful best operating practices on the unit and have 

incorporated the use of ammonia to raise the B3 condensate pH. Commenters stated that since 

the station already has advanced water treatment systems installed and high-quality water 

chemistry, there is no opportunity for improvements regarding additional treatment technologies 

to reduce boiler scale and improve plant heat rate.

Commenters stated that reduction of power plant heat rate as related to water treatment primarily 

involves maintaining the proper water chemistry to reduce boiler scale and minimizing the 

amount of boiler water blow down needed to control solids and impurities. Commenters stated 

that boiler scale lowers heat transfer by lowering thermal conductivity. Commenters stated that 

heat transfer may be reduced significantly by the presence of scale. Commenters stated that more 

important than the heat loss is that scale can cause overheating of the boiler tube metal and can 

result in subsequent tube failures, leading to costly repairs and boiler outages.

Commenters stated that high-purity water reduces water and energy losses because less scale is 

formed and less water must be discarded in the blow down. Commenters stated that by reducing 

the blowdown amounts, more steam is available in the thermal cycle, thereby improving overall 
74

power plant efficiency. Commenters stated that Springerville practices careful monitoring and 

maintenance of the water treatment systems for optimal water quality. Commenters stated that 

Units 1 and 2 have inline condensate polishers while Units 3 and 4 operate Powdex resin for 

polishing. Commenters stated that since the station already has advanced water treatment 

systems installed and high-quality water chemistry, there is no opportunity for further 

improvements regarding additional treatment technologies to reduce boiler scale, reduce boiler 

blowdown and improve plant heat rate. 

Comment 25: Comments regarding cooling system modifications

Response 25: The response to this comment is addressed by the response to Comment 1 in this

section. 

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

Commenters listed limitations that should be accounted for and a site specific analysis may

reveal additional limitations.

Cooling tower:

• Many units among the fleet have already implemented counter-flow 

configurations.

• Improvements to cooling towers may have spatial constraints.

Commenters presented information with regard to STATION A - WATER SYSTEMS, 

COOLING TOWERS. Commenters stated that Unit A1 is not equipped with a cooling tower; 

instead it uses once-through cooling from the river; therefore, no heat rate reduction strategies in 

this section are applicable. Commenters stated that Unit A2 is equipped with a counter-flow 

cooling tower. Commenters stated that the cooling tower was modified between 2005-2012 from 

cross-flow to counter-flow during the FGD project and that the counter-flow mechanism resulted 

in an improvement of approximately 1-1.5 degrees F of discharge water temperature, which 

provided an average heat rate reduction of approximately 0.09%.

Commenters presented information with regard to STATION B - WATER SYSTEMS, 

COOLING TOWERS. Commenters stated that all units at Station B use cooling towers as part of 

their closed-loop cooling systems and that since 2012, the plant added a new high-efficiency fill. 

Commenters stated that due to the nature of the high efficiency fills used, the units must maintain 

a sidestream filtration system which sometimes requires blow down. Commenters stated that 

each cooling tower fan has been improved with higher efficiency fan blades, but the efficiency of 

this improvement was never recorded. Commenters stated that the fan motors on Unit B3 may be 

retrofitted in the future and that this may make some efficiency improvement; however, it is not 

quantified at this time.

Commenters stated that Big Stone Plant uses a cooling pond rather than a cooling tower, so this 

option is not available. 
75

Commenters stated that once-through cooling is utilized on each of the 4 units at Big Bend 

Station and with the high cooling water flow and relatively small increase in cooling water 

discharge temperature, there is very little opportunity for recovering any usable thermal energy 

from the cooling water discharge from the condensers 

Comment 26: Comments regarding large motor upgrades

Response 26: The response to this comment is addressed by the response to Comment 1 in this 

section. 

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

Commenters presented information with regard to STATION A - LARGE MOTORS. 

Commenters stated that in there are other areas that can provide improvements on a plant-wide 

basis: VFDs and upgrade of large electric motors. Commenters stated that the other potential 

area for heat rate improvements is the upgrade of large electric motor (>450 hp) by replacing 

older electric motors with new, energy efficient motors and that the primary problems with 

implementing more efficient motors are the cost of the materials and the cost of training plant 

personnel on the proper maintenance procedures. Commenters stated that all electric motors in 

the range of 1-200 hp sold today in the U.S. must meet high-efficiency standards as mandated by 

the federal government in the Energy Policy Act of 1992 (EPAct) and therefore, replacing older, 

failing motors will entail the inclusion of a more efficient motor. Commenters stated that as part 

of the regular maintenance plan at Station A, the large electrical motors are regularly maintained 

or refurbished and many have not been replaced. Commenters stated that due to the base load 

conditions at which these units operate, it is not expected that replacement of motors will deliver 

any real efficiency improvement. Commenters stated that other motors, if replaced, will be of 

higher efficiency in the ordinary course of business, however, there does not appear to be 

sufficient gain in efficiency to justify premature replacement. Commenters stated that within this 

study, S&L evaluated the changes to the units' heat rate that occurred due to the improvements 

that have been implemented at Station A to date, as well as potential future heat rate 

improvements that are technically feasible. Commenters provided Table 17 and Table 18 which 

summarize the changes in heat rate to show the overall changes to the two units at Station A. 

Commenters presented information with regard to STATION B - LARGE MOTORS. 

Commenters stated that in addition to the various methods of improving plant performance that 

have been discussed, there are other areas that can provide improvements on a plant-wide basis: 

VFDs and upgrade of large electric motors. Commenters stated that the other potential area for 

heat rate improvements is the upgrade of large electric motor (>450 hp) by replacing older 

electric motors with new, energy efficient motors. Commenters stated that the primary problems 

with implementing more efficient motors are the cost of the materials and the cost of training 

plant personnel on the proper maintenance procedures. Commenters stated that all electric 

motors in the range of 1-200 hp sold today in the U.S. must meet high-efficiency standards as 

mandated by the federal government in the Energy Policy Act of 1992 (EPAct) and therefore, 

replacing older, failing motors will necessarily entail the inclusion of a more efficient motor. 

Commenters stated that as part of the regular maintenance plan at Station B, the large electrical 
76

motors are consistently refurbished and many have not been replaced. Commenters stated that 

due to the base load conditions at which these units operate, it is not expected that replacement of 

motors will deliver any real efficiency improvement. Commenters stated that other motors, if 

replaced, will be of higher efficiency in the ordinary course of business; however, there does not 

appear to be sufficient gain in efficiency to justify premature replacement. Commenters also 

stated that within this study, S&L evaluated the changes to the units' heat rates that occurred due 

to the improvements that have been implemented at Station B to date, as well as the potential 

future heat rate improvements that are technically feasible. Commenters stated that in Tables 19 

through Table 21, the changes in heat rate have been summarized to show the overall changes to 

the three units at Station B. 

Commenters stated that Springerville Units 3 and 4 were originally designed with and currently

operate SCR technology. Commenters stated that as previously mentioned, these units are fairly 

new (Commercial Operation Dates: 2006 and 2009, respectively) and extensive flow modeling 

was performed to achieve NOx reduction efficiency with minimum ammonia slip. Commenters 

stated that more importantly, these modeling efforts focus on achieving uniform flue gas 

distribution across the SCR catalyst with minimal pressure drop. Commenters stated that in 

addition, they have confirmed that a catalyst management system has been implemented to save 

on pressure drop across the SCR. Commenters stated that they are currently operating these SCR 

systems with the best operating and maintenance practices and heat rate improvements are not to 

be expected from changes to these systems. 

Commenters stated that in addition to the various methods of improving plant performance two

additional methods are variable frequency drives (VFDs) and upgrade of large electric motors.

Commenters stated that the other potential area for heat rate improvements is the upgrade of 

large electric motors (>450 hp) by replacing older electric motors with new, energy efficient 

motors. Commenters stated that all electric motors in the range of 1-200 hp sold today in the U.S. 

must meet high-efficiency standards as mandated by the federal government in the Energy Policy 

Act of 1992 (EPAct). Commenters stated that therefore, replacing older, failing motors will 

necessarily entail the inclusion of a more efficient motor.

Commenters stated that all of the large motors at the Springerville units are 95% efficient or 

greater; therefore, it is not practical to install new motors for Springville Units 1-4 for the 

purposes of heat rate improvement. 

Comment 27: Comments addressing cumulative efficiency gains from equipment and

technology projects.

Response 27: For the EPA’s response to these comments, see section V.C of the final rule

preamble of the CPP and Chapter 2 of the GHG Mitigation Measures TSD supporting the final 

CPP. As stated therein, we agree that the benefits of heat rate improvement measures are not 

always additive.

The following are summaries of the specific public comments under this comment:
77

Commenters stated that many of the available actions to improve heat rate do not provide

cumulative benefits and thus cannot be added together to estimate the potential efficiency gains 

at coal-fired EGUs. Commenters stated that in particular, measures that increase heat removal 

from the boiler, such as economizer modifications, improved air heater performance, and low 

temperature heat recovery, do not provide additive efficiency benefits because any heat that is 

recovered by an individual project cannot be recovered a second time. Commenters stated that 

small increments of efficiency improvements in the APH result in substantial reductions of net 

fuel consumption and parasitic loads.

Commenters stated that many available heat rate improving actions are not independent - each is

related. Commenters stated that each heat rate improving action affects unit efficiency in a 

different manner, and the payoff is not directly additive. Commenters stated as an example, the 

effluent heat from a boiler can only be captured once - thus benefits from multiple boiler 

upgrades are not directly additive. Commenters stated that similarly, the individual steps within a 

steam turbine to improve heat rate are not additive. Commenters stated that totaling the benefits 

from a list of heat rate improving options is not feasible and will likely require some form of 

discounting, depending on the options considered. Commenters presented a table depicting the 

interrelationships between various popular heat rate actions. 

Commenters stated that a 2014 National Coal Council report includes a review of various options 

for improving the heat rate of existing coal power plants including coal switching, coal drying, 

steam turbine upgrades, condenser cleaning, instrumentation and controls improvements, low 

temperature heat recovery, auxiliary power use reduction, and cooling tower improvements:

"In some cases the benefits are cumulative - such as those derived from minimizing auxiliary 

power, fuel drying, and improving heat rejection. Other actions that increase heat removal from 

the boiler - economizer modifications, improved air heater performance and low temperature 

heat recovery - do not provide cumulative benefits. All efficiency improving measures are unit 

and site-specific and will not always be technically and/or economically feasible. A detailed 

analysis would be required to assess the benefits of this set of measures, as well as its 

compatibility with new source review regulations. It is possible that a thermal efficiency 

improvement of up to 3-4 percentage points could be derived, if these actions can be proven to 

work together and do not compromise plant reliability."

Commenters stated that the report also has a detailed list of reasons why cited heat rate 

improvements might not be applicable at a specific power plant. Commenters stated that it also 

includes a list of factors which could lead to an increase in coal power plant heat rates including 

more operation at part-load, adding more environmental control equipment, switching from 

once-through to evaporative or air cooling, and switching from bituminous to lower 

subbituminous coal.

Commenters stated that EPA cites the January 2009 Sargent & Lundy (S&L) report "Coal-fired

Power Plant Heat Rate Reductions" as a basis for these potential improvements. Commenters 

stated that their company is one of the suppliers identified as a contributor to the S&L report and 

that in addition their subsidiary company, Diamond Power, provides intelligent sootblowing 

systems that are also identified in the S&L report as an opportunity for heat rate improvements. 

Commenters stated that while the plant modifications discussed in the report may be feasible for 
78

any given plant, they are not necessarily additive (i.e. not every improvement identified in the 

report will be applicable to every plant). Commenters concluded that some plants may have little 

or no opportunity for improvement based on their age, maintenance and operating practices, 

prior retrofits or upgrades, capacity and operating mode.

Commenters stated that EPA's Building Block 1 target is also flawed because the payoffs from

many heat rate improvement measures are not cumulative and thus cannot be added together to 

estimate the potential efficiency gains at coal-fired EGUs. Commenters stated that in particular, 

measures that increase heat removal from the boiler, such as economizer modifications, 

improved air heater performance, and low temperature heat recovery, do not provide additive 

efficiency benefits because any heat that is recovered by an individual project cannot be 

recovered a second time by other measures. Commenters stated that similarly, the use of variable 

frequency drives will compromise the benefit of deploying advanced neural network controls.

Commenters stated that the 2009 Sargent & Lundy Report estimated ranges of potential heat rate

improvements that could be achieved by applying various technologies, but did not include a 

discussion as to the impact of applying multiple technologies simultaneously. Commenters stated 

that in some cases, the heat rate reduction estimated to be achieved through a combination of 

technologies may be equivalent to the sum of each technology's estimated heat rate reduction but 

that, in many cases, the estimated heat rate reduction of a combined strategy would be less than 

the sum of each technology's estimated heat rate reduction because many of the technologies 

affect power plant operating variables that are related or dependent upon one another. 

Commenters stated that one example of a combination of technologies for which the combined 

heat rate reduction is lower than the sum of the individual heat rate reductions is the application 

of NN with ISB because the performance of each of these technologies relies on boiler 

performance variables that are related to one another, and their performance cannot be 

decoupled. Commenters stated that another example of overlapping effects would be combining 

condenser maintenance practices with state of the art boiler water chemistry. Commenters stated 

that the optimization of boiler water chemistry is a strategy to keep deposits from forming inside 

the boiler feed loop and if very balanced cooling water chemistry is maintained, then deposits are 

less likely to form, and the heat rate improvement realized by maintenance practices such as 

condenser cleaning would be lower. Commenters stated that because of the interdependency of 

variables for many of these heat rate improvement technologies, combinations of technologies 

cannot be assumed to have an additive impact on heat rate, rather combinations of technologies 

should be assessed on a case-by-case basis to determine the combined heat rate improvement.

3.1.3 Previous studies on heat rate improvement

This section discusses comments received on a number of studies using varying approaches 

performed to determine potential efficiency improvements and associated resulting CO2 

emission reductions. These approaches include characterizing the current U.S. coal-fired EGU 

fleet, identifying potential efficiency improvements, and applying improvement actions to 

existing EGUs.
79

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: General, multi-study comments

Response 1: For EPA’s response to the issues raised in these comments, see Chapter 2 of the 

GHG Mitigation Measures TSD supporting the final CPP. We appreciate the information 

provided in several studies and comments on the potential heat rate improvement for affected 

fossil fuel-fired EGUs. We have considered this information in evaluating and refining our 

analysis. Where pertinent, we have cited, discussed, or elaborated upon many of these studies in 

the above-referenced portions of the preamble and TSD. For the reasons noted in section V.C of 

the final rule preamble of the CPP and Chapter 2 of the GHG Mitigation Measures TSD 

supporting the final CPP, we believe our final assessment of potential heat rate improvement is 

comprehensive, reasonable, and appropriate given the nature of this rulemaking.

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

Commenters stated that other than EPA's rudimentary statistical analysis (4%) and the 2009 

Sargent & Lundy (S&L) report (2%), why did the EPA not explain how the other studies cited 

were used to develop or support the 6% HRI target. Commenters stated that specifically, on pp. 

2-13 to 2-15 of the GHG TSD several studies are noted:

NETL - Reducing CO2 - 2008

NETL - Improving the Efficiency - 2010a

Lehigh - Reducing HR - 2009

RFF - Regulating GHG - 2013

NRDC - Closing the Power - 2013

Commenters asked:

1. Why did the EPA not describe the methodology for selecting these studies as 

representative?

2. Why did the EPA not ensure adequate peer-review details?

3. What other studies were considered, but not included?

4. How were additional studies not detailed in this section but included in the bibliography 

factored in? 

Commenters stated that the study fails to account for upgrades that specific facilities have 

already made, thus, the report's conclusions of untapped technology-based heat rate improvement 

potential appear to be exaggerated. Commenters stated that EPA relied on an exceedingly small 

sampling of coal-fired units to project a fleet-wide standard onto the Nation's approximately 500 

coal-fired plants and in fact, using Sargent & Lundy data, EPA could identify just two cases that 

supported its conclusion that a 2 percent gain can be obtained fleet-wide. Commenters stated that 

other sources cited by EPA, e.g., EPA Region 7 and a 2001 EPA study of WEPCO's "two-phase 
80

efficiency program at four coal-fired plants," similarly identified only a few units that achieved 

any heat rate improvements through equipment upgrades and the former study analyzed heat 

rates at "three anonymous plants," while the latter study looked at a total of four plants. 

Commenters stated that EPA even conceded the inadequacy of its dataset, noting elsewhere that 

it "was unable to confirm specific equipment upgrades." 

Commenters provided an appendix with 20 articles from the scientific literature entitled 

"Appendix 2 - Literature Survey: Efficiency Improvements through Upgrades of Existing 

Plants". These articles discuss heat rate improvements.

Commenters stated that EPA has not adequately addressed heat rate improvements that units 

have already implemented and erroneously assumes all plants could average a 6 percent 

improvement in heat rate. Commenters stated that in technical support documents, EPA 

frequently mentions prior heat rate improvement studies as the source for information about 

technologies and improvement opportunities. Commenters stated that nearly all of the studies, 

however, are at least four years old and predate recent environmental regulations such as the 

Mercury and Air Toxics Standards (MATS) that will require many units to add additional 

pollution control technologies which will negatively affect heat rate. 

Commenters stated that the Wyoming Public Service Commission (WPSC) study determined 

that 2% improvement might be possible, nowhere near the EPA's projected 6%.

Comment 2: Comments regarding the EPRI report, "Range and Applicability of Heat Rate 

Improvements" (EPRI Report 3002003457) summarizing the results of recent EPRI projects 

focused on improving the heat rate of operating coal-fired power plants.

Response 2: The response to this comment is addressed by the response to Comment 1 in this 

section. 

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

Commenters described their 2014 report "Range and Applicability of Heat Rate Improvements” 

which summarizes the results of their recent projects focused on improving the heat rate of 

operating coal-fired power plants. Commenters stated that the study identified examples- both 

demonstrated/realized and projected - of methods to improve heat rate or recover efficiency 

losses. Commenters presented examples which include: 

• Production Cost Optimization (PCO). In their project, the units evaluated realized 

3-5% net heat rate improvements through various means. (Report 1015734, 

"Production Cost Optimization Assessments") 

• Sliding Pressure. By employing sliding pressure over a several-month period, a 

2% net heat rate improvement was realized at part load. (Report 1023912, 

"Methods to Mitigate the Effect of Increased Cycling and Load Following on 

Heat Rate") 
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• Remote Monitoring. The use of remote monitoring centers was documented to 

improve net heat rate 2.5 to 4%. (Report 1023075, "Evaluation of Remote 

Monitoring Heat Rate Improvement") 

• Steam Turbine Steam Path Modifications. Their members reported steam turbine 

steam path modifications were worth 2% to 4% net heat rate improvements. 

(Report 1018346, "Compilation of Results and Feedback Regarding Turbine 

Upgrades at Nuclear and Fossil Power Plants") 

• Cycle Alignment. Implementing a cycle alignment (isolation) program was 

documented to be worth at least 0.5% improvement in net heat rate. (Report 

1024640, "Cost Benefit Assessment of Cycle Alignment") 

• Capital and Maintenance Projects. A list of 57 potential actions and modifications 

to improve efficiency was made and evaluated in detail. While the amount of 

gains would be unit specific, the projected net heat rate improvements ranged 

from less than 0.1% to more than 2% for the various actions and modifications. 

One utility applied the methodology and analyzed a number of these potential 

projects for its own specific fleet, resulting in a projected 5% improvement in net 

heat rates.(Report 1019002, "Capital and Maintenance Projects for Efficiency 

Improvements")

Commenters supported use of building block 1, and stated that heat rate improvements, are 

adequately demonstrated and cost-effective. The commenters cited an independent study that 

indicated the proposed heat rate improvement of 6 percent was achievable by the U.S. fleet of 

EGUs. The commenters cited a study by EPRI that indicated power plant efficiency 

improvements are cost effective.

Comment 3: EPRI 2009 Heat Rate Conference - Applying the Fundamentals for Best Heat Rate 

Performance of Pulverized Coal Fueled Boilers

Response 3: The response to this comment is addressed by the response to Comment 1 in this 

section. 

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

Commenters provided an appendix with a paper entitled "EPRI 2009 Heat Rate Conference -

Applying the Fundamentals for Best Heat Rate Performance of Pulverized Coal Fueled Boilers", 

which discusses the factors that could influence boiler's unit heat rate. 

Comment 4: EPRI, 2011 Cycling and Load Following Effects on Heat Rate
82

Response 4: The response to this comment is addressed in section 3.1.4, and by the response to 

Comment 1 in this section. 

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

Commenters urged U.S. EPA to review the 2011 EPRI study entitled Cycling and Load 

Following Effects on Heat Rate, 2011. Commenters stated that this study measured heat rate as 

function of load for three years, during the transition of a 700 MW subcritical coal-fired EGU 

from a base load unit to a cycling unit. . Commenters stated that this study is very relevant to the 

assumptions of the proposed rule, in particular the impact that priority dispatch to natural gas 

units will have on the heat rates of coal-fired units. Commenters stated that this unit was 

primarily a base load serving unit through August of 2008, and then began serving the grid as a 

cycling unit. Commenters stated that the study demonstrates that this change in operation lead to 

a measured heat rate increase of 2.3%, and furthermore, the study presented heat rates of the unit 

during June of 2008 versus June of 2010. Commenters stated that during June 2008, while the 

unit was operating at near peak capacity, variations of approximately 1,000 BTU/kW-h were 

measured. Commenters stated that in June 2010, when the unit was serving as a cycling unit, 

variations of approximately 3,500 BTU/kW-h were measured, thus, they find it critical that U.S. 

EPA examine and account for the impact of increased cycling at the coal-fired units on heat rate 

as a direct result of priority dispatch to natural gas. Commenters believed U.S. EPA should 

consider how the increased dispatch in natural gas units will impact the operation of coal-fired 

power plants and how the 6% HRI goal can be part of system or emission reductions that is 

directly counteracted by the increased dispatch of natural gas units. Commenters stated that the 

study also examined, via designed cycling tests, the impact of load following on heat rate. 

Commenters stated that the study clearly demonstrates that operation at lower loads significantly 

degrades the heat rate performance of a coal-fired EGU. Commenters stated that Sargent & 

Lundy also agree stating "heat rate is increased when plants operate at lower loads, and the 

benefit of heat rate improvement strategy is reduced at lower loads" and "if an existing EGU is 

currently base-loaded and shifts to a load-cycling...that unit's annual average heat rate will 

increase." . Commenters stated that furthermore, they identify that HRI improvements from 

options similar to those in their study "could, in some cases, be negated by HRI losses associated 

with load-cycling." 

Commenters stated that the EPRI report also details the incorporation of "heat rate initiatives" at 

the unit examined in the study, including increased training of operators, enhanced coal sampling 

and analysis techniques, and excess air management measures. . Commenters stated that through 

these initiatives, the unit was able to manage and improve the initial heat rate degradation of 

2.3% to less than 1%; however, these measures could not overcome the full impacts of cycling 

on the unit's heat rate.

Commenters understood the increased use of natural gas will force more coal units to operate 

more cyclically, thus degrading their heat rates. Commenters urged U.S. EPA to consider how 

Building Blocks 1 and 2 of the goal setting will work together, or rather, against each other. 

Comment 5: 2009 Sargent & Lundy (S&L) report
83

Response 5: For the EPA’s response to these comments, see section V.C of the final rule 

preamble of the CPP and Chapter 2 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 EPA needs to further evaluate the state specific targets for Building 

Blocks 1 and 2, the coal heat rate improvement, and the re-dispatch of NGCC units. Commenters 

stated that Energy Coalition members have evaluated the Sargent Lundy report, along with their 

current work practices and have indicated that a heat rate improvement greater than 1-2 percent 

cannot be achieved. Commenters stated that to achieve heat rate improvements beyond this 

would require the installation of new equipment at a facility to increase efficiency. Commenters 

stated that most unit modifications to meet the proposals in Building Blocks 1 and 2 would 

trigger new source review (NSR), specifically related to efficiency improvement measures and 

operational limitations placed in previously issued permits. Commenters stated that reduced 

loading under Building Block 1 as proposed does not account for reduced load and that 

application of Building Block 2 and the likely impact of Building Blocks 3 and 4 will result in 

reduced utilization of coal units. Commenters stated that because these plants are designed to 

operate most efficiently at close to full load, reducing the load will result in reduced efficiency 

and that this reduced efficiency corresponds to a higher heat rate which is not consistent with the 

improvements required by Building Block 1. Commenters stated that because of this, the EPA 

should consider the impact of reduced load on achieving a more efficient heat rate and adjust 

Building Block 1 to account for this and also, much of the pollution control equipment (e.g., 

selective catalytic reduction (SCR)) needed to meet emission limits for other pollutants cannot be 

operated below a certain load. Commenters stated that South Carolina does not support taking 

pollution control equipment offline to allow units to operate at reduced load since this would 

result in increasing other emissions (e.g., criteria air pollutants). Commenters stated that these 

two examples point to the potentially conflicting building blocks used to calculate the state final 

reduction goals and the results of which will likely cause states to gravitate towards the other 

building blocks in the BSER to achieve the goals outlined in the EPA's proposed regulation. 

Commenters concluded that this negates some of the potential flexibility offered to states in the 

EPA proposal to reduce CO2 emissions.

Commenters briefly referred to EPA's BSER determination, Building Block 1, GHG Abatement 

Measures TSD, and EPA's use of the 2009 S&L Report's data. Commenters then summarized 

concerns with the way EPA interpreted heat rate improvement data and costs provided in the 

2009 S&L Report, and with the way EPA applied those data to establish its fleet-wide heat rate 

improvement projections and to evaluate the economic impact of implementing the HRI methods 

on a fleet-wide basis:

• Commenters stated that, first, heat rate improvement estimates provided in the 

2009 S&L Report were applied incorrectly in the GHG Abatement Measures TSD 

when the HRI methods were combined as though they were applied to a single 

EGU to establish a combined fleet-wide minimum /maximum heat rate 

improvement range of 415-1,205 Btu/kWh and that, by combining HRI methods 
84

in the 2009 S&L Report, EPA overestimated the fleet-wide heat rate improvement 

potential.

• Commenters stated that, second, equipment degradation and load profile were not 

taken into consideration when EPA applied heat rate improvement data from the 

2009 S&L Report to its long-term fleet-wide heat rate improvement calculation, 

and by failing to take into consideration both equipment degradation and load 

profile, heat rate improvement potential achievable on a fleet-wide average basis 

is overestimated.

• Commenters stated that, third, cost data provided in the 2009 S&L Report were 

incorrectly applied in the GHG Abatement Measures TSD when EPA combined 

individual HRI costs as though they were all applied on a single EGU to establish 

a combined fleet-wide minimum/maximum HRI capital cost. Commenters stated 

that cost estimates provided in the 2009 S&L Report represent order-ofmagnitude costs and were provided for comparative purposes only and that the 

costs were not intended to serve as the basis for estimating actual fleet-wide costs 

associated with implementing the HRI methods.

• Commenters stated that, fourth, the methodology used in the GHG Abatement 

Measures TSD to evaluate the economic impact of the HRI methods (i.e., 

applying an assumed combined total HRI capital cost of $100/kW and a combined 

fleet-wide average heat rate improvement of 6%) fails to take into account the 

wide range of real differences in both HRI potential and HRI costs, and does not 

provide an accurate representation of the cost-effectiveness of the HRI methods. 

Commenters stated that the wide range of HRI improvement and HRI costs 

presented in the 2009 S&L Report supports the conclusion that the costeffectiveness of any HRI method must be evaluated on a case-by-case basis.

Commenters points out that on page 34859 (Section VI.C.1.a.) of the proposal, EPA states, based 

on the 2009 Sargent & Lundy study that it: "believes that implementation of all identified best 

practices and equipment upgrades at a facility could provide total heat rate improvements in a 

range of approximately 4 to 12 percent." Commenters stated that the 2009 Sargent & Lundy 

study looked at the potential for HRI improvements prior to 2008, when many HRI projects 

considered low hanging fruit were not yet implemented. Commenters stated that EPD believes 

that many of the more feasible and cost effective HRI projects have already been accomplished 

and the law of diminishing returns will make achieving similar HRI targets difficult in the future. 

Commenters stated that a review of EPA's own TSD (Table 2-4, page 2-18) shows a tapering off 

of heat rate improvements since 2010. Commenters stated that EPA studied a population of 

almost 900 coal- and petroleum coke-fired EGUs from 2002 through 2012 (TSD, page 2-16) and 

found that most heat rate improvements occurred prior to 2008 (TSD Table 2-4 page 2-18), in 

the same timeframe covered by the 2009 Sargent & Lundy study.

Commenters stated that EPA's use of a study of measures that had been employed by power 

plants to improve heat efficiency as a basis for establishing its goal of a six percent improvement 

in heat efficiency is arbitrary and capricious because: 
85

1. The study is five years old and looks backward at measures that had been previously 

employed, and thereby necessarily does not consider improvements in process and new 

emission control devices installed at these plants more recently to meet more 

contemporary EPA requirements such as the Clean Air Interstate Rule (CAIR), 

Prevention of Significant Deterioration (PSD), Cross-State Air Pollution Rule (CSAPR), 

and the Mercury Air Toxics Standards (MATS); 

2. In the time since the study was published, operators of these plants have necessarily been 

required to examine and maximize heat efficiency as part of their strategy for meeting 

these other emission control requirements; 

3. EPA has erroneously concluded that the heat efficiency gains from implementing 

different measures is cumulative, when it is not, and derived its goal, in part, by simply 

adding the projected percentages of the different heat efficiency improvements; and, 

4. EPA employed a statistical overlay in its calculations to conclude that the heat efficiency 

goal should be a six percent improvement. However, this statistically-derived result is not 

supported by real life data or examples. None of the case studies of real life situations 

found an improvement in heat rate of greater than four percent. 

Commenters stated that EPA's use of a five year old, backward looking study is also 

arbitrary and capricious, because it ignores that the utilities that operate most of these 

plants are both publically traded companies and regulated by state public service or 

public utility commissions and have always been under obligations to both their 

shareholders and these regulators to achieve any economically achievable efficiencies.

Commenters stated that in an October 15, 2014 letter to the National Rural Electric Cooperative 

Association, Sargent & Lundy provided key clarifications regarding their previous study and that 

these explanations by the study's own authors undercut the validity of the goals EPA set 

purportedly based on the S&L study, support the equipment upgrade comments WVDEP made 

above, and are hereby incorporated in the WVDEP comments:

• Commenters stated that Sargent & Lundy's 2009 Report does not conclude that 

any individual coal-fired EGU or any aggregation of coal-fired EGUs can achieve 

6 percent HRI (heat rate improvement) or any broad target, as estimated by the 

EPA. 

• Commenters stated that the results in the 2009 Report were mostly based on 

publicly available data, data from original equipment manufacturers, and Sargent 

& Lundy's power plant experience. Commenters stated that also the case studies 

showed that not all of the examined alternatives were feasible to apply to an 

individual generating unit due to a number of factors, including plant design, 

previous equipment upgrades, and each plant's operational restrictions.

• Commenters stated that various limitations exist for applying each heat rate 

improvement strategy, and these limitations depend on the unit type, fuel type, 

and many other site-specific conditions, and therefore, the ability to apply each 
86

strategy and the amount of heat rate reduction that can be achieved by each 

strategy is site-specific and must be evaluated on a case-by-case basis.

• Commenters stated that it appears as though the EPA assumed that heat rate 

improvements cited in their 2009 Report were additive and applicable to all coalfired units. Commenters stated that heat rate improvement ranges described in the 

2009 Report case studies were estimated at a conceptual level, and were not based 

on detailed site-specific analyses. Commenters stated that verification of actual 

heat rate improvements was not made to determine whether any of the strategies 

were implemented and what actual heat rate improvements were realized based on 

site-specific design.

• Commenters stated that combinations of strategies to achieve heat rate 

improvements do not always provide heat rate improvement reductions equal to 

the sum of each individual strategy's heat rate improvement because many of the 

technologies affect, or are dependent upon, plant operating variables that are 

inter-related and therefore, case-by-case analyses should be conducted to 

determine whether the incremental heat rate improvement through the application 

of multiple strategies is economically justified.

• Commenters stated that the performance of some of the evaluated heat rate 

improvement strategies degrades over time, even with best maintenance practices 

and therefore, depending on the strategy employed or the technology installed to 

reduce heat rate at an existing coal-fired EGU, the unit heat rate initially obtained 

may increase over time.

• Commenters stated that heat rate is increased when plants operate at lower loads, 

and the benefit of a heat rate improvement strategy is reduced at lower loads and 

therefore, if an existing EGU is currently base-loaded 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 as compared to base-load operation. 

Commenters stated that in some cases any HRI improvements achieved by 

undertaking the relevant options described in S&L's 2009 Report could, in some 

cases, be negated by HRI losses associated with load-cycling.

• Commenters stated that the installation of additional pollution controls such as 

that required by regulations including BART, MATS, etc. will decrease the heat 

rate efficiency of any unit as compared to its heat rate efficiency before the 

installation.

• Commenters stated that many of the options for HRI listed in their 2009 Report 

have triggered New Source Review actions by EPA and others.

• Commenters stated that based on the case studies performed by S&L, it appears 

that most of the utilities are employing best operational and maintenance practices 
87

and therefore it appears that significant further reduction in heat rate, such as that 

assumed by the EPA, may not be feasible.

• Commenters stated that Sargent & Lundy concludes that the only technically 

appropriate method to properly evaluate potential HRI is to conduct a unit-by-unit 

evaluation.

Commenters referred to S&L's summary of their 2009 report:

"The purpose of the 2009 Report was to identify various methods that have been 

successfully implemented in the industry to reduce the heat rate of existing U.S. coalfired power plants. The 2009 Report identified a range of conceptual Btu/kWh heat rate 

improvement projects, including boiler improvements, steam turbine improvements, 

control system improvements, high efficiency motors, and similar improvements known 

to result in system efficiency gains. A list of the heat rate improvement projects 

considered in the 2009 Report is shown in Table 1."

For each alternative, S&L estimated the potential heat rate improvement that may be achieved at 

a 200, 500, and 900 MW coal plant. These improvement ranges were based on publicly available 

data, data from original equipment manufacturers (OEMs), and S&L experience and were meant 

to be applied to typical equipment at full load. Minimum and maximum ranges are meant to 

reflect site-specific differences. The estimates do not account for normal degradation that occurs 

in some equipment retrofits. No excess retrofit factors were taken into account nor were any 

impacts due to combination of technologies. In addition, these values are meant to represent a 

range only if the methods are applicable to the unit. If the technology is not applicable, the 

improvement is assumed to be zero. Table 2 shows the range of heat rate improvements that 

were estimated in the 2009 Report. The 2009 Report also provided two conceptual level case 

studies: one for a 250 MW unit and the second for an 850 MW unit, to provide examples of how 

heat rate improvement projects would be implemented and to identify some of the site-specific 

technical issues that would need to be taken into consideration. The selection of the units 

involved in the case studies were not planned to represent a "typical" unit, nor were they meant 

to represent simple or difficult retrofits cases. These units were merely selected based on inhouse studies previously performed. Each unit should be analyzed on a unit-by-unit basis; these 

case studies are meant to represent two possible scenarios and guide the reader on the proper 

methodology for the use of identified technologies. Table 3 summarizes the heat rate 

improvement projects evaluated to be technically feasible at the 250 MW unit, the estimated 

potential reduction in heat rate, and the associated order-of-magnitude costs for each technology 

evaluated. Table 4 summarizes the heat rate improvement projects evaluated to be technically 

feasible at the 850 MW unit, the estimated potential reduction in heat rate, and the associated 

order-of-magnitude costs for each technology evaluated. For each unit, site-specific technology 

constraints were used to determine conceptual level improvement rates and overall unit 

reduction. Some of these constraints include already performing best operation and maintenance 

practices, already having made equipment improvements, or not having eligible AQCS 

equipment. If the method was not applicable, no heat rate reduction was considered. The case 

studies illustrate that with more constraints, lower heat rate improvement results, if it is 

applicable at all.
88

As can be seen from Tables 3 and 4, the difference in heat rate reduction is significant. This is 

due to the overall site constraints and resulting applicability of the 16 methods. Since there were 

more available improvements for the smaller unit in this case study, it is possible to achieve a 

higher heat rate improvement. It is important to note that the majority of the heat rate 

improvement comes from installing new air heaters, steam turbine upgrades, and boiler feed 

pump, all of which are subject to normal performance degradation. Therefore, 4% represents the 

potential improvement at full load after the technologies are initially installed. These numbers 

are not meant to represent achievable values for all units of these sizes within the U.S. fleet. 

Instead, these numbers are meant to show the variability of heat rate improvements among the 

fleet. Heat rate improvements ranges described in the 2009 Report case studies were estimated at 

a conceptual level, and were not based on any site-specific detailed analysis. The results were 

mostly based on publicly available data, data from original equipment manufacturers, and 

Sargent & Lundy's power plant experience. In addition, verification of actual heat rate 

improvements was not made to determine whether any of the improvement strategies were 

implemented and what actual heat rate improvements were realized based on detailed design. 

Therefore, it is possible that the ranges provided may not be achievable depending on additional 

limitations."

Commenters provided general conclusions of the 2009 S&L report.

• Commenters stated that Sargent & Lundy's 2009 Report does not conclude that 

any individual coal-fired EGU or any aggregation of coal-fired EGUs can achieve 

6% HRI (heat rate improvement) or any broad target, as assumed by the EPA.

• Commenters stated that the results in the 2009 Report were mostly based on 

publicly available data, data from original equipment manufacturers, and Sargent 

& Lundy's power plant experience. Commenters stated that, the case studies 

showed that not all of the examined alternatives were feasible to apply to an 

individual generating unit due to a number of factors, including plant design, 

previous equipment upgrades, and each plant's operational restrictions.

• Commenters stated that various limitations exist for applying each heat rate 

improvement strategy, and these limitations depend on the unit type, fuel type, 

and many other site-specific conditions. Commenters stated that therefore, the 

ability to apply each strategy and the amount of heat rate reduction that can be 

achieved by each strategy is site-specific and must be evaluated on a case-by-case 

basis.

• Commenters stated that the combinations of strategies to achieve heat rate 

improvements do not always provide heat rate improvement reductions equal to 

the sum of each individual strategy's heat rate improvement because many of the 

technologies affect, or are dependent upon, plant operating variables that are 

inter-related. Commenters stated that therefore, case-by-case analyses must be 

conducted to determine whether the incremental heat rate improvement through 

the application of multiple strategies is economically justified.
89

• Commenters stated the 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 added that therefore, if an existing EGU is currently base-loaded 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 S&L's 

2009 Report could be negated by HRI losses associated with load-cycling.

• Commenters stated the installation of additional pollution controls such as those 

required by regulations including regional haze rules and MATS, will decrease 

the heat rate efficiency of any unit as compared to its heat rate efficiency before 

the installation.

• Commenters stated that many of the options for HRI listed in the 2009 Report 

have triggered New Source Review actions by EPA and others.

• Commenters stated that based on the case studies performed by S&L subsequent 

to the 2009 Report, it appears that most of the utilities are already employing best 

operational and maintenance practices.

• Commenters stated that the case studies performed in the development of this 

study estimate that on a weighted average, approximately 1.2% improvement has 

been achieved to date, while 0.3% improvement is the potential for the future for 

over 2,500 MWNET power generation. Commenters added that future 

improvement strategies are limited, due to the amount of previous improvements 

already performed on these units. Commenters stated that in light of this 

observation, it appears that a 6% reduction in heat rate, such as that assumed by 

the EPA from the 2012 baseline, may not be feasible.

• Commenters stated that furthermore, if improvement options are limited to the 

boiler island, the weighted average past and future potential heat rate 

improvement is approximately 0.04% and 0.08%, respectively, which would be 

impossible to verify.

Commenters stated that they conducted their own assessment of the technical, economic and 

market potential HRI in the coal-fired steam turbine fleet and provided methodology. 

Commenters reviewed scope and value of heat rate improvement solutions and since the specific 

HRI options identified in the Agency's proposed rule are based primarily upon a 2009 study

prepared by Sargent & Lundy (S&L), and reviewed this study to assess the technical merits and 

HRI potential of each HRI identified. Commenters stated that they are in general agreement with 

the referenced study's statement of heat rate improvement options, however an engineering 

review was performed with the following objectives:

• Identify possible HRI solutions that were not considered in the S&L report or 

were not available at the time of the 2009 study
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• Identify areas were their position on heat rate improvement differs from the 

values stated in the S&L study

• Add to the S&L analysis, since the 2009 study was not done expressly for 

measuring the heat rate potential of the US coal-fired EGU fleet

Commenters presented a table (Table A-1 shows percent heat rate improvements for 19 best 

practices and 5 upgrade) summarizing the estimated range of heat rate improvements that could 

be feasible for a "typical" or average 500 MW existing coal-fired plant. Commenters stated that 

similar to the S&L study, they considered low and high estimates for each improvement option 

for each of three nominal plant sizes (i.e., 200, 500 & 900 MW plants). 

Commenters stated, EPA's proposed BSER for this rule differs significantly from what has been 

done in the past. Commenters said, many of the concepts for BSER that EPA has presented 

include theoretical extremes that are not adequately demonstrated. Commenters said, they 

include extreme assumptions for electric generation units (EGUs) that cannot be achieved. 

Commenters said, for instance, in Building Block 1 EPA assumes that coal facility heat rates can 

be improved by 6%. Commenters said, EPA bases this assumption on the Sargent & Lundy 2009 

study of heat improvement potentials from equipment and system upgrades. Commenters said, 

the Sargent and Lundy study has been proven to include theoretical assumptions that are 

inaccurate. Commenters said, EPA also assumes that a 6% heat rate improvement at the facility 

will directly translate to a 6% reduction in the net CO2 emission rate.

Commenters stated that cost estimates would seem to be inaccurate and certainly would change 

due to market conditions over the intervening 5 plus years 

Commenters stated that S&L applied their findings to two case studies to estimate potential 

improvements. Commenters stated that the S&L Report identifies hypothetical actions that might 

improve heat rates at some facilities, but it does not support EPA's assumption that a significant 

improvement is feasible or achievable across the board at all or most coal-based facilities. 

Commenters stated that the S&L Report does not address the many variables that impact the 

measurability, feasibility, availability and sustainability of the listed potential improvement 

opportunities, and does not consider the extent to which heat rate improvements already have 

been achieved at many facilities. Commenters stated that the two case studies are isolated 

examples that cannot necessarily be replicated at other facilities. 

Commenters stated that S&L itself has recently evaluated the Proposed Rule's reliance on and 

characterization of the 2009 S&L Report and made the following specific conclusions 

undermining EPA's use of the S&L Report to support its assumptions regarding the potential for 

heat rate improvement 

Commenters made the following specific conclusions:

• Commenters stated that Sargent & Lundy's 2009 Report does not conclude that 

any individual coal-fired EGU or any aggregation of coal-fired EGUs can achieve 

6% HRI or any broad target, as estimated by the EPA.
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• Commenters stated that the results in the 2009 Report were mostly based on 

publicly available data, data from original equipment manufacturers, and Sargent 

& Lundy's power plant experience and furthermore, the case studies showed that 

not all of the examined alternatives were feasible to apply to an individual 

generating unit due to a number of factors, including plant design, previous 

equipment upgrades, and each plant's operational restrictions.

• Commenters stated that various limitations exist for applying each heat rate 

improvement strategy, and these limitations depend on the unit type, fuel type, 

and many other site-specific conditions and therefore, the ability to apply each 

strategy and the amount of heat rate reduction that can be achieved by each 

strategy is site-specific and must be evaluated on a case-by-case 

basis. Commenters stated that it appears as though EPA assumed that heat rate 

improvements cited in their 2009 Report were additive and applicable to all coalfired units. Commenters stated that heat rate improvements ranges described in 

the 2009 Report case studies were estimated at a conceptual level, and were not 

based on detailed site-specific analyses. Commenters stated that verification of 

actual heat rate improvements was not made to determine whether any of the 

strategies were implemented and what actual heat rate improvements were 

realized based on site-specific design.

• Commenters stated that combinations of strategies to achieve heat rate 

improvements do not always provide heat rate improvement reductions equal to 

the sum of each individual strategy's heat rate improvement because many of the 

technologies affect, or are dependent upon, plant operating variables that are 

inter-related and therefore, case-by-case analyses should be conducted to 

determine whether the incremental heat rate improvements through the 

application of multiple strategies are economically justified.

• Commenters stated that the performance of some of the evaluated heat rate 

improvement strategies degrades over time, even with the best maintenance 

practices and therefore, depending on the strategy employed or the technology 

installed to reduce heat rate at an existing coal-fired EGU, the unit heat rate 

initially obtained may increase over time.

• Commenters stated that heat rate is increased when plants operate at lower loads, 

and the benefit of a heat rate improvement strategy is reduced at lower loads and 

therefore, if an existing EGU is currently base-loaded 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 as compared to base-load operation. 

Commenters stated that in some cases any HRI improvements achieved by 

undertaking the relevant options described in S&L' s 2009 Report could, in some 

cases, be negated by HRI losses associated with load-cycling.

• Commenters stated that the installation of additional emission controls such as 

that required by regulations including BART, MATS, etc. will decrease the heat 
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rate efficiency of any unit as compared to its heat rate efficiency before the 

installation.

• Commenters stated that many of the options for HRI listed in S&L's 2009 Report 

have triggered New Source Review actions by EPA and others.

• Commenters stated that based on the case studies performed by S&L, it appears 

that most of the utilities are employing best operational and maintenance 

practices. Commenters stated that in light of this observation, it appears that 

significant further reduction in heat rate, such as that assumed by the EPA, may 

not be feasible. 

Commenters stated that the assumption by S&L and accepted by EPA that there would be cost 

savings from these upgrades would seem to be questionable and for all the reasons stated above 

under building block 1, the savings are not likely to affected if the load is reduced as planned for 

the coal and recognized additional CO2 reductions will not happen

Commenters stated that EPA relied for most of their technical approach to heat rate 

improvements on a Sargent & Lundy (S&L) report. Commenters stated that the S&L report 

"Coal-Fired Power Plant Heat Rate Reductions" is a good report on the heat rate impacts on coalfired plants but the report is generic, not specific and does not provide detailed information to be 

used as a basic tool in rule making. Commenters stated that the S&L report is correct when it 

stated that the heat rate improvements they reviewed had been successfully implemented, 

however, no one has ever implemented all of the listed improvements into one single project or 

design. Commenters stated that Page 1-3 of the report states that the cost in the report should not 

be used as a basis for project budgeting; so how can they be used for Rule Making and S&L 

states that market conditions required site specific estimating.

Commenters stated that on page 1-1 the report states that the analysis is based on full load 

operations and with the increased capacity of wind and solar coming on line, coal plants are 

cycling more, operating at minimum load and even shutting down for several days at a time -

each of these conditions results in an increased heat rate. Commenters stated that the S&L report 

was completed prior to the publication of ASME's Research Committee on Energy Environment 

& Waste (RCEEW) report on Fuel Delivery System (FDS) upgrades and therefore the case 

evaluations used in the FDS report should be evaluated along with the S&L report. Commenters 

stated that ASME evaluated a coal fired boiler group, aged 30- to 45-year old units, comprised 

216 GW and 63% of the total fleet capacity with an average unit capacity of 500 MW and these 

units will bear the burden of ensuring the usual high standards of electric grid performance, 

availability, and reliability.

Commenters stated that a vital part of any coal-fired unit is the Fuel Delivery System (FOS), 

comprising feeders, pulverizers, classifiers, coal piping and burners. Commenters stated that 

ASME investigated three typical 500-MW wall-, tangential-, and cyclone-, fired boilers 

originally designed for eastern bituminous coal and now firing low sulfur subbituminous Powder 

River Basin (PRB) coals. Commenters stated that the subcommittee reviewed and selected 

retrofit upgrades to various parts of the FDS, determining costs and the potential value of the 

ensuing benefits and in the case of a 500 MW bituminous wall fired boiler, they concluded that 
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0.34% improvement in boiler efficiency on a 500 MW wall fired coal boiler at a cost of 

$13,600,000. Commenters stated that EPA needs to evaluate this concept.

Commenters stated that improvements in the combustion system are not detailed in the S&L 

report and the S&L report does not address the types of boilers ("T"-fired, wall-fired and 

cyclone) or the heat rate improvements or the limitations for each type of boiler. Commenters 

stated that the ability to improve the heat rates on each of these types of boilers is different and 

the amount of reductions that can be achieved for each type of boiler is different and boiler 

design impacts need to be addressed in evaluating heat rates.

Commenters stated that the S&L report also does not address the types of coal (bituminous, 

PRB, or lignite) used in power generation. Commenters stated that each of these coals has 

different impacts on the ability to improve heat rate and in addition, many boilers were originally 

designed to burn bituminous coals and were later converted to burn PRB. Commenters stated 

that most of these boilers were significantly derated to burn PRB. Commenters stated that the 

derated plants will not have the same ability to improve heat rate. 

Commenters stated that S&L on page 2-2 discusses adding surface area to the boiler. 

Commenters stated that they point out that units with SCRs most likely cannot add surface area 

to the economizer section since this would impact the performance of the SCR. Commenters 

stated that adding surface area to the economizer section is normally one of the easier and lower 

cost modifications that can be made to a boiler and since approximately 50% of the coal fired 

boilers now have SCRs, this eliminates this option for a large number of boilers. Commenters 

stated that this impacts EPA's estimated heat rate reduction on the coal fleet and since the larger 

boilers were typically retrofitted with SCRs, the% of MWs impacted is even greater.

Commenters stated that S&L correctly points out that the air heater (APH) is the single most 

important area of the combustion train where heat rate improvements can be made and this is one 

area of existing boilers that needs to be looked at with more engineering studies. Commenters 

stated that on page 2-8 S&L highlights the issue that lowering the APH outlet temperature could 

result in acid dew point problems resulting in increased outages due to air heater plugging and 

corrosion in the system. Commenters stated that this issue is even more critical on units with 

SCRs where blue plume issues could result or the SCR limits any temperature changes. 

Commenters questioned if this could trigger NSR (S03 emissions). Commenters stated that 

plants would need to install acid gas controls (OSI) which do have other consequents such as 

impacting ESP performance and the sale of ash. Commenters stated that the MATs rule has 

resulted in the installation of some OSI systems so that these systems can be evaluated if it 

allows plants to lower their APH exit temperatures and most of the so called APH upgrades that 

S&L discusses are actually maintenance items, not upgrades.

Commenters stated that in discussions with air heater manufactures and companies that rebuild 

and maintain air heaters, they all concluded that in most cases replacing circumference and radial 

seals, and basket replacements will only bring an existing air heater back to its original design 

condition. Commenters stated that the S&L data indicated that the costs used in this analysis are 

for bringing an existing air heater to design or as new condition. Commenters stated that most 

APHs cannot be upgraded beyond their original design conditions, however, there are some units 

that can be upgraded to achieve improved heat rates. Commenters stated that these are costly 

upgrades that can run up to $10,000,000 for a 500 MW unit not including outage time cost for 
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improvement of less than 1.8% in heat rate, however, upgrades beyond the original design 

cannot be done on all boilers.

ID and FD Fans. Commenters stated that variable frequency drive (VFD) applications could have 

a positive impact on heat rates and more detailed cost and benefits analysis should be done in 

this area. Commenters stated that with the increase in plant load cycling, the application of VFD 

needs more benefits analysis, however, not all plants are candidates for VFD applications and 

plants that use axial fans would not have a beneficial impact on heat rate if they switched to 

VFD. Commenters stated that there are also limitations on the electrical system in plant and site 

size restrictions that limit the application of VFD motors. 

Wet FGD Systems Improvements. Commenters stated that the S&L report discusses the removal 

of venturi throats, however most of the old venture FGD systems have either been modified or 

taken out of service, so this is not an area that EPA should consider in fleet wide improvement 

database. Commenters stated that modeling of the ductwork and flue gas distribution is a good 

option but this is a very site specific design issue and they do not have a basis for estimating 

improvements fleet wide at this time.

Commenters stated that for WFGD units built after 2004, which is a major part of the fleet, 

modeling has already been done. Commenters stated that the application of VFD recycle pumps 

could be a little tricky. Commenters stated that generally OEMs recommend turning them off as 

load decreases, but in practice many plants just leave them on so they can avoid flushing and 

draining. Commenters stated that limestone slurry tends to form deposits in the spray headers 

and nozzles which plug the lines and will be worse as plants cycle more. Commenters stated one 

would have to limit turndown at times to maintain minimum velocities in the slurry lines 

depending on the application and this may not result in a lot of power saving. Commenters stated 

that at the lower flow, one would see lower header pressures and pressure drops through the 

nozzles, therefore one would also have to account for decreased nozzle performance (larger 

droplets) and possible carry over. Commenters stated that normally, the lower two headers run at 

full capacity, therefore, VFD is not an option on these pumps.

Commenters stated that in the WFGD, the oxidation air blowers are another source of high 

power consumption and not all blowers have turndown controls. Commenters stated that 

Turblex, which is now Siemens, can run with the blowers turned down but many of the Atlas 

Copco blowers simply blow off the excess air so they see no benefit. Commenters stated that one 

could probably save 500 hp. or more by retrofitting the oxidation air blowers alone. 

ESP Power Reductions. Commenters stated that since the S&L report was written in 2009, there 

have been a number of ESP that have already been upgraded with modern voltage controls to 

meet the MATs rule and EPA should survey the industry to determine if this is an option that can 

be added to the list of improvements.

SCR Systems. Commenters stated that the report states that the only power savings readily 

available to reduce power in SCRs is direct injection of ammonia. Commenters stated that 

Babcock Power has used this design feature on their SCRs and Babcock Power has installed 

about 33% of SCRs (by MW) in the US. Commenters stated that therefore, a significant number 

of SCRs cannot take advantage of this power saving design -- also other OEMs may also have 

used this feature since the report was written in 2009.
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Commenters stated that S&L does address other areas of power plants such as steam turbines and 

heat exchanges but has not commented on these areas and these should be addressed by experts 

in these areas. 

Commenters stated that the cost factors used in the S&L report appear to be capital cost only and 

they do not appear to be total cost that a utility would face which leads to another point in EPA 's 

analysis that $100/kW was justified. Commenters asked if EPA's value of $100/kW just capital 

cost or is it total cost including financing and lost revenue for outages. Commenters stated that 

many of the heat rate improvements discussed in the S&L report require outages to implement. 

Commenters stated that Indiana requests that U.S. EPA consider the follow-up release by 

Sargent & Lundy. Commenters stated that in this paper, Sargent & Lundy provide summary 

comments regarding the study used by U.S. EPA in the proposed rule and are clear that the 6% 

heat rate improvements are in fact not attainable. 

Commenters stated that the EPA identifies several "no-cost and low-cost options" from the S&L 

report that it classifies as "best practices," but that there are several key questions the EPA did 

not answer. The commenters questioned if some or all of these measures reduce heat rate 

variability, or just overall heat rate. The commenters also questioned that if some reduce 

variability, EPA should specify which ones. The commenters also questioned that for those that 

do not reduce variability, EPA should clarify if they support a claim that improvements of 4% 

are available through reducing variability. 

Commenters stated that the use of a single study and application of its general conclusions to 

every coal-fired power plant in the country, irrespective of age, class, type, fuel, maintenance 

history, upgrades or any other relevant factors, denies states the ability to undertake considered 

rulemaking to consider the four factors that Congress intended the states to consider in 

establishing performance standards.

Commenters stated that the EPA has not adequately demonstrated the feasibility of the proposed 

emission requirements for Florida under Building Block 1 and that this is supported in part by a 

recent communication by Sargent & Lundy, LLC, which prepared a study on heat rate

improvement that was relied on by EPA in its technical support documentation. Commenters 

stated that Sargent & Lundy, LLC, states that its 2009 report on heat rate improvements "did not 

conclude that any individual coal-fired EGU or aggregation of coal-fired EGUs can achieve six 

percent heat rate improvement or any broad target, as estimated by EPA." Commenters stated 

that moreover, Sargent & Lundy, LLC, notes that the feasibility of heat rate improvements at an 

individual generating unit are limited by "a number of factors, including plant design, previous 

equipment upgrades, and each plant's operational restrictions." 

Commenters quoted a recently released report by Energy Ventures Analysis (EVA) that takes 

issue with each of the assumptions underlying EPA's 6% heat rate improvement requirement for 

Block 1. Commenters stated that first, EPA assumes that a 4% improvement can be achieved by 

using best practices and that this figure was derived from a regression analysis using capacity 

factor and ambient temperature. Commenters stated that EVA notes that EPA has provided 

insufficient data to support its regression analysis and that EPA's analysis very likely failed to 

account for various factors affecting heat rate. Commenters stated that second, EVA notes that 
96

EPA assumed that 2% of the heat rate improvement could come from an average capital upgrade 

investment of $100/kW, which was derived from a 2009 Sargent and Lundy study. Commenters 

stated that EVA concludes that EPA has misinterpreted the Sargent and Lundy study, stating, 

"[n]owhere in the report did Sargent and Lundy conclude that average plant efficiencies for all 

coal-fired plants could be improved from 2008 levels (let alone current levels) by 2% for 

$100/kW. The study 'cautions that the costs provided. . . are not indicative of those that may be 

expected for a specific facility. . . The costs should not be used as a basis for project budgeting or 

financing purposes.' Commenters stated that yet this is precisely what the EPA has done." 

Energy Market Impacts of Recent Federal Regulations On the Electric Power Sector, Energy 

Ventures Analysis, at 12 (Nov. 2014).

Comment 6: Comments regarding the Sierra Club’s 52-Unit Study

Response 6: The response to this comment is addressed by the response to Comment 1 in this 

section. 

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

Commenters stated that in the 52-Unit Study, they examined the long term variability in the 

performance of a representative number of randomly selected coal-fired power plants. 

Commenters stated that in order to assure that the selected plants provided an accurate 

representation of the generation of electricity by the coal-fired EGU population as a whole 

(which would not be the case if focused on a large number of lightly used or smaller plants), the 

52 Unit Study first grouped each plant into a specific "bin" based on its generation in 2012 as 

reported to EPA's AMPD. Commenters stated that it then identified a proportionate number of 

randomly selected plants within each generation bin for further study. Commenters stated that 

selection was based on applying the standard random number generator in Microsoft Excel to 

each bin of units. Commenters stated that additional "standby" candidates were initially 

identified in each bin in case some of the initially identified candidates were excluded from the 

study. Commenters stated that the study did not attempt to ensure that units of different designs 

(such as stoker, wall-fired, or circulating fluidized bed units) were equally represented in the 

sample pool, but information about each unit's design, age, installed pollution controls and 

capacity factor were captured for use in further analysis. Commenters stated that they note that 

the average capacity of units in the study was 597MW and the average capacity factor for those 

units was 0.61. Commenters provided a table (Table 1) that provides a profile of each of the six 

generation bins in the study. Commenters stated that for each selected unit, the study captured 

daily average performance data between January 1, 2001 and December 31, 2012 for heat rate, 

generation, CO2 emission rate, fuel consumption, and criteria pollutant emissions, as well as 

facility data such as the date of first commercial operation, maximum capacity, and installed 

pollution controls. Commenters stated that the data permit a reasonably objective determination 

of the temporal variation in carbon emission rate (CO2/MWh) at subject plants. Commenters 

stated that the study reports rolling annual averages of the daily average emission rates in order 

to minimize the effect of weather and load, to represent long-term trends, and to reflect the 

likelihood that EPA's guidelines will be based on annual average emissions. Commenters stated 

that to illustrate data from one facility in the study, commenters presented Figure 2 (titled: 
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“Cross Unit One Daily Average Emission Rate, 2001-2012”), which depicts the daily average 

emission rate at Cross Unit One during the 12-year study interval. Commenters also provided 

Table 2 results of the 52 Unit Study. 

Commenters noted that EPA proposes a single HRI target to be applied, on average, to all 

remaining coal-fired units in a state and then allows the state to determine whether to apply the 

HRI targets at all. Commenters stated that this approach provides more than enough flexibility to 

rebut any industry argument that individual units might not be able to meet a single proposed 

HRI target. Commenters stated that moreover, EPA need not set a standard that every unit can 

achieve. Commenters stated that to the extent that EPA declines to set the standard based on the 

lowest rolling annual average, however, EPA could set the HRI based on a calculation of the 

95th percentile of the lowest rolling annual average emission rate (instead of the lowest rolling 

annual average emission rate) for each of the affected EGUs in a given state over a long term 

(such as 2001-2012) and an additional four percent reduction of that rate to reflect the 

improvements to be expected from the hardware upgrades. Commenters stated that this emission 

rate, multiplied by the generation from each unit in the year that the target rate is calculated,

would determine the weighted average emission rate that is the Block 1 heat rate improvement 

for the state. 

Commenters stated that in the 52-Unit Study, they also examined the extent to which the fleet's 

daily average emission performance varied with respect to load over the 12-year interval. 

Commenters stated that at some units, there were very large differences in emission rates at the 

same daily load and, indeed, over all load ranges. Commenters provided Figure 3 Powerton Unit 

61 Daily Average Emission Rate, 2001-2012 and Figure 4 Powerton Unit 61 Daily Average 

Emission Rate vs. Gross Daily Load, 2001-2012.

Commenters stated that at other units, including Joppa Steam Unit Two, variation in emission 

performance over most load ranges was far smaller. Commenters provided Figure 5 (titled: 

“Joppa Steam Unit Two Daily Average Emission Rate, 2001-2012” and Figure 6 (titled: “Joppa 

Steam Unit Two Daily Average Emission Rate vs. Gross Daily Load, 2001-2012”). Commenters 

stated that detailed plots for each unit in the study are presented in Appendix 1. Commenters 

stated that these data support a conclusion that factors other than load are responsible for 

significant variation in the reported efficiency of many existing coal-fired EGUs. 

Commenters provided Figure 7 (titled: “Bruce Mansfield Unit Three CO2 Emission Rate v Load 

2001-2012”) and stated that it may be observed that the Bruce Mansfield emission rates trend up 

at lower load as one would expect, but what is notable is the fact that at and near full load, where 

this plant normally operates, the daily emission rate varies from less than 1,500 lbs CO2/MWh to 

2,000 lbs CO2/MWh. Commenters stated that if load, weather and the laws of physics are not the 

controlling factors, the question naturally arises as to whether the observed variances may be 

reasonably be inferred to be due to differences in O&M cycles and practices. Commenters 

believed that these factors are most likely the cause of the variances and that EPA is justified in 

making such an inference in the absence of compelling information to the contrary. Commenters 

stated that these variances are different from the consistent, systematic improvements in 

efficiency that one might expect from installation of combustion optimization tools or equipment 

upgrades. Commenters stated that since the study population is randomly selected and biased 

toward units that produce the most generation (and presumably are maintained better than units 
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that are dispatched less frequently), a conservative estimate for the average expected plant 

improvement through better operation and maintenance of existing equipment is six percent. 

Commenters stated that under the relevant case law the standard does not have to be achievable 

by every single source. 

Commenters stated that the results of the 52-Unit Study demonstrate that, on average, plants 

have achieved and maintained for a year an emission rate that is 7.60 percent better than their 

long term (12-year) average. Commenters stated that the difference between the 95th percentile 

figure and the long-term average is 6.07 percent. Commenters stated that the use of rolling 

annual averages minimizes any short term efficiency variations based on weather, load, or 

equipment upgrades. Commenters stated that because there are differences in the year-over-year 

variation experienced at different units, broadly applicable factors, such as basic principles of 

thermodynamics or weather do not appear to be dominant, since such factors would create 

similar variation across all units. Commenters stated that the Load v. Rate plots in the 52-Unit 

Study reveal a large difference in emission rates even at or near full load. 

Comment 7: RMB Consulting & Research Inc. Real Heat Rate Improvement or Measurement 

Variability/Uncertainty (UARG Attachment G)

Response 7: CO2 has no bias adjustment factor. For the remainder of the issues raised in these 

comments, see section V.C of the final rule preamble of the CPP and chapter 2 of the GHG 

Mitigation Measures TSD supporting the final CPP for EPA’s response to this comment. For the 

reasons noted in those documents, we believe our final assessment of HRI potential is 

comprehensive, reasonable, and appropriate given the nature of this rulemaking.

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

Commenters stated that Part 75 regulations cap the BAF at the lesser of the value calculated from 

Equation 4 or 1.111. Commenters stated that in practice, most BAFs observed by RMB are in the 

1 to 5 percent range. Commenters stated that the reason for presenting the BAF discussion is to 

present another example of how CEMS responses can exhibit step changes of several percent 

completely independently of any change in heat rate or CO2 emission rate. Commenters stated 

that in EPA's discussion of its EGU study population of 884 EGUs, the Agency acknowledges 

the data substitution procedures imposed by Part 75 and how these procedures are designed to 

overestimate emissions. Commenters stated that, however, EPA does not mention how BAFs or 

how BAF-adjusted data were treated in its study/analysis and that in the absence of even the 

acknowledgement of BAF-adjusted data, Commenters believe it is reasonable to assume that 

EPA's analysis failed to account for such data. Commenters stated that changing, adding or 

deleting BAFs will clearly cause CEMS data to exhibit step changes; there is no evidence that 

the EPA analysis accounted for BAF-adjusted Part 75 data. 

Commenters stated that in its GHG Abatement Document, EPA discusses the optional flow 

reference methods the Agency adopted to allow owners to correct for the high biases that can be 

created by non-axial flow and wall effects at some EGUs and that EPA estimated that 

"approximately two thirds of the large decreases in heat rate" in its study population of 355 units 
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can be associated with changes in the flow method used to conduct the annual RATA. 

Commenters stated that although EPA claims that it screened for such reporting changes when it 

selected the 16 reference units, several owners report significant reductions in heat input 

associated with a change in flow methods.

Commenters stated that based upon the analytical approach described in the previously 

referenced GHG Abatement Document and the data presented in the attached graphs, EPA would 

likely conclude that significant heat rate improvement projects had been conducted. Commenters 

stated that to the contrary, RMB assisted the plant in (1) performing a more accurate reference 

method testing to determine the volumetric flow (i.e., EPA Method 2F instead of Method 2) and 

recalibrating the two stack flow monitors based on the more accurate reference method data, and 

(2) implementing the wall effects correction factor (Method 2H). There was no change in the 

heat rate of either unit.

Commenters questioned how EPA missed the impact of such changes in its "screening" process,

and continued stating that it might be argued that RMB possessed "inside" information regarding 

the case study presented above; information above and beyond what an EPA analysis could have 

reasonably obtained. Commenters disagreed for the following reasons: First, if the significant 

decrease in CO2 emission rate depicted on the attached graphs were the result of heat rate 

improvement projects, you would have expected the decrease to occur after the unit had been off 

line (to allow the heat rate project to be conducted). Clearly, this was not the case. Second, EPA 

could have easily verified whether the change in CO2 emission rate was the result of a recent 

relative accuracy test. The relative accuracy test audit (RATA) data are readily available using 

EPA's Emission Collection and Monitoring System (ECMPS) software. The following important 

information is available from a RATA report.

• Test method used (e.g., Method 2, 2F, or 2G)

• Number of loads for which a flow RATA was conducted

• Bias adjustment factor (BAF) required, if any.

• Wall-effects adjustment factocommentr (WAF) (whether default value or 

calculated).

Commenters stated that, depending upon the flow pattern that exists within the stack, application 

of any one of the three acceptable EPA reference methods can yield results that vary from one of 

the other EPA reference methods by several percent. Commenters stated that the calibration of a 

flow monitor can easily change following a relative accuracy test -- if an EGU owner/operator 

has elected to change from one EPA reference method (e.g., Method 2) to another (e.g., Method 

2G).

Comment 8: Critique the of EPA's Use of Reference Units to Select Heat Rate Reduction 

Targets 
100

Response 8: The response to this comment is addressed by the response to Comment 1 in this 

section. Furthermore, with respect to the 16 units referenced by commenters, the EPA decided 

not to include a separate identification of the average quantity of heat rate improvement

achievable solely through equipment upgrades, for the reasons stated in section V.C of the final 

rule preamble of the CPP and Chapter 2 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 in a report titled "Critique of EPA's Use of Reference Units to Select 

Heat Rate Reduction Targets," ("Reference Unit Critique"), their consultants summarized 

information they obtained from the owners of 14 of the 16 units regarding likely causes of the 

supposed heat rate improvements. Commenters stated that the report illustrated that most 

changes in heat rate calculated from the Part 75 reported data were due to unrelated normal 

variations in continuous emissions monitoring system (CEMS)-based heat input values, and not 

the result of proactive steps to reduce heat rate. Commenters stated further that as a supplement 

to that report, they asked RMB Consulting & Research, Inc. (RMB) to review the summaries of 

the owners' explanations and more fully explain some of the sources of unrelated normal 

variability in reported Part 75 heat input data that could result in year-to-year changes in heat 

rates calculated from Part 75 data. Commenters stated that RMB is eminently qualified to 

comment on CEMS technical issues because the RMB staff has been involved with the Part 75 

CEMS requirements since their inception circa 1992. Commenters stated that although the Part 

75 data used by EPA meet stringent quality assurance criteria, all Part 75 CEMS measurements 

used to calculate heat input are subject to variability the cause of which may not be apparent 

when the data are viewed as annual averages and that, in addition, provisions in Part 75 that 

allow for, or require, adjustment of monitored data create inherent biases in the data that limit 

how the data can be used.

Comment 9: Cichanowicz Heat Rate Report (prepared for UARG)

Response 9: The response to this comment is addressed under Comment 1 in this section.

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

Commenters stated that as discussed in the Cichanowicz Heat Rate Report, EPA does not 

account for the fact that the efficiency benefits associated with the measures identified in the 

2009 Sargent & Lundy report are highly variable by unit, are not cumulative, and degrade over 

time (Cichanowicz Heat Rate Report at 3-1 to 3-2).

Commenters stated that a recent report by the National Coal Council, a federal advisory 

committee to the U.S. Secretary of Energy, highlighted these basic facts, noting that "[t]he 

opportunity to apply these efficiency improvements across the existing fleet will vary 

significantly (" National Coal Council, "Reliable & Resilient" The Value of Our Existing Fleet: 

An Assessment of Measures to Improve Reliability & Efficiency While Reducing Emissions" at 

4 (May 2014) ("NCC Report"), available at 

http://www.nationalcoalcouncil.org/NEWS/NCCValueExistingCoalFleet.pdf - included in the 
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commenters' separately filed Supplemental Materials for the Rulemaking Record)]. Commenters 

stated that measures that may improve heat rate at an individual plant by as much as 1 percent 

may yield only negligible or nonexistent benefits at many others that have already implemented 

similar measures or that are otherwise operating in a highly efficient manner. Id.

Commenters continued that likewise, many of the available actions to improve heat rate do not

provide cumulative benefits and thus cannot be added together to estimate the potential 

efficiency gains at coal-fired EGUs. Cichanowicz Heat Rate Report at 4-4; in particular, 

measures that increase heat removal from the boiler, such as economizer modifications, 

improved air heater performance, and low temperature heat recovery, do not provide additive 

efficiency benefits because any heat that is recovered by an individual project cannot be 

recovered a second time (NCC Report at 69).

Commenters added that, to the extent that any measures to improve heat rate are available at a 

given unit, the long-term payoffs of many of these measures are significantly smaller than the 

immediate reduction in heat rate observed after implementation (Id. at 70) and that upgraded 

components begin to incur wear as soon as they return to operation, and will need to be replaced 

themselves eventually in order to maintain the improved heat rate. Commenters provided the 

example that, while a steam turbine upgrade may improve a unit's heat rate below its design 

level, gradual degradation of the turbine blades will reduce the magnitude of that improvement 

over time from the "new" state without periodic overhauls (Cichanowicz Heat Rate Report at 4-3 

to 4-4). Commenters stated that field data indicate that the efficiency of a steam turbine retrofit 

may decline by 0.5 percentage points in the first 6 months, and by about 4 percentage points after 

10 years. Id. at 4-4.

Commenters further stated that numerous other analyses have noted the same issues regarding 

the practical limits on benefits from heat rate improvement measures. Commenters mentioned 

that a new analysis by Sargent & Lundy (prepared in support of the National Rural Electric 

Cooperative Association's ("NRECA") comments on the Proposed Guidelines) is highly critical 

of the Agency's use of the 2009 Sargent & Lundy report to support the Proposed Guidelines. 

Commenters stated that in the new analysis, Sargent & Lundy conclude that EPA greatly 

exaggerated the amount of heat rate improvements that can realistically be expected at coal-fired 

EGUs. Commenters stated that this report emphasizes many of the same issues noted by their

consultants in the Cichanowicz Heat Rate Report, including the fact that actual benefits from 

many heat rate improvement methods are non-additive, temporal, and highly site-specific, and 

that, among other conclusions, the 2014 Sargent & Lundy analysis specifically disavows EPA's 

reliance on the earlier report, stating that "Sargent & Lundy's 2009 report does not conclude that 

any individual coal-fired EGU or any aggregation of coal-fired EGUs can achieve 6% heat rate 

improvement ... or any broad target, as assumed by the EPA." Id. at C-1.Commenters stated that 

Sargent & Lundy also note that the potential benefits cited in their 2009 report "were estimated 

at a conceptual level and were not based on detailed site-specific analyses." Id.

Commenters stated that the conclusions reached by their consultants in the Cichanowicz Heat 

Rate Report and the 2014 Sargent & Lundy report are further corroborated by similar analyses 

performed by EPRI and by the National Coal Council.
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Comment 10: Comments regarding NETL studies and workshops in general

Response 10: The response to this comment is addressed by the response to Comment 1 in this 

section. The proposal TSD’s single mention of “the NETL studies” was a reference to the NETL 

studies cited, described, and contextualized in the proposal TSD. Commenters had sufficient 

information to provide meaningful comment on the technical basis for the proposed rulemaking. 

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

Commenters stated that EPA cites several "studies" by the National Energy Technology 

Laboratory ("NETL") but EPA does not, however, provide complete versions of these studies in 

the record, and at least one (the 2008 study) appears to be only a deck of slides and the link 

provided for another does not contain the referenced study (the 2010 study). Commenters stated 

that even within the text of the TSD, EPA only discusses "the NETL studies" generally and thus, 

it is not possible to provide meaningful comment on EPA's use of these NETL studies because 

the record is not complete nor is EPA's analysis adequately explained.

Commenters stated that what could be discerned from the various NETL studies that are 

available indicates that those studies do not support EPA's conclusions under block 1. 

Commenters stated that the April 2010 NETL study listed potential heat rate improvement 

projects based on a literature review and unlike EPA's assessment, NETL grouped units based on 

fuel type, steam cycle, and size. Commenters stated that the NETL study looked at the bottom 

90% of the EGU heat rates and assumed that each group could improve its heat rate to the 

average performance of the top 10% of the group. Commenters stated that the NETL study is 

based specifically on unit heat rate performance from 1998 to 2008.

Commenters stated that none of the NETL studies constitute the type of comprehensive unitspecific analysis needed to set heat rate goals. Commenters stated that the April 2010 NETL 

study claims only to "set forth a vision for coal-fueled power plant ("CFPP")] fleet-wide average 

efficiency of 36% based on (1) retirements of lower efficiency units combined with increased 

generation from higher efficiency refurbished units and (2) advanced refurbishments and 

improved operation and maintenance practices to increase average efficiency of some segments 

beyond the best-in-class "and thus, NETL's review considers measures outside of block 1-

namely, the retirement of existing units. Commenters stated that furthermore, "[t]he 36% CFPP 

fleet efficiency target does not take into account installing sulfur scrubbers at facilities that lack 

controls," which would induce a heat rate penalty. Commenters stated that further, the total heat 

rate improvement that NETL targets across the U.S. fleet - 2.7% - takes into account both best 

operational and maintenance practices and refurbishments, and is well below the 6% that EPA's 

proposal would target and the 4% "alternative" target. Commenters stated that the NETL study 

also "considered that units may achieve their best year efficiency when they are running at 

maximum load," which is not how EPA is projecting coal units will operate under its proposal. 

Commenters stated that the NETL study is not conclusive and recognizes that substantial 

additional work would need to be performed to determine if the 36% fleet-wide efficiency is 

even feasible. 

Commenters stated that other relevant reports and studies have been carried out that address the 

complexities, opportunities and challenges associated with heat rate improvements. EPA failed 
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to consider these reports and the issues they raise. Commenters stated that for instance, in 2009 

and 2010, US DOE and NETL sponsored industry workshops specifically targeted toward 

opportunities to improve the efficiency (heat rate) of existing coal-fired power plants. 

Commenters stated that these workshops brought together industry experts, utility owners and 

operators, equipment suppliers, consultants, industry associations, and research organizations to 

explore heat rate improvement. Commenters stated that key takeaways from the workshops were 

documented and several are listed below:

• "The heat rate of a coal-fired power plant is costly and difficult to accurately 

measure in real-time."

• "Better national data on plant efficiency is needed, but this is hindered by the 

variation in methods and accuracy for measuring plant heat rate."

• "Without adequate heat rate data, it will be difficult to monitor improvements in 

the overall efficiency of the U.S. fleet of coal-fired power plants."

• "Plant operators often lack sufficient monitoring tools or measurement 

frameworks to measure both baselines and future improvements for a given 

process."

• "The industry also lacks clear guidelines and standards for measuring and 

reporting efficiency improvements."

• "Hard to make a business case for something one cannot measure (heat rate)"

• Four of the top five barriers and challenges identified that inhibit the adoption and 

application of technical options to improve heat rate were:

− Age of fleet prevents significant changes

− Inability to compare plants on a similar basis

− Difficult to measure improvement and monetize benefits

− Efficiency is limited by exiting design

Commenters stated that these issues and concerns still exist, and further support the fact that 

achieving, measuring, and sustaining a 6% heat rate improvement across the fleet is simply not 

practical.

Commenters provided an appendix with a workshop report from a conference held July 15-15, 

2009 and sponsored by the National Energy Technology Laboratory. Commenters said the 

workshop report was entitled "Opportunities to Improve the Efficiency of Existing Coal-Fired 

Power Plants". Commenters stated the report discussed ways of increasing the thermal efficiency 

of the existing U.S. fleet of coal-fired power plants.
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Comment 11: Comments regarding the availability of the NETL report, "Reducing CO2 

Emissions by Improving the Efficiency of the Existing Coal-Fired Power Plant Fleet”

Response 11: The proposal TSD appropriately presented the summarized information from 

NETL that EPA used at the proposal stage. In addition, the EPA included sufficient bibliographic 

information to identify the report referenced by the commenters, and included the URL for the 

NETL presentation by the same name that summarized the report’s relevant conclusions. The 

information upon which EPA relied for that portion of the proposal TSD was contained in the 

hyperlinked presentation—a presentation that has itself been directly cited in numerous 

publications by respected institutions, including the Congressional Research Service. The 

proposal TSD provided a full airing of the reasoning undergirding the proposed rulemaking, and 

allowed for meaningful technical comment of the type found throughout section 3.1.

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

Commenters stated that the EPA TSD references a NETL report, entitled "Reducing CO2 

Emissions by Improving the Efficiency of the Existing Coal-Fired Power Plant Fleet;" however, 

the link provided in the TSD is to a deck of slides and charts describing the NETL report, not the 

full report. Commenters stated that no link is provided to the full report or any text which might 

explain the data in the slides and additional searches to uncover the complete report were 

unsuccessful. Commenters stated that without the underlying text of the report, the 

administrative record is incomplete, and it is unclear as to whether NETL discussed the 

challenges and limitations to efficiency improvements.

Comment 12: 2010 NETL report, entitled "Improving the Efficiency of Coal-Fired Power Plants 

for Near Term Greenhouse Gas Emission Reductions

Response 12: The response to this comment is addressed by the response to Comment 1 in this 

section. 

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

Commenters stated that a 2010 NETL report, entitled "Improving the Efficiency of Coal-Fired 

Power Plants for Near Term Greenhouse Gas Emission Reductions," examined 10 years (1998-

2008) of unit efficiency data from 892 coal-fired units and while the report projected that 

efficiency improvements across the fleet were possible, key takeaways from the NETL analysis 

were:

• Load factors (ratio of average load to peak load) for the top decile of the units 

studied averaged 83%, meaning that these units, when operating, operated at 

nearly full load, and their performance would not be achievable by units operating 

at lower load factors.

• NETL acknowledged that quantification of the opportunity to improve efficiency 

could be improved by things such as:
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− Verification of the data;

− Unit-specific data to enable estimation of the heat rates

− Estimates of the costs to improve efficiency; and

− Case studies at specific units and computer models to provide more details 

into the opportunities to improve heat rate.

Commenters stated that the bulleted items above indicate that NETL had an appreciation for the 

variability, possible inaccuracy, and overall feasibility of the heat rate improvement potential 

which they analyzed. Commenters stated that the report suggests that these items should be 

considered to better assess the improvement opportunity. Commenters stated that EPA ignored 

such language in the NETL report and simply cited the report as a reference for their 

determination of achievable improvements. 

Comment 13: Comments regarding the Lehigh University study, "Reducing Heat Rates of CoalFired Power Plants"

Response 13: The response to this comment is addressed by the response to Comment 1 in this

section. Furthermore, as discussed in section V.C of the final rule preamble of the CPP and 

Chapter 2 of the GHG Mitigation Measures TSD supporting the final CPP, the EPA agrees that 

the degree to which individual coal-fired EGUs can implement heat rate improvement measures 

will vary. 

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

Commenters stated that EPA cites a very brief two-page report, entitled "Reducing Heat Rates of 

Coal-Fired Power Plants," from Lehigh University, that relies upon high-level conceptual 

information regarding heat rate improvement options and very general reduction percentages.

Commenters stated that the Lehigh report does a poor job of characterizing the unit-specific 

nature of heat rate improvements and fails to discuss factors that affect heat rate improvement, 

but does, however, accurately state that "it would not be possible to take full advantage of all 

possible improvements on every coal-fired unit," but does not provide any substantiated evidence 

as to what level of improvement is achievable. Commenters stated that examples provided in the 

report are largely comprised of unsupported conceptual estimates and/or limited operational data 

and there is no real data on which EPA could base any determination of achievable heat rate 

improvement.

Commenters provided an appendix from the Lehigh Energy Update published January 2009 

entitled "REDUCING HEAT RATES OF COAL-FIRED POWER PLANTS". Commenters 

stated the article discusses research projects investigating heat rate improvements in coal-fired 

power plants. 
106

Comment 14: Comments regarding the Resources for the Future study, "Regulating Greenhouse 

Gases from Coal Power Plants under the Clean Air Act"

Response 14: The response to this comment is addressed by the response to Comment 1 in this 

section.

Commenters stated that a paper from Resources for the Future, entitled "Regulating Greenhouse 

Gases from Coal Power Plants under the Clean Air Act," does not attempt to assess or evaluate 

what percentage of heat rate improvement exists on coal-fired generating units, but rather relies 

upon an EPA statement from the 2008 "Technical Support Document for the Advance Notice of 

Proposed Rulemaking for Greenhouse Gases: Stationary Sources," in which EPA then estimated 

that a 2-5% efficiency improvement was possible, along with additional references to the 2009 

S&L report. Commenters stated that the authors do, however, acknowledge that "significant 

analysis and expertise are required to find the optimal combination of [heat rate] upgrades and 

techniques, if any, for each specific plant."

Commenters stated that the paper considers how market and/or regulatory impacts might 

influence or "force" the realization of heat rate improvements. Commenters stated that in similar 

fashion to other EPA references in the TSD, the entire report is based on the assumption that 

EPA's estimates for improvement potential from the measures discussed in the S&L report are 

achievable across the fleet, which is simply not the case.

Commenters stated that the EPA identified a number of measures that could improve efficiencies 

at coal-fired power plants and quantified the level of improvement each could achieve. 

Commenters stated that while some stakeholders have raised concerns about the viability of this 

level of HRI (especially for newer plants) several technical studies support the conclusion that 

higher improvements are possible and cost effective over the entire fleet. Commenters stated that 

resources for the Future (RFF) analyzed performance data for coal plants in 2008, sorted by 

boiler type, and found the average HRI would be 5.5 percent if each plant matched the best 

performing (top 10 percent) plants in its class. Commenters stated that RFF concluded that the 6 

percent figure is technically plausible and economically reasonable. Commenters stated that the 

National Energy Technology Lab has laid out a vision for improving the nation's coal fleet from 

32.5 percent efficiency to 36 percent. 

Comment 15: Comments regarding the NRDC study, "Closing the Power Plant Carbon 

Pollution Loophole"

Response 15: The response to this comment is addressed by the response to Comment 1 in this 

section. The EPA agrees with the propositions that the benefits of heat rate improvement 

measures are not always additive, and that the overall potential for heat rate improvement varies 

among individual EGUs.

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

Commenters stated that NRDC prepared a report, entitled "Closing the Power Plant Carbon 

Pollution Loophole," that relies heavily on the same 2009 S&L report used by EPA in the 
107

proposed rulemaking to characterize and support its assumptions for heat rate improvement. 

Commenters stated that NRDC provided a table in Appendix V to show that the technical heat 

rate improvement options addressed conceptually in the S&L report were simply added to 

determine the total available heat rate improvement potential. Commenters stated that for reasons 

stated earlier in this report, this is simply not a practical feasible approach, and the S&L technical 

information was not intended to characterize the actual heat rate improvement potential for any 

one unit or group of units. 

Comment 16: ASME's Research Committee on Energy, Environment and Waste "The Case for 

Fuel Delivery System Upgrades on Utility Boilers"

Response 16: The response to this comment is addressed by the response to Comment 1 in this 

section.

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

Commenters stated that EPA states that an additional 2% of heat rate improvements to get to 6% 

are available with some expense (presumably, most of that $100/kW). Commenters stated that, to 

put things in perspective, $100/kW is about one fifth the cost of a wet scrubber which is an 

expense that is not excessive for most power plants. Commenters stated that the one sticking 

point is concern about New Source Review. Commenters stated that in a 2013 paper published in 

Power Magazine prepared by ASME's Research Committee on Energy, Environment and Waste 

titled "The Case for Fuel Delivery System Upgrades on Utility Boilers" they found that by 

upgrading the fuel delivery system they could achieve a 0.34% improvement in boiler efficiency 

on a 500 MW wall fired coal boiler at a cost of $13,600,000. Commenters also stated that a 

major steam turbine overall/upgrade for a 500 MW can cost between $30-50 million.

Comment 17: Comments regarding the article by Linn, Mastrangelo and Burtraw, funded in part 

by EPA and DOE

Response 17: The response to this comment is addressed by the response to Comment 1 in this 

section.

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

Commenters stated that an article by Linn, Mastrangelo and Burtraw, funded in part by EPA and 

DOE, examined data from 1985-2009 and attempted to control for firing type, capacity and fuel 

type and found significant heterogeneity in the data. Commenters stated that the heterogeneity in 

the data after factoring in these three technical features was evidence, they believed, that there 

was room to improve efficiency - by roughly 6% and that they did not consider that the 

unexplained variation might actually be because they had not fully considered all of the key 

parameters beyond the facility's ability to control that impact heat rate - more than just the three 

parameters they considered. Commenters stated that the authors make several errors in their 

analysis, among them:
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• Commenters stated that they limited the technical factors beyond the facility's 

control over this period to only three parameters. Commenters stated that this is 

an inherently technical decision in their analysis; yet, no engineers contributed to 

this study. Commenters stated that engineers familiar with the operation of 

electric power plants are well aware that the factors that impact heat rate that are 

beyond the operator's ability to control are many more than three. Commenters 

stated that this critical flaw results in them mistaking the variability in heat rate 

that was not explained by only three factors as opportunities to improve heat rate.

• Commenters stated that they offer pass-through of fuel (for regulated utilities) as a 

reason that utilities are not motivated to improve heat rate. Commenters stated 

this ignores the fact that many coal power plants operate in deregulated markets 

where companies competitively bid and such pass through is not allowed, and that 

utilities in regulated markets can sell their power into these deregulated markets. 

Commenters stated that it also dismisses the oversight role of utility commissions 

and the economic incentive for regulated utilities to make capital investments that 

benefit the consumer with lower fuel costs. Commenters stated that therefore, this 

explanation of theirs is incorrect.

• Commenters stated that they identified how the boiler is used in the electricity 

system as a factor that affects heat rate that is under the control of the firm. 

Commenters stated this is fundamentally incorrect. Commenters stated the firm 

has no control over how the unit is dispatched and that this is determined 

according to the economic order of dispatch determined by the Independent 

System Operator. Commenters stated that even vertically integrated utilities with 

regulated markets units must dispatch using an economic dispatch order that is 

beyond the plant's control. 

Comment 18: Applicable to the supplemental proposal for Tribal and Territorial - Article by 

Linn, Mastrangelo and Burtraw, funded in part by the EPA and the DOE

Response 18: The response to this comment is addressed by the response to Comment 1 in this 

section.

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

Commenters stated that EPA has funded an article by Linn, Mastrangelo and Burtraw that 

presents the findings of work funded in part by EPA and the US Department of Energy. 

Commenters stated that this study examined fuel use and generation data from 1985-2009 and 

after controlling for firing type, capacity and fuel type, significant variability was found in the 

heat rate data. Commenters stated that the authors believed that the variability in the heat rates 

after considering these three technical features was evidence that there was room to improve 

efficiency by roughly 6% on average and similar to EPA's analysis, however, they did not 

consider the possibility that the unexplained variation might actually be the result of other key 
109

parameters that impact heat rate and are beyond the facility's ability to control. Commenters 

stated that the authors make several errors in their analysis, among them:

Commenters stated that they limit the technical factors beyond the facility's control over this 

twenty-five year period to only three parameters and that this is an inherently technical decision 

in their analysis; yet, no engineers contributed to this study. Commenters stated that engineers 

familiar with the operation of electric power plants are well aware that there are many more than 

three factors that impact heat rate and are beyond the operator's ability to control. Commenters 

stated that this critical flaw results in the authors mistaking the variability in heat rate that was 

not explained by only three factors over this long period as opportunities to improve heat rate.

Commenters stated that they offer pass-through of fuel (for regulated utilities) as a reason that 

utilities are not motivated to improve heat rate but this explanation ignores the fact that many 

coal power plants operate in deregulated markets where companies competitively bid to supply 

power into the market and pass-through of fuel cost does not occur. Commenters stated that even 

utilities in regulated markets may bid their power into these deregulated markets and it also 

dismisses the oversight role of utility commissions and the economic incentive for regulated 

utilities to make capital investments that benefit the consumer with lower fuel costs. Commenters 

stated that for these reasons plant operators are both motivated and incentivized to minimize fuel 

cost.

Commenters stated that they identify how the boiler is used in the electricity system as a factor 

that affects heat rate that is under the control of the plant owner or operator as opposed to being a 

factor beyond the operator's control and that this assumption is fundamentally incorrect. 

Commenters stated that the plant owner or operator has no control over how the unit is 

dispatched and dispatch takes place according to the economic order of dispatch determined by 

the Independent System Operator. Commenters stated that even vertically integrated utilities that 

operate in regulated markets must dispatch using an economic dispatch order that is beyond the 

plant's control. Commenters stated that the operator can only influence the dispatch order by 

trying to make their plant as economical as possible, which includes efforts to minimize fuel 

cost.

Commenters stated that as a result, the conclusions drawn from EPA's statistical analysis, from 

the analysis by Lim, et. al., and from other studies with similar errors, are not reliable.

Comment 19: Comments regarding the IEA Clean Coal Centre report, "Efficiency and 

emissions monitoring and reporting" (2011)

Response 19: The response to this comment is addressed by the response to Comment 1 in this 

section.

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

Commenters provided an article published October 2011 by the IEA Clean Coal Centre entitled 

"Efficiency and emissions monitoring and reporting". Commenters stated the article discussed 

power plant efficiency. 
110

Comment 20: Topic Paper #4 Electric Generation Efficiency, July 18, 2007

Response 20: The response to this comment is addressed by the response to Comment 1 in this 

section.

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

Commenters provided an appendix with a paper entitled "Topic Paper #4 Electric Generation 

Efficiency". Commenters stated the paper was published on July 18, 2007. The paper discussed 

improvements that would make existing coal-fired power plants more efficient. 

3.1.4 EPA's heat rate improvement assessment

This section discusses specifics of the EPA’s heat rate improvement assessment as it applies to 

coal-fired units. Heat rate improvements (HRI) are changes implemented at an EGU that increase 

the efficiency with which the EGU converts fuel energy to electric energy, thereby reducing the 

amount of fuel needed to produce the same amount of electricity and consequently lowering the 

amount of CO2 produced as a byproduct of fuel combustion. For the proposal, the EPA 

conducted several analyses to assess the potential for heat rate improvements from the coal-fired 

EGU fleet. The comments in this section address the EPA’s methodology for determining the 

amount of heat rate improvement appropriately included in the BSER as building block 1. That 

methodology is further discussed in section V.C of the preamble, and in Chapter 2 of the GHG 

Mitigation Measures TSD.

Commenters have raised a number of issues related to this subsection which are organized by 

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

Comment 1: Commenters asserted that the EPA’s heat rate assessment fails to consider a

variety of factors that impact heat rate.

Response 1: The EPA appreciates commenters’ identification of factors that commenters

believe the EPA failed to take into account when evaluating HRI. Where appropriate, the EPA 

has evaluated the potential impact of these factors on its heat rate assessment. For the EPA’s 

response to these comments, see section V.C of the final rule preamble of the CPP and Chapter 2 

of the GHG Mitigation Measures TSD supporting the final CPP. For example, electricity demand 

is accounted for by way of capacity factor, and is also addressed by IPM. Furthermore, the EPA 

relied on an 884-EGU dataset that reflects many of the factors highlighted by commenters. 

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

Commenters stated that when evaluating heat rate reduction strategies, it is important to consider

the limitations of each HRI strategy. Commenters stated that the type of fuel burned at a unit can 
111

impact the potential HRI methods because heating value, sulfur content, and moisture content are 

important components that affect a plant's heat rate and that the age of a power plant will also 

affect the applicability of HRI methods, as units designed in the last 10-15 years were designed 

with the lowest possible heat rate for supercritical and subcritical steam cycles. Commenters 

stated that newer units will likely have the most efficient equipment/configuration already 

implemented; cross-flow cooling towers, dense pack turbine, VFDs on fans, etc. Commenters 

added that site spatial constraints can also play a role in heat rate improvement project options, 

including access issues and available square footage and that, finally, installing some types of air 

pollution control equipment may limit the applicability of some HRI strategies or even lead to 

net heat rate increases. Commenters stated that additionally, the installation of additional 

pollution controls such as that required by regulations including BART, MATS, etc. will increase 

the net unit heat rate (NUHR) of any unit as compared to its NUHR before the installation due to 

use of auxiliary power.

Commenters stated that despite acknowledging the number of design and operational variables, 

as well as site specific factors that affect heat rate performance, EPA fails to adequately consider 

and apply this knowledge in its evaluation of potential improvement opportunities and in its 

BSER determination. Commenters stated an expanded discussion of these fundamental issues is 

provided in Appendix A, which contains a white paper they developed regarding heat rate issues 

and potential improvement opportunities at coal-based generating plants. 

Commenters stated that EPA's first proposed strategy for reducing CO2 emissions from EGUs 

consists of changes to individual EGUs. Commenters identified several issues with Building 

Block 1:

• The assumed 6 percent heat rate improvement capability,

• The effects of other environmental regulations on heat rate, and

• The time period needed to implement heat rate improvements. 

Commenters stated that there is a steady decline of heat rate for coal-fired units during long runs 

of operation and, additionally, heat rate is negatively impacted by cycling through load range, 

which coal plants will have to do to support grid and load requirements if they are forced to 

redispatch to NGCC units, as contemplated by building block 2. Commenters also stated that the 

performance of some heat rate improvement technologies degrades over time, even with best 

maintenance practices. Commenters stated thus, the unit heat rate initially obtained through the 

implementation of new heat rate improvement technologies will likely increase over time. 

Commenters stated that EPA ignores the adverse effect on heat rate that implementing the other 

Building Blocks will have

Commenters summarized EPA's heat rate analysis and listed the following issues:

• Heat rate assumptions are incorrect.

• Not all EGUs are created equally
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• Lower loads equal higher heat rates

• MATS-related improvements raise net heat rates.

• Improvements may trigger New Source Review ("NSR") process.

• Empirical modeling used in heat rate analysis is flawed.

• EPA fails to consider the potential stranded costs and rate impacts associated with 

its recommendations.

Commenters stated that the proposed ESPS emission reduction goals for the states are all based 

on four compliance building blocks (BBs) that were developed considering national and regional 

assumptions and costs that may not translate to a state and its utilities which is especially the 

case regarding EPA's assumed 6% efficiency improvements for coal units, since Florida's 

relatively new coal-fired generating fleet already employs most of the available cost-effective 

heat rate improvements. Commenters stated that in addition, many FMEA utilities undertook 

additional energy efficiency improvement projects to offset the parasitic load additions

associated with air pollution control systems added to comply with CAIR and the utility MATS 

rules. Commenters believed that the State of Florida needs to have the authority to adjust BB #1 

based on the energy efficiency improvements already employed by existing EGUs and in 

addition, it is unreasonable for EPA to assume that a 6% efficiency improvement of the coal fleet 

is even possible based on the fact EPA predicts that 91% of coal-fired energy will be redispatched to natural gas-fired combine cycle (NGCC) units. Commenters stated that at a 

minimum, the Florida emission limiting standard goals should be adjusted to reflect this fact. 

Commenters stated that EPA developed building block 1 by assuming an amount of 

improvement identified in the Sargent and Lundy report for each HRI action but these values 

appear to represent the amount of improvement that may be gained in the first year the action is 

implemented, not over the long-term. Commenters stated that for example, Wisconsin utilities 

closely monitor and maintain steam turbine operation, because heat rates will indeed degrade 

over time. Commenters stated that however, opening the turbines for maintenance is a significant 

endeavor requiring careful planning and many Wisconsin utilities perform turbine maintenance 

every 5 to 8 years. Commenters stated that under this schedule, the heat rate of Wisconsin's 

vintage coal-fired EGUs has improved over time, thus, EPA cannot assume that a more frequent 

turbine maintenance schedule is appropriate for Wisconsin EGUs. Commenters stated that in 

fact, new turbines are designed to be opened up only after 10 years or more of operation and 

therefore, when calculating building block 1, EPA must allow for reasonable maintenance 

cycles. Commenters stated that the best way to do this is to hold EGUs to the heat rate that is 

expected at the end of the maintenance cycle. Commenters stated that this approach should apply 

to other building block 1 HRI actions as well as air heater leakage, condenser cleaning, boiler 

feedpump rebuilding and economizer replacement. 

Commenters stated that heat rate improvements of 4-6% as described by EPA are not achievable 

at Nebraska coal-fired power plants. Commenters stated that Nebraska utilities are required by 

law to deliver least-cost, reliable electricity; as such, they have already implemented most if not 

all achievable heat rate improvements at existing facilities. Commenters stated that any 
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remaining improvements will be far more modest than the EPA's 4-6%, and these gains will 

likely be offset by efficiency losses resulting from additional controls needed to comply with the 

Mercury Air Toxics Standards (MATS), Regional Haze Rule, the Cross-State Air Pollution Rule 

(CSAPR), and the sulfur dioxide (SO2) National Ambient Air Quality Standards (NAAQS). 

Commenters stated that coal-fired power plants are also facing more frequent ramping, cycling, 

and startup/shutdown events resulting from greater use of natural gas and renewable generation 

facilities and all of these factors lower the efficiency of coal-fired power plants and increase their 

emission rate, putting the EPA's 4-6% heat rate improvement even further out of reach.

Commenters stated that under the Proposed Rule, EPA first assumes that all coal-fired steam 

EGUs can achieve a 6% heat rate improvement and to support this assertion, EPA claims that 

affected coal-fired steam EGUs can obtain an average 4% heat rate improvement by adopting 

operating "best practices," and an additional 2% improvement, on average, through equipment 

upgrades. Commenters stated that these assumptions are unrealistic and unachievable for most 

EGUs and for example, they have already implemented most of the best practices and equipment 

upgrades identified by EPA - a situation that is typical for most of the industry. Commenters 

stated that furthermore, to the extent that some equipment upgrades may be available, the costs 

of implementing these upgrades at affected units would generally be prohibitive and additionally, 

EPA's approach fails to consider the impact of subsequent building blocks on the emission rate 

reductions that could be achievable at coal-fired steam EGUs

Commenters stated that not all heat rate improvements are cumulative, and some solutions may 

be limited in certain cases. Commenters stated that plant design and configuration vary across 

the fleet, and operational and load profiles are changing and this places additional constraints on 

the amount of heat rate improvement that can be achieved. Commenters stated that furthermore, 

various solutions may not interact in an economically viable way, thus limiting adoption of some 

heat rate improvement options. 

Commenters stated that the EPA has suggested that State's adopt an across-the-board 

requirement for heat rate improvements (HRI) on coal-fired EGU's. Commenters stated that this 

requirement is impractical and unachievable because:

• HRI is unit dependent; 

• The proposal does not credit efforts already implemented for HRI, and thus

The proposal penalizes units with existing low heat rates;

• That actual HRI achievable across the board is substantially less that purported;

• That the re-dispatch requirements under Building Block 2 will negate any HRI 

that might be achieved because load cycling at loads of lower efficiencies will 

increase heat rates of coal plants; and, 

• Modifications required to meet HRI goals will likely require PSD re-permitting.

Commenters stated that EPA's assumes that coal-fired power plants can reduce their emissions 

by 6% by implementing heat rate improvements but the Agency does not base this assumption 

on an actual analysis of each state's plant conditions. Commenters stated that instead, it simply 

used national reporting continuous Emissions Monitoring ("CEMs") data as a springboard for 

bold assertions that the relied-upon data does not support. Commenters stated that specifically, 
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EPA breaks up the justification for its assumption into two categories: (1) best practices for 

operation and maintenance; and (2) equipment upgrades. Commenters stated that for the best 

practices portion of its assumption, EPA analyzed the hourly data these plants reported to the 

EPA from 2002-2012, which included hourly heat input and, for most EGUs, hourly gross 

generation and after analyzing this data, it determined a range of 1.3% to 6.7% potential for 

improvement in the average heat rate of the entire national fleet of coal-fired EGUs as a result of 

best practices. Commenters stated that it then arbitrarily determines that a "reasonable" estimate 

of heat rate improvement is 4% without justifying why 4% (rather than say 3.8% or 4.2%) is 

"reasonable." 79 Fed. Reg. at 34,859. Commenters stated that EPA makes the arithmetic 

assumption that higher heat rate units can improve their efficiency to more closely resemble 

lower heat rate units. Commenters stated that EPA lists examples of best practices, including 

turning off unneeded pumps at reduced loads, installation of digital control systems, more 

frequent tuning of existing control systems, or earlier like-kind replacement of worn existing 

components but however, in arriving at its projection, EPA did not assess which plants in a state 

can or already have adopted these measures; rather, it has simply analyzed aggregated data from 

which it has drawn an unsupported conclusion. Commenters stated that similarly, with regard to 

equipment upgrades, EPA makes an arbitrary determination that does not naturally stem from the 

data it relies upon. Commenters stated that it cites one study - conducted by Sargent & Lundy 

("S&L") - as its source and then improperly uses the data in the study and it then determined 

that, by adopting all relevant upgrades at a facility, an EGU could achieve a 4% heat rate 

improvement. 79 Fed. Reg. at 34,860. Commenters stated that however, S&L disputes EPA's 

summary of its assessment. Commenters inserted S&L's letter in its entirety to dispute EPA's 

assumptions and stated that EPA's reliance on the S&L study falls far short of the "substantial 

evidence" requirement in Costle. Sierra Club v. Costle, 657 F.2d at 364. Commenters stated that 

rather than assessing which facilities have adopted heat rate improvements to determine an 

accurate estimate, it draws unsubstantiated conclusions based on aggregated data and thus, EPA 

fails to show that including a 6% heat rate reduction, or 4% or 2%, in each state goal is 

"reasonably reliable," "reasonably efficient," "feasible," or will produce the improved 

performance necessary to achieve the goal, as required by the D.C. Circuit.

Commenters stated that potential heat rate improvements are impacted by many variables, many 

of which are beyond the control of unit owners and operators and/or already have been 

implemented by them and/or would provide no meaningful incremental heat rate reduction. 

Commenters stated that in their substantial experience, heat rate of an EGU is not a constant 

value and varies significantly due to numerous factors which can have both positive and negative 

effects. Commenters stated that considerations involve basic unit design, fuel characteristics, 

operating load conditions, age/condition of equipment, maintenance and cleanliness of 

components. Commenters stated that further, coal-based steam generating EGUs are not 

designed with the same heat rate and the diversity of the existing coal-based generating fleet is 

not unlike the diversity of automobiles on the highway. Commenters stated that their existing 

coal fleet is comprised of units of various ages, which were designed by different manufacturers 

to burn different types of coal. Commenters stated that for example, their Laramie River Station 

and Dry Fork Station were designed for and utilize higher energy content coals from the Powder 

River Basin while their Antelope Valley Station and Leland Olds Station were designed for and 

utilize lignite coals from North Dakota. Commenters stated that the Proposed Rule does not take 

into account the wide variety of EGUs in the nation's coal fleet. 
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Commenters stated that EPA also incorrectly applies a single HRI percentage to every EGU and 

that this method does not adequately account for differences in HRI potential due to firing 

different fuels such as subbituminous, bituminous, biomass or other fuels. Commenters stated 

that it also does not account for differences between new and older EGUs, different sizes and 

configurations of units, and the degradation of heat rate due to operation of pollution control 

equipment. Commenters stated that under EPA's approach, an EGU has a more stringent 

emission target simply due to factors which cannot be controlled by the utility. Commenters 

stated that for example, heat rates will be higher (less efficient) when the plant is operating with 

a full complement of pollution control equipment. Commenters stated that in this case, applying 

the 6% value to the net heat rate will result in a larger HRI action than for an EGU that does not 

have pollution control equipment. Commenters stated that the flaws in EPA's analysis and 

resulting potential difference between the 6% HRI assumed by EPA and the real HRI potential as 

applied to Wisconsin is illustrated in comment. 

Commenters stated that they believe that these flaws in EPA's analysis of potential HRI are so 

fundamental that EPA should have sought formal peer review of all the major elements of the 

Agency's analysis prior to proposing this rule. The commenters stated that this includes the S&L 

report (which EPA funded but has never accepted as an official EPA report), the 884 unit hourly 

database used for projecting maintenance-based HRI, the "bin" analysis, and the heat rate 

regression analysis. Commenters stated that moreover, the data quality issues and 

methodological issues raised in the discussion above are so critical to EPA's technical 

conclusions forming the basis of the proposed rule that questions should be raised about the 

Agency's compliance with Clean Air Act (CAA) Section 307(d).

Commenters stated that EPA's assumptions are not achievable for their facility and for example, 

they have already implemented most of the best practices and equipment upgrades identified by 

EPA - a situation that is typical for multiple coal-fired units still operating in Texas and across 

the industry. Commenters stated that Texas's coal-fired fleet cannot on average meet a 6% 

improvement in efficiency. Commenters stated that to the extent that some equipment upgrades 

may be available for specific units, the costs of implementing these upgrades at affected units 

would be cost prohibitive. Commenters stated that additionally, it appears the Building Block 

methodology does not consider the impact of subsequent Building Blocks on the emission rate 

reductions that could be achievable at coal-fired steam EGUs. Commenters stated that they

operate two relatively new, state of the art coal fired units, Spruce Units 1 and 2. Commenters 

stated that Spruce 1 was built in the early 1990s and Spruce 2 began operating in late 2009. 

Commenters stated that the units are already very efficient due to periodic efficiency 

investments, the use of state of the art technology, and best operating practices. Commenters 

stated that it is not feasible for them to achieve 6% efficiency improvements estimated that the 

most improvement they can reasonably achieve is 0.7%, not 6%. Commenters recommended that 

the efficiency improvement for existing coal-fueled power plants should be reduced from 6% to 

1%. 

Commenters disagreed with EPA's application of its methodology. Commenters disagreed with 

EPA's assumption under "Block 1" that existing coal-fired electric generating units can achieve a 

six percent heat rate improvement through the "adoption of best practices" and "equipment 

upgrades." Commenters stated that EPA's analysis is outdated and the vast majority of existing 

units already have implemented best practices and made the equipment upgrades identified by 
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EPA. Commenters stated that at these plants, it is not technologically feasible to achieve a six 

percent heat rate improvement from best practices and equipment upgrades. Commenters stated 

that EPA's assumption especially penalizes units designed to burn lignite coal, like many units 

located in North Dakota because the carbon intensity of lignite is approximately ten percent 

higher than the carbon intensity of other coals, thus, it is significantly more difficult for lignitefired units to achieve heat rate improvements. 

Commenters stated that investments in equipment upgrades (turbine overhauls, economizers, 

etc.) have not and will likely never reach the percentage improvements called for in the proposed 

rule and moreover, the start date of the performance period prevents many investments that have 

already been made from counting toward the state's reduction target.

Commenters stated that EPA assumes a national average heat rate improvement would be 

appropriate to impose upon states and that heat rate improvements are cost-effective at existing 

coal-fired power plants. Commenters stated that EPA's national rather than a state heat rate 

improvement target relied on one study (Sargent & Lundy) which concluded the potential for 

heat rate improvements at existing coal-fired power plants ranges from "less than 5 percent to 

greater than 15 percent." Commenters stated that EPA called for a two percent heat rate 

improvement from equipment upgrades to a four percent heat rate improvement from best 

operating practices without providing a justification for why a six percent reduction is the 

appropriate target for all existing coal-fired power plants within the range of potential heat rate 

reductions at model plants. Commenters stated that EPA also assumed the cost of a six percent 

heat rate improvement will be $100 per kilowatt on average nationally without providing a 

detailed explanation for this estimate and, in addition, EPA failed to take into account the natural 

decrease of heat rate due to aging equipment and the installation of emissions control 

technologies. 

Commenters stated that a major factor in determining whether or not it is cost effective to 

undertake heat rate improvements is the average age of a particular generation fleet. Commenters 

stated that PJM has the oldest weighted average fleet age (41 years) of any RTO/ISO and over 

the course of the past four decades, these plants have been subject to physical modifications and 

repairs and have suffered age-related degradation. Commenters stated that many of the 

modifications have been the addition of emissions controls, which typically have an adverse 

effect on heat rate. Commenters stated that since initial startup, many units have changed fuel 

supply and reduced staffing size in order to remain competitive in wholesale markets, increasing

operational challenges which create additional potential adverse heat rate effects.

Commenters requested that EPA take into consideration in its development of its BB1 proposal: 

(1) the importance of regional and individual generation facility characteristics in estimating 

HRI; (2) ability for generation facilities to support investment in HRI equipment; and (3) the 

impact of regional load factors on HRI. 

Commenters stated that the proposed 6 percent heat rate and alternative 4 percent heat rate 

improvement overestimates the average available heat rate improvements for their facility, and 

while specific data for all units in Colorado cannot be provided, the commenters were aware that 

all other utilities in the state have already completed turbine upgrades at major plants and all 

coal-fired boilers are subject to the Colorado Regional Haze State Implementation Plan. 
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Commenters stated that few heat rate improvements are available in Colorado, while pollution 

controls will degrade heat rate. Commenters stated that EPA should reduce the building block 1 

heat rate improvement to 1 percent or less in Colorado. Commenters stated that alternatively, 

states can have the flexibility to adjust performance goals.

Commenters stated that they are currently installing Flue Gas Desulfurization (scrubbers) on 

three of four coal units to meet the requirements of Colorado's Regional Haze State 

Implementation Plan. Commenters stated that there were no scrubbers in place in the 2012 

baseline year and all scrubbers are expected to be in operation by 2020. Commenters stated that 

the new scrubbers add auxiliary loads which degrade (that is, numerically increase) net heat rate 

approximately 2 percent.

Commenters stated that they contracted for two engineering evaluations to determine the extent 

to which the heat rate lost to the scrubbers could be recovered and the studies examined both 

maintenance and capital improvements available. Commenters stated that Best Achievable heat 

rate may not be physically possible under normal operating conditions such as unit cycling and 

between maintenance events, however, it is useful for comparing to Building Block 1 

assumptions. Commenters stated that the results of these studies are combined with the scrubber 

impact, to show that, considering pollution controls, no improvement is available. Commenters 

provided a table showing best achievable improvement, and the negative impact of scrubbers for 

3 generators.

Commenters stated that several responders to the proposed rule, including TVA and Owensboro 

Municipal Utilities, have responded to specific assumptions and conclusions in the proposed rule 

relating to heat rate improvements, challenging the viability of the assumed improvements that 

can be achieved in building block 1. Commenters stated that while they don't own or operate 

electric generating facilities, it seems logical to them that owners of such units (1) have already 

made improvements to unit efficiency when economically feasible, (2) have determined that 

building block 2's emphasis on natural gas dispatch will render such investments uneconomical, 

and/or (3) will face offsetting heat rate inefficiencies from coal-fired EGUs whose output is 

displaced by gas-fired EGUs. Commenters have also noted that building block l's assumptions 

cannot be projected into the proposed rule without understanding the dynamics and impacts 

involved from the other building blocks. Commenters stated that the block's assumptions are 

interdependent, not independent. 

Commenters stated that notwithstanding their pre-existing commitment to and incentive for high 

efficiency, they have reviewed and considered all potential options for heat rate improvement at 

Lowman as diligently as possible in the short time frame provided since the rule was proposed. 

Commenters stated that their initial analyses of their heat rate improvement opportunities at 

Lowman belie any possibility of attaining and maintaining a 6 percent heat rate improvement at 

any cost. Commenters stated that EPA's assumption that units such as Lowman's Units 1-3 could 

do so is unsupported.

Commenters stated that the use of a single study and applying its general conclusions to every 

coal-fired power plant in the country, irrespective of age, class, type, fuel, maintenance history, 

upgrades or any other relevant factors is, on its face, arbitrary and capricious. Commenters stated 

that it also denies the states the ability to undertake considered rulemaking to evaluate the four 
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factors (cost, non-air quality health and environmental impact, energy requirements, and 

remaining useful life) that Congress intended the states to consider in establishing performance 

standards. Commenters stated that EPA's broad excuse that states can make up for the overstringency of Building Block 1 by expanding the scope of the other three Building Blocks does 

not overcome the lack of basis in using a six percent heat rate improvement in establishing state 

emission rate goals. Commenters stated that EPA could make the same argument with regard to 

its failings to rationally apply each of the Building Blocks; yet if each of the building blocks 

individually is infeasible, and interactions among Building Blocks that make their cumulative 

impacts less than additive are ignored, then EPA has not provided a means for states to comply. 

Commenters stated that even if they had not incorporated advanced pollution control equipment 

at commissioning, they question EPA's efficiency assumptions. Commenters stated that first, 

EPA makes several unfounded assumptions about the coal-fired EGU fleet that fail to account 

for significant variations in geography, fuel diversity, electricity demand, and age and design of 

individual facilities. Commenters stated that these variables affect heat rate and, thus, the 

potential for efficiency gains through best operating practices. Commenters stated that second, 

EPA relies on an outdated, 2009 study by Sargent & Lundy to extrapolate achievable efficiency 

gains through technological upgrades, but that study fails to account for upgrades that specific 

facilities have already made, thus, the report's conclusions of untapped technology-based heat 

rate improvement potential appear to be exaggerated. Commenters stated that third, EPA fails to 

consider Building Block 1 in the context of the other three building blocks because implementing 

the other building blocks directly impacts heat rate by reducing the operating time of coal-fired 

units, that is because less operating time means more cycling which, in turn, increases heat rate. 

Commenters requested that the final BSER for heat rate improvements suggested by EPA (and 

left to the states to determine) be within a guidance range of 0% to 2%. Commenters stated that 

they estimate this revision would add 48 lbs CO2 per MWh to the proposed Michigan standard. 

Commenters stated that potential heat rate improvements must be left to state plan submittals, in 

which identified units provide achievable improvements available on a case by case basis after 

taking into account factors such as retrofits and the expected remaining life of those units. 

Commenters stated that EPA assumed that the 6 percent heat rate improvement at coal-fired 

electric generating units ("EGUs") will directly translate to a 6 percent reduction in the carbon 

emission rate of those EGUs. Commenters stated that applying this assumption to Tennessee's 

coal fleet results in a decrease from the starting 2012 baseline rate of 2,015 lbs/MWh to 1,902 

lbs/MWh, a reduction of 113 lbs/MWh. 

Commenters stated that they have implemented heat rate improvements where economically and 

technically feasible; however, significant projects such as turbine upgrades have not been done 

because of two primary reasons: 1) they have not been economically feasible and 2) the 

possibility of triggering NSR.

Commenters stated that EPA has not taken into account the negative impact to heat rate from 

environmental compliance projects, including this proposed rule. Commenters stated that they 

have installed environmental control equipment for SO2 and NOx (FGD; LNB with SCR and 

SNCR) and these projects raised the plant heat rate by more than 6%. Commenters stated that 

Building block 2 will necessarily cause more coal fired units that were designed and operated as 
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base load units to cycle as more the capacity factor of NGCC units rises. Commenters stated that 

cycling increases heat rate and that they have experienced this as they have been required to 

cycle the units for economic dispatch. Commenters stated that daily cycling of ESGS Unit 1 

increased its heat rate by 5%. Commenters stated that EPA's assumptions on heat rate are 

severely flawed and this proposed building block provides very little real opportunity to carbon 

dioxide reductions and further, EPA apparently lacks an understanding of the relationship of 

heart rate at coal-fired EGUs and capacity factors/cycling due to non-economic dispatch signals 

from the market as are suggested via the use building blocks 2 and 3 in the proposed rule. 

Commenters stated that a base load coal-fired EGU that is forced to cycle due to non-economical 

natural gas fired or renewable energy will reduce the coal-fired EGU's efficiency and increase 

the heat rate. 

Commenters stated that municipal electric utilities that are subject to building block 1, do not 

think it is possible to achieve a 6% heat rate reduction. Commenters stated that the basis upon 

which this mandate would apply to municipal utilities in Iowa is flawed because EPA used 

models that were designed for 600MW plants. Commenters stated that the ability to make a 

significant heat rate reduction decreases with the municipal's smaller plants. Commenters stated 

that in addition, Iowa's municipal electric utility plants have already undergone extensive 

improvements. Commenters stated that if the improvement was cost-effective, it has likely 

already been implemented. Commenters stated that as identified in NERC comments, "sitespecific engineering analyses" would be required to actually determine if there are any remaining 

heat rate improvements to be made on the plant. 

Commenters stated that the 19 minority owners of affected units do not have a say in how the 

units comply with EPA regulations. Commenters stated that if heat rate improvements are 

available at municipal utilities' affected units, the interaction of the various building blocks may 

make the improvements uneconomical. Commenters stated that implementing Building Blocks 2, 

3, and 4 will all have the effect of reducing the run time of affected coal power plants. 

Commenters stated that it will be difficult to justify making heat rate improvements to a unit that 

will run less in the future, and financing the improvements may be challenging. 

Commenters stated that the CPP follows a flawed methodology in determining the magnitude of 

reductions in carbon dioxide emissions achievable from coal-fired EGUs. Commenters stated 

that specifically, EPA has failed to appreciate the immense variety of factors that can cause 

fluctuation in heat rates at a given facility, as well as the numerous types of EGUs at which 

installation of certain equipment upgrades would not be cost-effective or even technically 

feasible. 

Commenters stated that the EPA's proposed rule is arbitrary and capricious in light of their 

unique circumstances, and it constitutes an impermissible expansion of the EPA's authority under 

the Clean Air Act. Commenters stated that as Central has noted in its submission, several of the 

EPA's proposed "building blocks" for meeting carbon dioxide reduction targets are based on 

faulty assumptions with uneven application. Commenters stated that specifically, the proposed 

regulations call for a six percent improvement in heat rate for South Carolina's coal plants which 

fails to account for the relatively young age of the applicable coal fleet in South Carolina, as well 

as their substantial investment in older units to meet other emissions standards. Commenters 
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stated that improvements of this magnitude are not possible, and even if they were, they would 

almost certainly trigger New Source Review for other pollutants. 

Commenters stated that they have a long history of implementing heat rate improvements due to 

the fuel savings that can be realized. Commenters stated that their experience has involved both 

equipment upgrades and O&M practices and as such, they have already made significant 

efficiency improvements to their fleet of coal-fueled EGUs and, contrary to EPA's assumptions, 

based on their substantial technical experience there is very little potential for additional coal unit 

efficiency improvements from either equipment upgrades or O&M practices. Commenters stated 

that they are concerned that the level of heat rate improvement relied upon by EPA in the 

calculation of the goals for the several states in which they operate are vastly overstated, and 

may not be achievable at any cost. Commenters stated that in addition, heat rate and unit 

availability is negatively impacted by increased cycling and low load operations, which are likely 

impacts of the implementation of the other building blocks set forth in the Proposed Rule. 

Commenters stated that EPA must consider these impacts in establishing a much more 

reasonable target for any potential improvement in heat rate. Commenters stated that in these 

comments they explain why EPA's assumptions regarding the potential for heat rate 

improvements are inaccurate for their facilities. Commenters stated that they are not unique, and 

EPA's assumptions likely are invalid for many other EGUs as well. Commenters stated that EPA 

has failed to provide reliable empirical data to support its assumptions. 

Commenters stated that EPA has used primarily two studies to determine potential heat rate 

improvement capability fleet wide. Commenters stated that these studies were from Sargent and 

Lundy (S&L) and National Energy Technology Lab (NETL). Commenters stated that in these 

studies, EPA assumed that all of the heat rate improvements mentioned in the studies were 

applicable on a fleet-wide basis without looking at what improvements had already been made to 

the fleet. Commenters stated that many of the changes suggested by these studies have already 

been made and thus are not available to the fleet. Commenters stated that there was no 

accounting for that in the EPA analysis which should have been performed and in fact, in one of 

the NETL studies, it had further recommended that a fleet-wide study be performed. 

Commenters stated that also heat rate degradation from additional pollution controls required by 

EPA regulations and additional cycling because of a change in market conditions was not 

considered. Commenters stated that a further discussion of these items is contained in an ASME 

presentation on September 25, 2014 (https://www.asme.org/events/asme-energy-forum/powerplant-efficiency). Commenters stated that in summary, EPA chose to look at all the potential, not 

actual, improvements available without accounting for the heat rate degradation from additional 

pollution controls, and unit cycling.

Commenters stated that EPA assumes that coal-fueled plants can achieve a 6 percent heat rate 

improvement by 2020 through a combination of recommended operation and maintenance 

practices (4 percent) and capital investments (2 percent). Commenters stated that the regression 

analysis used by EPA to assume a 4 percent heat rate improvement lacks sufficient technical data 

and fails to account for differences in coal rank, boiler type and boiler age, all of which have 

significant effects on heat rate efficiencies. Commenters stated that an analysis by Energy 

Ventures Analysis (EVA) using an algorithm that incorporates the factors EPA omits shows no 

incremental heat rate improvements were possible from additional practices. Commenters stated 
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that the 2 percent improvement from capital investments rests upon a single 2009 study. 

Commenters stated that however, EPA's reliance upon that study is misplaced - the study did not 

conclude that all coal plants can improve heat rates-let alone by 2 percent from 2008. 

Commenters stated that at the same time, EPA's MATS rule issued two years ago requires 

extensive retrofits of existing plants that will make them less efficient by increasing their 

parasitic load. Commenters stated that moreover, the present proposal will force many coal 

plants to run at reduced and sub-optimal levels which in turn will also make them less efficient. 

Commenters stated that it is not aware of any work EPA performed to 1) validate their statistical 

approach and variability of the data set, 2) validate the assumption that 30% of the heat rate 

variability is due to operation and maintenance practices, or 3) evaluate that such practices, are 

cost effective - both in a competitive and regulated market structure. Commenters stated that the 

proposed rule's use of a 4% HRI for maintenance and operating practices is significantly 

overstated which results in a BSER that is unachievable.

Commenters stated that at the heart of Building Block 1 is the assumption that coal steam turbine 

heat rates may be improved by 65%, however, many coal-fired plants have already undergone 

significant efficiency upgrades and improvements, which in large part contributed to the 13.2% 

reductions in CO2 emissions achieved since 2005. Commenters stated that they have invested 

millions of dollars in maintaining its fossil fueled EGUs to comply with environmental 

regulations and increase their energy efficiency. Commenters stated that while it may be possible 

to make some further improvement in the heat rates of existing coal-fired plants, the marginal 

costs are likely to be burdensome. Commenters stated that under Building Block 2 of the 

Proposal, NGCC will replace much of the output from coal plants, reducing revenues and placing 

expensive environmental upgrades out of reach. Commenters proposed that the coal plant 

efficiency target of 6% be reduced to a more achievable target. 

Commenters stated that under the Proposed Rule, EPA first assumes that all coal-fired steam 

EGUs can achieve a 6% heat rate improvement. Commenters stated that to support this assertion, 

EPA claims that affected coal-fired steam EGUs can obtain an average 4% heat rate 

improvement by adopting operating "best practices," and an additional 2% improvement, on 

average, through equipment upgrades. Commenters stated that these assumptions are unrealistic 

and unachievable for most EGUs. Commenters stated that for example, Santee Cooper has 

already implemented most of the best practices and equipment upgrades identified by EPA's 

situation [sic] that is typical for most of the industry and furthermore, to the extent that some 

equipment upgrades may be available, the costs of implementing these upgrades at affected units 

would generally be prohibitive. Commenters stated that additionally, EPA's approach fails to 

consider the impact of subsequent building blocks on the emission rate reductions that could be 

achievable at coal-fired steam EGUs. 

Commenters stated that to the extent that there are potential heat rate improvements, EPA must 

also take into account the significant barriers to implementing these potential changes such as the 

most significant ones - New Source Review litigation liability; and the uncertain future of certain 

plants, given the long return-on-investment time that is typical of these projects. Commenters 

stated that while it is difficult to quantify the impact of these barriers in the abstract, these factors 

will certainly reduce the true potential for heat rate improvements at individual units. 
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Commenters stated that questions have been raised regarding the validity of certain of EPA's 

assumptions that underpin its four Building Blocks, which are used for establishing state-by-state 

emissions targets. Commenters stated that for example, the Electric Power Research Institute 

(EPRI) has raised significant issues with respect to the Building Blocks proposed by EPA. 

Commenters stated that specifically, EPRI observes that coal generation heat rate improvement 

estimates should, but do not, take into account EPA environmental control regulations.

Commenters stated that compliance with other EPA regulations paradoxically can have the effect 

of reducing coal unit efficiency, thus increasing CO2 emissions. Commenters stated that EPRI 

also recommends that heat rate improvements be analyzed on a state or regional basis, not a 

national average, because the increasing use of renewables and natural gas under the rule may 

actually increase heat rates at coal units because these units will be run at less than optimal 

efficiency. Commenters stated that NERC also questions whether heat rate improvements at the 

level projected by EPA are achievable, noting that "many plant efficiencies have already been 

realized and economic heat rate improvements have been achieved." Commenters stated that 

NERC has concluded that the assumed heat rate improvements across the entire coal fleet are 

"unlikely."

Commenters stated that in summary, Building Block 1 should be reduced from 6% to 1% 

efficiency increase for coal units, since most efficiency gains have already been implemented, as 

well as provide relief from triggering New Source Review for efficiency programs that might be 

implemented after the rule is finalized. 

Commenters asked for clarification on how the plan would credit states like Pennsylvania for the 

good work already done and for the efficiencies that they are talking about. Commenters there 

are significant concerns about the grid reliability and what will offset the coal plants that have 

been providing power, specifically in the cold winters. Commenters stated that over 95 percent 

of the coal plants were in usage during the polar vortex. Commenters stated that a lot of those 

won't be around in 2016 under current regulations, not even the proposed regulations. 

Commenters asked if EPA has numbers that can speak to the grid reliability and the pricing 

associated with that. 

Commenters referred to EPA's approach to six percent net heat rate reduction via operating and 

maintenance "best practices" and "equipment upgrades." Commenters stated that EPA's analyses 

that underlie the six percent reduction are derived from a series of missteps. Commenters stated 

that first, EPA ignores current industry practice, which it well knows from its NSR enforcement 

program and as a result, EPA invents an arbitrary level of operational improvement that it 

concludes coal-fired EGUs can achieve without explanation. Commenters stated that second, the 

Agency ignores the impossibility of sustaining individual, component-based efficiency 

improvements and completely misuses a 2009 Sargent & Lundy report ("S&L Report"). 

Commenters stated that finally, EPA fails to account for the number of factors that 

counterbalance and negatively impact heat rate at a given unit that make achieving and 

sustaining a six percent improvement simply impossible. 

Commenters stated that heat rate of an EGU is not a constant value and varies significantly due 

to numerous factors which can have both positive and negative effects and variability comes 

from basic unit design, fuel characteristics, operating load conditions, age/condition of 

equipment, maintenance and cleanliness of components.
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Commenters stated that EPA's unrealistic 6% heat rate improvement sought under Building 

Block 1 is based on a faulty analysis that fails to look at the complete picture. Commenters stated 

that EPA's analysis does not adjust for the following factors that have a significant impact on 

efficiency: "(1) subcritical versus supercritical boiler designs; (2) fluidized bed combustion, 

integrated gasification combined-cycle (IGCC), and pulverized coal; (3) unit size and age; and 

(4) coal quality variations in moisture and ash." 

Commenters stated that the EEI commentary on O&M improvements as a means to reduce heat 

rate by four percent recognizes that the EPA cited nine factors that can impact unit efficiency at a 

given site. Commenters stated that EEI also acknowledges that an attempt was made to account 

for some of these factors that may influence heat rate variability, namely load factor and ambient 

temperature but that some of the other factors may have a larger impact at any given site, and as 

EEI points out, the "EPA's only attempt to recognize and control for the range of factors that 

might affect heat rate variability is to assume that 30 percent (instead of 50 percent) of the 

variability observed in bin data is caused by O&M practices. Commenters stated that no analysis 

supports this assumption and assigning the cause of 30 percent of the variability to O&M 

practices is arbitrary."

Commenters stated three of the nine factors that the EPA cites as factors impacting heat rate are 

significant in the operation of their coal fired generating fleet:

• EGU coal rank and quality

• EGU pollution control systems

• EGU load generation flexibility requirements.

• Commenters stated that additionally, many of the other factors do impact unit 

efficiency and would not be totally addressed by improved O&M practices. 

Commenters stated that the statistical approach used by EPA does not consider any technical 

aspects of the facility, or if any characteristics changed over the eleven year period of time, such 

as if a facility was operating in a cycling mode, had retrofit low NOx burners, SCRs, scrubbers, 

new burner and furnace management systems etc., or if the facility changed coals over this 

period, or any characteristics of the fuel for that matter. 

Commenters stated that EPA's statistical analysis fails to account for other important factors. 

Commenters stated that the issue with EPA's analysis is that it presumes that ambient 

temperature and load are the only factors beyond the operator's control that impact heat rate and 

that the analysis does not consider unit design, changes in cooling water temperature, or fuel 

heating value and moisture content, coal ash composition changes, extreme weather conditions, 

rate of load change, equipment changes over the period and/or wear, etc.

Commenters stated that according to the EPA's statistical analysis, ambient temperature and 

capacity factor only explain approximately 25% of the variation in heat rate - leaving about three 

quarters of the variation unexplained. Commenters stated that the unexplained variation, EPA 
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apparently assumes, is due to a failure to use "best practices" rather than other, unaccounted for 

factors that are beyond the operator's control. Commenters stated that their concern is that 

because EPA did not consider enough of the factors beyond the operator's control that impact 

heat rate, the approach used by EPA mistakenly considers the unexplained variation in their twofactor analysis as an opportunity for improvement in heat rate rather than the effects of other 

important factors that were not considered.

Commenters stated that EPA's approach does not properly address the effects of capacity factor 

and that EPA's approach regards average load over an hour as capacity factor, when industry 

actually averages capacity factor over longer periods of time. Commenters stated that the 

approach used by EPA would consider an hour with load that is steady at 70% as equivalent to 

an hour where load changes from 40% to 100%, when in fact the boiler will behave very 

differently in these two situations.

Commenters asked - on pp. 2-23 to 2-24 of the GHG TSD - why Fig 2-3 uses 2012 monthly 

capacity factor, but then compares it with the 30 year climate normal and not the 2012 data. The 

commenters also stated that EPA does not explain why a twenty-two mile average distance (p. 2-

19) is considered a good approximation to determine the temperature at an EGU, and questioned 

the methodology EPA used to make this determination.

Commenters stated that EPA failed to account for fuel quality, which can significantly impact a 

coal-fired unit's heat rate via its moisture, ash, heating value, sulfur and iron content by 

increasing the heat rate, ranging from one to four percent depending on the available coal, 

potentially offsetting any perceived gains from implementing best practices. 

Commenters stated that they believe that U.S. EPA failed to account for other variables in both 

the available database and the subsequent analysis that further call into question the results of 

U.S. EPA's analysis. Commenters stated that examination of the dataset reveals errors that 

should have been filtered out prior to the analysis, including gross efficiencies at or near 42%, 

which they understand is not physically possible for even the most efficient coal-fired boilers. 

Commenters stated that U.S. EPA binned the data based on a 10% capacity factor band. 

Commenters stated that while such an approach does serve to eliminate some variability, the 

10% band in capacity factor can represent up to a 4% difference in heat rate. Commenters stated 

that to their knowledge, U.S. EPA did not attempt to filter or eliminate data during periods in 

which controls were being installed, periods when fuel switching had occurred, and periods of 

testing, for example, new environmental controls. Commenters stated that these variables can 

significantly and temporarily degrade the heat rate of a particular unit well outside of its normal 

operating conditions. 

Commenters stated that EPA's assumption regarding coal units being able to achieve heat rate 

improvements of 6% (or in the alternative 4%) is inaccurate, unreasonable, and lacks record 

support. Commenters stated that there are clear errors in EPA's analysis that prove that a 4% to 

6% heat rate improvement is impossible to achieve. Commenters stated that EPA concludes that 

4% of heat rate improvement can be achieved through best practices and an additional 2% can be 

achieved by equipment upgrades. But that however, there is no way to guarantee or even support 

that these types of improvements can be achieved at every, or even most, units. Commenters 

stated that EPA's fundamental basis outlined in its GHG Abatement Measures Technical Support 
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Document ("TSD") for assuming that heat rate improvements can be attained is based on its 

observations that there are differences "in operating efficiency of EGUs with similar design 

characteristics and [that] the year-to-year variability in individual EGU efficiency indicates that 

there is potential for broadly applicable efficiency improvements through cost effective 

operational and maintenance practices." Commenters stated that this is a far too simplistic view 

of differences in heat rates at EGUs and an unsupported assumption that this is evidence of the 

ability to achieve heat rate improvements and further, it is almost immediately contradicted in 

the same TSD, where EPA outlines the various reasons why heat rates may vary between units. 

Commenters stated that these reasons include, but are not limited to: coal rank and quality, 

operating practices, installed pollution control systems, cooling systems, geographic location and 

ambient conditions, load generation flexibility requirements, and plant components.

Commenters stated that EPA's data and conclusions do not match. Commenters stated that EPA 

makes several unfounded assumptions about the coal-fired EGU fleet that fail to account for 

significant variations in geography, fuel diversity, electricity demand, age, and design of 

individual facilities and these variables affect heat rate and, thus, the potential for efficiency 

gains through best operating practices. 

Commenters stated that EPA's unrealistic six percent heat rate improvement sought under 

Building Block 1 is based on an incomplete analysis that fails to look at the complete picture and 

EPA's analysis does not adjust for the following factors that have a significant impact on 

efficiency: "(1) subcritical versus supercritical boiler designs; (2) fluidized bed combustion, 

integrated gasification combined-cycle (IGCC), and pulverized coal; (3) unit size and age; and 

(4) coal quality variations in moisture and ash."

Commenters stated that on a more fundamental level, EPA's analysis incorrectly assumes that the 

existence of variation in heat rate at individual units mean there is "significant variation in the 

operation of EGUs," indicating that "significant potential for heat rate improvement is available 

through the application of best practices." Commenters stated that in fact, heat rate variability at 

individual units is driven by the design, duty cycle, fuel type, size, cooling conditions, and 

location of each unit, and it cannot be ameliorated by changes in operating practices. 

Commenters further stated that EPA did not assess differences in variability based on these 

factors or control for these factors in its achievability analysis.

Commenters stated that the USEPA applied "best practices" for improvements and "further 

equipment upgrades." Commenters stated that the statistical approach taken for "improvements" 

is somewhat puzzling given that the USEPA reduced variability in heat rates "because the 

deviations generally result in performance worse than optimal heat rates." Commenters stated 

that statistically, variability is a change relative to an average value, but in this case, the USEPA 

made it relative to an "optimal" (minimal) value, thereby, skewing the results to a higher 

percentage value reduction. 

Commenters stated that EPA has no basis for assuming implementing its best practices would 

eliminate the heat rate variability among coal-fired power plants and that there are innate 

differences between power plants that affect the efficiency of boilers, the heat and the 

performance of the plant as a whole. Commenters stated that best practices cannot make boilers 

perform beyond their capabilities. 
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Commenters stated that EPA's assumed levels of sustainable heat rate improvement fail to 

consider critical issues related to unit design, load, cycling, and degradation. 

Commenters stated that in its assumption, EPA has failed to recognize the causes of variability in 

heat rate efficiency that are outside the control of the individual unit, such as:

• Variability in coal quality, such as heat content (BTUs) and moisture

• Variability in pollution control efficiency and electricity demand 

• Variability in other ambient and weather conditions such as humidity and rainfall

• Variability attributable to unavoidable cycles in degradation of components 

designed to wear out over time

• Variability attributable to changes in heat rate calculation methods

Commenters stated that EPA also fails to acknowledge that running coal generation units at a 

lower capacity to reduce carbon intensity will actually increase heat rate, as coal burns more 

efficiently at high capacity. Commenters stated that these are among numerous factors that make 

a 6% heat rate improvement infeasible.

Commenters stated the potential for negative factors to degrade heat rate and these factors 

include the addition of pollution control equipment, with auxiliary load requirements and future 

operation at lower load factors. Commenters reminded that building block 2 is based on 

operating coal-fired generators at lower load factors. Commenters stated that many of the 

measures that EPA identifies for HRI are routinely employed by existing units, and the 

variability observed in heat rate data may reflect the fact that the measure was applied in the past 

and cannot be "counted twice." Commenters also stated that actual fuel carbon content 

(lb/MMBtu) causes variability, including impacts of PRB blending. Commenters stated that it

appears that CO2-lb/MMBtu varies by both rank and geographic region: Central Appalachian 

bituminous coal: 206-209; Northern Appalachian bituminous coal: 199-203; Powder River Basin 

subbituminous coal: 210-212. Commenters stated that this variability between coals implies that 

the real variability in estimated emissions (which were used to estimate heat rate) relative to the 

reported values could be as much as 6 percent. 

Commenters stated that EPA's analysis incorrectly assumes that the existence of variation in heat 

rate at individual units mean there is "significant variation in the operation of EGUs" indicating 

that significant potential for heat rate improvement is available through the application of best 

practices. Commenters stated that in fact, heat rate variability at individual units is driven by the 

design, duty cycle, fuel type, size, and location of each unit, and it cannot be ameliorated by 

changes in operating practices. Commenters stated that EPA did not assess differences in 

variability based on these factors or control for these factors in its achievability analysis. 

Commenters stated that in essence, EPA has failed to prepare the necessary background 

information for the Proposal, and has failed to demonstrate that its proposed Building Block 1 

target of 4 - 6% improvement in heat rate for coal-fired EGUs is achievable "under the range of 

relevant conditions which may affect the emissions to be regulated.
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Commenters stated that EPA's variability analysis is flawed because it only accounts for two of 

the many uncontrollable sources of heat rate variability, specifically, PNM is concerned that 

EPA's analysis fails to take into account the many other factors that may actually reduce 

efficiency at the same time by as much or more than the efficiency improvement that EPA 

expects units to achieve using the best practices and equipment upgrades that EPA recommends. 

Commenters stated that such offsetting factors include unavoidable variability that EPA has 

failed to consider (such as coal quality), the addition of new pollution control equipment to 

comply with other EPA regulations, the natural and unavoidable deterioration of a unit's 

performance levels over time, and the other aspects of EPA's proposed rule that will reduce the 

capacity factors of coal-fired units and increased cycling operations, which typically reduce 

efficiency levels. Commenters stated that EPA also fails to recognize that any new upgraded, 

more efficient equipment will also degrade over time, and therefore will not maintain peak 

efficiency improvement levels on a long-term basis. 

Commenters stated that they conducted an analysis of heat rates across their coal-fired fleet for 

years 1997-2013. Commenters stated that to enable a direct comparison of heat rate values put 

forth by U.S. EPA, they considered gross generation and heat input from the Clean Air Markets 

Database. Commenters noted that they disagree with the blanket application of HRI targets based 

on gross generation, with no consideration for environmental controls. Commenters stated that 

this evaluation was done for purely demonstrative reasons. Commenters stated that firstly, 

examination of Ohio's coal fleet reveals that annual heat rates across the fleet are highly variable. 

Commenters stated that given the number of variables which may influence heat rates, among 

them load, short and long term demand, fuel prices, and others, it is difficult to pinpoint which 

variables contribute most significantly to this variability. Commenters stated that what is 

apparent is that heat rates improved markedly from 1997 to 2012 and the most significant 

improvements are seen in the early years of deregulation in Ohio, between 1999 and 2002. 

Commenters stated that heat rates during this time improved 4.4%, from 10,104 BTU/kW-h to 

9,661 BTU/kW-h. Commenters stated that secondly, year-to-year variation in heat rates range 

from less than 1 BTU/kW-h to 630 BTU/kW-h. Commenters stated that this clearly indicates to 

them that heat rates are strongly influenced by a great number of variables and should not be 

considered a fixed value. Commenters stated that they strongly encourage U.S. EPA to 

reevaluate this variability, examine potential HRIs in light of past improvements, and consider 

the differences in heat rates and profit motives between regulated and deregulated power 

markets.

Commenters said, with respect to building block 1, EPA’s determination that an average heat 

rate improvement at existing coal facilities and assumed that all states can achieve that goal is 

incorrect because not all coal-fired generation is of equal vintage or efficiency. Commenters said 

the EPA assumption that an average degree of improvement is possible is unsupported. 

Commenters said a newer coal power plant or a plant that has made improvements will not have 

much opportunity to improve efficiency

Comment 2: Comments regarding the transparency of EPA's analysis under building block 1.
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Response 2: See section V.C. of the final rule preamble of the CPP and Chapter 2 of the GHG 

Mitigation Measures TSD supporting the final CPP for EPA’s response to this comment. Those 

documents thoroughly describe the EPA’s heat rate improvement assessment under building 

block 1, just as EPA thoroughly explained its proposed approach for building block 1 at 

proposal. In addition, the final rule of the CPP specifies monitoring, reporting, and 

recordkeeping requirements. 

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

Commenters asked why, regarding topic 2.3 on pp. 2-5 to 2-10 of the GHG TSD, the EPA did 

not provide: citations, methodologies for the estimates, degradation estimates, or an analysis of 

what combinations are possible.

Commenters asked U.S. EPA to clarify which method(s) states are to use to quantify and 

document the reduction in heat rates. Commenters stated that if U.S. EPA is expecting that states 

use CEMs to monitor BtU/KWh, this expectation should be clearly stated within the rule. 

Commenters asked what peer-review the WEPCO two-phase efficiency program study went 

through. 

Commenters stated that Building Block 1 would require a significant improvement in the 

efficiency of coal-fired electric generating units by requiring those units, on average, to reduce 

their heat rate by 6%. Commenters stated that EPA concluded that a 6% improvement was 

possible by identifying two categories of actions that EPA claims utilities can use to costeffectively improve the efficiency of their generating units, namely (i) operating and 

maintenance ("O&M") "best practices" and (ii) capital projects.

Commenters stated that although they recognize that the activities EPA identified can have some 

beneficial impact on the heat rate for coal-fired units, EPA's analysis contains many unsupported 

assumptions and many holes. Commenters stated that for example, EPA either failed to provide 

or failed to document any analysis it performed on the coal-fueled EGUs in Montana and as a 

result, there is no reliable basis to conclude that such a heat rate improvement is attainable in 

Montana. 

Comment 3: Several commenters asserted that EPA’s proposed 6% heat rate improvement

is not feasible, achievable, sustainable, and/or adequately demonstrated.

Response 3: See section V.C. of the final rule preamble of the CPP and Chapter 2 of the GHG 

Mitigation Measures TSD supporting the final CPP for EPA’s response to this comment. As 

described in these documents, the EPA’s assessment of average potential heat rate improvement 

is based on an analysis of historical performance—i.e., what actual existing coal-fired EGUs 

have previously achieved—and has been lowered since the proposal. This backward-looking 

assessment provides a conservative estimate of the potential heat rate improvement (and 

accompanying reductions in CO2 emission rates) that affected EGUs can achieve on an average 

basis, as described in section V.C of the preamble and Chapter 2 of the GHG Mitigation 

Measures TSD. The precise amount of heat rate improvement feasible at individual EGUs will 
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vary. The final CPP provides states the flexibility to develop plans with emission standards that 

more precisely take into account the potential heat rate improvement of individual EGUs—

should states desire to consider potential heat rate improvement at all. Furthermore, if an affected 

EGU cannot meet the particular emission standard solely because it has below-average potential 

to reduce emissions through heat rate improvements, then in instances where the EGU’s state 

plan allows emissions trading, the EGU can acquire credits or allowances from affected EGUs 

that have above-average potential. Additionally, with respect to Texas, the final rule calculates 

heat rate improvement on an interconnection basis and thus further obviates commenters’ 

concerns about direct comparisons between EGUs in ERCOT and those in other 

interconnections. 

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

Commenters supported the use of heat rate efficiency improvement projects at existing coal-fired 

EGUs (Subpart Da units) as a means of reducing the carbon emission rate. Commenters stated 

that heat rate efficiency improvement projects will achieve lower carbon emission rates and may 

be cost justified; in fact, such actions are business as usual for electric utilities, as utilities have 

been implementing efficiency improvement actions for decades. Commenters stated that as a 

legal matter, building block 1 is the only legal method pursuant to Section 111(d) for reducing 

carbon emissions at existing Subpart Da units, however, the performance standard must be 

achievable at all units based on measures that can be integrated into the design and operation of 

the source. Commenters stated that contrary to EPA's assertion, based on their professional 

judgment, which is supported by years of engineering and operational experience with Subpart 

Da units and corroborated by current research, a six percent efficiency improvement for all 

Subpart Da units is simply unachievable. Commenters stated that therefore, they do not support 

the required six percent heat rate improvement on Subpart Da EGUs as proposed by EPA.

Commenters stated that EPA relies on a combination of best operating practices (four percent) 

plus equipment upgrades (two percent) to collectively establish the six percent efficiency 

improvement target for each affected Subpart Da EGU. Commenters stated that the carbon 

emission rate reduction associated with the efficiency improvements at each Subpart Da EGU 

was then carried forward and used to set the interim and final carbon emission rate goals. 

Commenters stated that the six percent improvement proposed by EPA is unfounded and states 

cannot reliably count on this magnitude of efficiency improvement on every Subpart Da source 

to comply with the state goals.

Commenters summarized that, considering EPA's misuse of the 2009 Sargent & Lundy (S&L)

Report, the commenters’ S&L Report correcting EPA's flawed interpretation of this earlier S&L 

report, EPA's flawed matrix study as identified in the UARG critique, and the commenters’ Nine 

Unit Study, EPA has presented no valid study or data to justify any HRI goal for coal-fired 

EGUs. Commenters stated that the studies or study methods on which EPA relies to support the 

HRI proposals are either misused or rely on flawed assumptions or faulty analysis. Commenters 

stated that accordingly, EPA must withdraw the HRI requirements for Building Block 1 because 

they are not supported by the record.

Commenters described that EPA is proposing to find that overall heat rate improvements of 6 

percent (or 4 percent under the alternate goals EPA solicits comment on) are achievable at 
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existing coal-fired EGUs under building block 1. Commenters stated that the Agency based its 

estimates of achievable heat rate improvements primarily on measures described in a 2009 report 

by Sargent & Lundy, along with its own limited analysis of historical generating data. 

Commenters then continued to state that EPA's estimates are arbitrary and capricious, and they 

demonstrate the Agency's poor understanding of the nature, cost, and availability of heat rate 

improvement measures. Commenters stated that EPA has failed to consider several critical 

factors that will make it impossible for affected EGUs to reach this goal individually or on 

average across any state.

Commenters also stated that EPA has failed to satisfy its obligation to demonstrate that its 

proposed Building Block 1 target of 4 to 6 percent improvement in heat rate for coal-fired EGUs 

statewide is achievable "under the range of relevant conditions which may affect the emissions to 

be regulated." Commenters stated that therefore, EPA should assess what efficiency upgrades 

have already been implemented by affected coal-fired EGUs in order to determine what level of 

additional heat rate improvements is achievable. Commenters stated that it should also assess 

other factors that will determine what level of heat rate improvements is achievable for 

individual coal-fired EGUs across the source category as a whole, such as whether the upgrades 

are compatible with the design and hardware present at a unit and whether the upgrades may 

present operational reliability issues at a particular unit. 

Commenters stated that because EPA failed to consider the effect of looming or recently 

completed emission control projects that adversely affect EGU heat rate, affected EGUs will be 

forced to overcome the energy penalties associated with these controls and then achieve an 

additional 4 to 6 percent improvement in heat rate, on average, in order to comply with the 

Proposed Rule. Commenters further stated that in addition to these fundamental oversights, the 

Agency has failed to provide any reasonable analysis of whether its heat rate improvement 

targets are achievable and that for these reasons, the "assessment of heat rate improvement 

potential" in the GHG Abatement Measures TSD does not support EPA's claim that state-wide 

heat rate improvements of 4 to 6 percent are achievable.

Commenters referred to the first example included in EPA's TSD on pages 2-32 and 2-33, where 

EPA's Region 7 reported that seven coal units performed equipment modifications such as 

turbine and condenser upgrades, variable frequency drives. Commenters stated that Region 7 

reported that together all of these modifications achieved a 0.25 to 3.5% improvement in heat 

rate and another utility (WEPCO) reported improvement of 2.3 to 4.1% due to equipment 

upgrades and only a 0.5% per year improvement using best practices. Commenters stated that in 

summary, the example indicates that well thought out modifications to unit design and operation 

only resulted in a maximum improvement of approximately 4% in heat rate and that having 

performed these improvements these seven units would have difficulty in further improving their 

heat rate to the stated 6% goal. 

Commenters stated that EPA's assessment of national capabilities does not appear to be 

sufficiently rigorous or granular to conclude that such a reduction is indeed attainable and EPA 

fails to provide data to support the case that all coal plants in the country are capable of this level 

of improvement. Commenters stated that further, it is reasonable to conclude that fossil plant 

efficiency will actually decrease under the CPP due to EPA's planned changes in dispatch that 

will result in increased cycling of coal units not designed for this kind of load following. 
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Commenters concluded, based on unit specific plant analysis as well as based on an historic 

understanding of the impacts of plant efficiency at lower dispatch rates, that the 6% efficiency 

improvement is not ''technically feasible" and therefore cannot be a component of the final Rule. 

Commenters stated that they commissioned a study, also conducted by S&L, relative to potential 

heat rate improvement opportunities at its North Valmy Generating Station, but the S&L analysis 

indicates that a 6% heat rate improvement is not achievable and a more modest 1-2% 

improvement may be achieved at a potentially significant cost. Commenters stated that therefore, 

they believe that EPA should revisit the assumptions which underlie the Building Block 1 targets 

and revise them to a more realistic range. 

Commenters expressed concerns with meeting Kentucky's State-Specific Goal. Commenters 

stated that the building blocks that comprise the Best System of Emission Reduction (BSER) 

have technological and/or legal vulnerabilities, and therefore, the Cabinet contends that a state's 

target should be adjusted commensurate with the elimination of the percentage contribution to 

the target should a court invalidate one or more of the building blocks. Commenters stated that 

one of the most serious technological limitations is EPA's use of a six percent heat rate 

improvement for Electric Generating Units (EGUs). Commenters stated that the utility 

stakeholders met with in Kentucky were unanimous on this issue - the six percent heat rate is not 

practicable and must be adjusted, with a commensurate adjustment in the state's emissions rate. 

Commenters stated that improving the existing U.S. coal fleet's average heat rate by 6 percent 

may be difficult to achieve. Commenters stated that possible options and considerations for 

attaining a portion of this target may include the following: Site-specific engineering analyses 

are required to determine if there are remaining opportunities for heat rate improvement 

measures through implementation of operational best practices or capital investments. 

Commenters stated that if the U.S. coal fleet does not achieve target heat rates, more CO2 

reductions would be required from other CPP Building Block measures. Commenters stated this 

can result in some coal-fired power plants retiring earlier than anticipated, which creates 

additional uncertainty in future generation resources.

Commenters stated that EPA determined the fleet-wide potential for the two types of HRI using 

fundamentally different analyses and that both of these approaches are flawed, resulting in overly 

optimistic projections for fleet-wide HRI that may result in state emission rate targets that are 

unachievable. Commenters stated that EPA also overestimated the value of fuel costs savings to 

an affected EGU and that EPA should revise the analyses used to determine the potential fleetwide HRI that could result from both O&M "best practices" and equipment upgrades. 

Commenters stated that they do not agree that a 6% average heat rate improvement is feasible for 

all coal units. Commenters stated that many utilities have already retired their least efficient 

units and upgraded turbines and other equipment on remaining units because this makes 

economic sense. Commenters stated that EPA's asserted basis for its 6% number does not 

account for this. Commenters stated that States should be allowed to set efficiency improvement 

targets based on unit specific factors and costs including remaining useful life, previouslyupgraded equipment, added environmental controls, and other factors. Commenters stated that 

those other factors should include the adverse impacts that result from other building block 
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activities that States may choose. Commenters stated that the emission guidelines should be 

adjustable based on the states' analysis of achievability of Building Block 1. 

Commenters stated that coal-fired power plants cannot achieve a six percent heat rate 

improvement. Commenters stated that the studies on which EPA relies to assert that a six percent 

heat rate improvement is achievable are not representative and that the analyses are flawed. 

Commenters stated that even assuming a heat rate improvement at coal power plants is possible, 

many coal power plants have already upgraded their plants and adopted best practices and further 

investments would be uneconomical. Commenters further stated that coal power plants would 

not be able to maintain the six percent heat rate improvement throughout the performance period 

because of the installation of parasitic controls, lower utilization of coal power plants, and 

natural degradation.

Commenters stated that at their August 15 joint workshop, SWEPCO detailed numerous flaws in 

EPA's analysis that "lead to a gross over-estimation of the potential heat rate improvements that 

could be reasonably and cost-effectively achieved by the fleet of coal-fired power plants that will 

be impacted by." Commenters concurred with these assessments, namely that EPA(1) ignored 

certain of the caveats and conclusions included in the engineering reports, and the impact on heat 

rate of the emission control projects currently under construction to comply with other rules; (2) 

inappropriately assumed that heat rate variability that is not associated with unit load or ambient 

temperatures can be controlled through operational practices or capital improvements; (3) 

conducted a statistical analysis that (a) includes a number of units that will be retired prior to the 

initial interim compliance date, (b) uses gross heat rate data and inappropriately applies the 

results to a net heat rate goal, and (c) ignores additional sources of variability that are not 

controllable; (4) erroneously assumed that capital projects and operational practices could be 

universally applied to improve the efficiency of all coal-fired generating units; and (5) failed to 

collect any industry data on the extent to which such improvements have already been 

implemented and therefore are reflected in current plant efficiency values

Commenters stated that as a boiler and air quality control system supplier, they have participated 

in numerous plant retrofits and upgrades that have resulted in plant efficiency improvements and 

heat rate reductions for their customers. Commenters stated that they understand very well the 

potential for plant heat rate improvements and are of the opinion that the opportunity for a 6% 

heat rate improvement across the fleet of existing plants is far overstated. Commenters stated that 

while utility companies are in the best position to evaluate the potential for retrofits of the 

operating fleet of coal fired boilers, given their experience in retrofitting power plants over the 

last 30 years they would project that less than 50% of the existing fleet would be capable of heat 

rate improvements of 3% or more with the remainder of the fleet having little or no opportunity 

for improvements of any significant nature.

Commenters stated that, as explained in the memorandum prepared by RMB Consulting & 

Research, EPA's 6% heat rate improvement required under Building Block 1 is based on a 

flawed and superficial analysis. Commenters stated that given the lack of heat rate improvement 

projects available, EPRI estimates that there may be opportunities to achieve heat rate 

improvements in the range of 0.5%-5%; however this would not rise to the 6% average heat rate 

improvement sought by EPA in Building Block 1. Commenters stated that Indiana Utilities 
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Regulatory Commission opines that facilities in Indiana can only obtain heat rates improvements 

of 1-3%, far short of the 6% proposed by EPA

Commenters stated that 6 percent heat rate improvement is not achievable because a vast 

majority of coal-fired EGU operators, including their facility, have already captured most, if not 

all, the cost-effective heat rate efficiency in their units since this just makes good business sense.

Commenters stated that EPA's proposed six percent heat rate improvement is simply not feasible, 

sustainable, or adequately demonstrated, and that EPA ignores industry practice and factors that 

negatively affect heat rate, misinterprets an expert report on the subject, and performs a 

completely arbitrary "best practices" analysis to arrive at an unachievable efficiency 

improvement percentage that they apply to all affected coal units across the nation.

Commenters stated that they are concerned the analysis EPA used for Building Block #1 may 

overstate the potential reductions and for many coal-fired power plants, improvements have 

already been completed which makes 6 percent fleet wide heat rate improvement an ambitious 

goal. Commenters suggested that EPA further study the value allocated to set this goal and 

consider a revised Block #1 goal. 

Commenters stated that they have explored the achievability of a 6% heat rate improvement and 

has determined that a more realistic target for heat rate improvements is 1 to 1.5%. Commenters 

stated that coal-fired power plants were initially built to achieve unit-specific heat rates. 

Commenters stated that it is in the best interest of any utility to operate coal-fired units as 

efficiently as possible to obtain the greatest amount of product (electricity) for the smallest costs. 

Commenters stated that EPA's statement in the GHG Abatement Measures technical document 

that "coal-fired units are designed to operate most efficiently at full capacity" is accurate and is 

the reason that utilities strive to optimize unit performance themselves by improving heat rate. 

Commenters stated that substantial improvements (flue gas desulfurization, selective catalytic 

reduction, etc.) have already been made to the older coal-fired units to reduce emissions and 

those units that are deemed inefficient have been shut down or future plans to decommission are 

already in the works. Commenters stated that heat rate improvements are also very specific to the 

individual unit. Commenters stated that it has explored the achievability of a 6% heat rate 

improvement and has determined that this percentage is not a realistic percentage for units that 

have already made substantial modifications to improve heat rate. Commenters stated that as a 

matter of fact, their units consistently rank in the top 20 coal fired units by heat rate and 

therefore, the Clean Power Plan should only use 1 - 1.5% heat rate improvement as the objective 

for Building Block 1.

Commenters stated that further, coal-fired steam generating EGU's are not designed with the 

same heat rate and North Dakota utilities' existing coal fleets are comprised of units of various 

ages, which were designed by different manufacturers to bum different types of coal. 

Commenters stated that North Dakota utilities have a long history of implementing heat rate 

improvements due to the fuel savings that can be realized and this experience has involved both 

equipment upgrades and O&M practices. Commenters stated that in an effort to determine what 

reasonable heat rate improvement opportunities for coal-fueled EGUs may exist in North 

Dakota, the Commission consulted with the operators of these facilities. Commenters stated that 

taking responses received into account, they believe a statewide heat rate improvement of 2 
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percent is the best that could be achieved and with regard to North Dakota, they believe this 

information is superior to the broad assumptions EPA used in developing the Proposed Rule. 

Commenters stated that EPA has made no effort to consider these circumstances at EGUs in 

North Dakota and EPA's 6 percent criteria is arbitrary as applied to North Dakota EGUs. 

Commenters stated that contrary to EPA's assumptions, Wisconsin's coal-fired EGU heat rates 

have improved over time. Commenters stated that Wisconsin's EGU heat rates have not degraded 

over time and in its analysis, EPA determined that heat rates have degraded for approximately 

40% of the coal-fired EGUs in the nation. Commenters stated that on this basis EPA concludes 

that there is potential to improve heat rates in every EGU in the nation, however, EPA's data 

actually shows that the heat rate for Wisconsin's vintage EGUs has not degraded at all; in fact, it 

has improved substantially since 2000. Commenters stated that this data, plotted in Figure 1 

(titled: “Average Heat Rate Trends and Capacity Utilization for Wisconsin Vintage Coal-fired 

EGUs”) reveals a trend in the early 2000s where the fleet gross heat rate is greater than 10,750 

btu/kWh. Commenters stated that since 2007, however, the trend has consistently been below 

10,500 btu/kWh. Commenters stated that this difference represents a 2% improvement in the 

fleet gross heat rate.

Commenters stated that looking more closely, from 2008 through 2010 the heat rate trend was 

consistently at or lower than 10,250 btu/kWh. Commenters stated that during this time period, 

the utilization of the fleet remained greater than 50% capacity factor, which is more comparable 

to the higher capacity factors in the early 2000s. Commenters stated that this comparison shows 

an efficiency gain of 500 btu/kWh - a 4% improvement in the fleet heat rate at capacity factors of 

50% or greater.

Commenters concluded that the Wisconsin coal-fired EGU heat rate, when compared to similar 

dispatch levels, appears to have improved by as much as 4% over time. Commenters concluded 

that this result indicates that there is little additional potential to improve Wisconsin's coal-fired 

fleet heat rate.

Commenters stated the Texas fleet tends to already operate efficiently which makes a 6% heat 

rate improvement less achievable. Commenters stated that Texas has a total of 41 operating coalfired EGUs and the average age of the Texas coal-fired EGU is 15 years newer that the national 

average coal-fired EGU fleet and newer units tend to be more efficient. Commenters stated that 

Texas has five units that are less than six years old and would otherwise be considered new units. 

Commenters stated that the average size of coal-fired EGU in Texas is larger than the national 

average-sized unit and efficiency tends to increase with size of the unit. Commenters added that 

Texas coal-fired EGUs operate in a competitive de-regulated energy market that already 

incentivizes efficiency improvements. Commenters stated that Texas has five units that are less 

than six years old and would otherwise be considered new units and new coal-fired EGUs are not 

capable of achieving a 6% heat rate improvement, because these units are already operating at 

very low heat rates. 

Commenters stated that even with the most optimistic outlook for tweaking existing coal plant 

efficiencies, an overall 6% efficiency gain is highly unlikely to be achieved for the fleet, so 

additional coal retirements could occur and/or the other EPA building blocks would need to 

compensate for that in order for states to comply. Commenters stated that the aggressive EPA 
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assumptions for those three building blocks only serve to increase reliability and sustainability 

concerns.

Commenters stated that the proposed 6 percent efficiency improvement for existing coal units is 

a step in the right direction, for they are doubtful that all of these investments would ever be 

made, given the rule's negative impact on coal generation and new-source review permitting. 

Commenters stated that the EPA again gets ahead of this current state of technology by assuming 

that all coal-fired units can achieve a 6-percent reduction in CO2 emissions through efficiency 

improvements, even as these units add energy-intensive and/or efficiency-reducing controls to 

comply with other EPA rules and furthermore, the EPA has provided no basis for the 6-percent 

number chosen for the rule, or cites any examples of plants that have been able to achieve that 

reduction through existing technology. Commenters stated that most of the straightforward and 

cost-effective measures to improve efficiency at power plants have already been implemented. 

Commenters stated that ESPS building block 1 assumes that coal-fired power plants can achieve 

a six percent improvement in heat rate as part of BSER through the application of best practices 

and equipment upgrades. Commenters were concerned that this level of improvement is overly 

ambitious because EPA does not seem to have fully considered that many plant efficiencies have 

already been realized as a result of currently existing incentives to operate units at peak 

efficiency and to the extent that a facility has already undertaken improvements and best 

practices to improve performance, further improvements may become infeasible. Commenters 

stated that also EPA does not appear to have considered the impact of post-combustion 

environmental controls in reducing the electric generating efficiency of facilities.

Commenters stated that the suggested heat rate improvements of 4-6 percent are largely 

unobtainable because: (1) utilities have been making efficiency improvements whenever 

economical and no realistic heat rate improvements exist, and (2) some heat rate improvements 

may trigger NSR. Commenters stated further, even if the 4-6 percent improvement was 

attainable, it would be inadequate to satisfy direct emission limits imposed by the goals set by 

EPA. 

Commenters stated that EPA's first building block incorrectly assumes that each coal-fired unit 

can improve and continuously maintain its efficiency by 6 percent and that this assumption is 

absurd considering the fact they already operate their units as efficiently as possible in order to 

minimize costs for their customers. 

Commenters stated that EPA's contention that power plants have the ability to decrease their heat 

rate and therefore improve plant efficiency by 6 percent is a concern and that talking to many 

utilities about this issue they have not heard of a single plant that could achieve anything more 

than one to two percent, and at a tremendous cost. Commenters stated that efficiency increases

that are cost-effective have already been made. 

Commenters stated that the EPA calculated CO2 emissions utilizing a 6 percent heat rate 

improvement from coal fired plants. Commenters questioned whether this is achievable because 

the items mentioned in the report on which this 6 percent number is based have largely been 

accomplished by EGUs previously and they have done the steam turbine replacements and other 
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heat-rate improvement projects. Commenters stated that improvements that are remaining are 

those projects that are not economically justifiable. 

Commenters stated that they are yet to identify a single expert in the industry who believes a 6 

percent heat rate improvement is achievable in Colorado's coal fleet. Commenters stated that if 

coal steam operators could achieve this improvement in order to benefit their customers, and 

frankly their own financial margins, they would have already done so. 

Commenters stated that the Proposed Rule assumes existing power plants can improve the 

efficiency of their power production by 6 percent, which is not technically feasible for the plants 

in Arkansas. Commenters stated that even with significant time and the investment of 

tremendous capital, the most likely efficiency improvements will be in the 1 percent to 2 percent 

range, at most. 

Commenters stated that their non-profit business model is based upon fulfillment of their mission 

to provide safe, affordable and reliable electricity to their members and part of satisfying their

mission to provide affordable utility service requires them to ensure their generating units are 

operating at optimum efficiency, thus, they have already captured most, if not all, of the costeffective heat rate efficiency in its units possible. Commenters stated that however, with 

significant additional capital expenditures, perhaps it is possible to squeeze some additional 

efficiency in certain-but not all-of their generating units, but the highest achievable efficiency 

improvement is actually a small fraction of the proposed 6%, and that is assuming a best-case 

scenario. 

Commenters stated that when creating its four-building-block formula for setting state emissions 

targets, EPA included a stringent measure that called for a 6 percent heat improvement rate at all 

coal-fired electrical generating units (EGU). Commenters stated this has been condemned by 

many utility executives as unrealistic and unworkable and a more fair and achievable 

improvement rate would be in the 1-2 percent range. Commenters strongly urged EPA to 

reconsider the 6 percent heat improvement rate requirement. 

Commenters stated that based on their experience in servicing and upgrading power plants, fewer 

than half of the existing coal-fired fleet would be able to achieve heat rate improvements of as 

much as 3%, in contrast with the EPA estimate of 6% heat rate improvement industry-wide. 

Commenters stated that applying the 3% improvement to the upgradeable half of the operating 

coal fleet, yields an industry-wide average heat rate improvement of 1.5% or less. 

Commenters stated that reducing carbon intensity of coal-fired generation through heat rate 

improvements is a viable component in EPA's Clean Power Plan but did not find EPA's 

assumption that a fleet-wide 6 percent heat rate improvement is based on documented, technical 

information. Commenters urged EPA to recognize that a state's carbon intensity can be reduced 

to some degree by efficiency improvements at coal-fired units, and that a state's overall carbon 

intensity can be minimized by enhancing the efficiency of zero-carbon emitting nuclear units. 

Commenters stated that it is appropriate that EPA establish a process to credit efficiencies that 

occurred at both coal and nuclear units and that existing market incentives and state regulatory 

policies require that utilities continually improve the efficiency of base load generation to 

minimize costs to customers, meet growing demand and maximize the dispatch of these units in 
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competitive markets. Commenters stated that the ability of these improved units to replicate 

additional efficiency improvements may be limited and as such, EPA should allow states to 

demonstrate the investments that have directly resulted in power plant efficiencies and to include 

this percentage in their compliance plans. 

Commenters stated that EPA does not justify the assumptions that 6% heat rate improvements 

are feasible in the administrative record. 

Commenters recommended that the EPA materially reduce the magnitude of reductions assumed 

to be adequately demonstrated for heat rate improvements at existing coal plants and 

recommended a level of no more than 3% as being more reasonable in light of the above flaws in 

EPA's analysis.

Commenters stated that a problem with EPA's use of a six percent heat rate improvement as part 

of its goal-setting process is that EPA incorrectly assumes that coal-fired power plants will 

maintain heat rate improvement over the life of the plant. Commenters stated that the heat rate 

improvement that coal-fired power plants can achieve through the installation of new turbines, 

rotors, economizers, fans, and other such equipment necessarily will decline over the course of 

time and that such normal declines are due to natural degradation of new equipment, installation 

of new pollution control technologies that impose parasitic loads, and changes in the duty of the 

power plants.

Commenters stated that Heat Rate Improvement is the only building block appropriate to be 

included in BSER determination but that however, the specific goal is unattainable. Commenters 

agreed with EPA's consideration of heat rate improvements in the determination of BSER, in 

fact, only Building Block 1 is appropriate to be included in the determination of BSER for 

existing fossil fuel-fired EGUs. Commenters stated that in Pennsylvania, heat rate improvements 

only account for 13.4 percent of the total CO2 reductions required by the final goal in the 

proposed rule. Commenters stated that the proposed levels of heat rate improvement of either six 

percent in the primary proposal or four percent in the alternate proposal across the entire fleet of 

coal-fired EGUs are not feasible. Commenters determined during its stakeholder engagement 

process that less than two percent heat rate improvements may be achievable by coal-fired EGUs 

in Pennsylvania. Commenters stated that the North American Electric Reliability Corporation 

(NERC) also states in its Initial Reliability Review that EPA's analysis is flawed and that the heat 

rate improvements of 6 percent may be difficult to achieve.

Commenters stated that IPM projects substantial HRIs at those coal-fired power plants remaining 

operational in 2025. Commenters stated that these HRIs represent a fleet-wide improvement of 

7.7% from 2012 levels in Ohio, as indicated by the CO2 emission intensity. Commenters stated 

that this HRI will be unattainable by those units remaining in operation beyond

2016. Commenters stated that as indicated in the comments related to Building Block 1, they do 

not believe the 6% HRIs proposed by U.S. EPA are achievable let alone 7.7% HRIs predicted by 

this model. Commenters stated that it is understood that these remaining coal-fired power plants 

will already be well-controlled and efficient, having operated in a deregulated, competitive 

power market for 24 years by 2025.
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Commenters stated that a 6% heat rate improvement as BSER is an overestimation of what is 

feasible for many EGUs; therefore, the alternative suggestion of 10% is even more infeasible. 

Commenters stated that the costs associated with the assumptions for this higher rate make this 

unreasonable and likely technically impossible for New Mexico's facilities.

Commenters stated that in calculating the emissions rate goal for each state EPA assumes that all 

coal-fired electric generation units can achieve a 6% heat rate improvement and that this 

assumption is unrealistic and unachievable for coal fired generation in Utah. 

Commenters stated that Utah currently has 10 coal fired units located at five power plants 

Carbon Power Plant (198 MW), Hunter Power Plant (1,472 MW), Huntington Power Plant (996 

MW), Intermountain Power Plant (1,800 MW), and Sunnyside Power Plant (58 MW). 

Commenters stated that this analysis applied heat rate improvements at Utah's three largest coal 

fired power plants Hunter, Huntington, and the Intermountain Power Plant. Commenters stated 

that Carbon Power Plant is scheduled to retire in 2015 and Sunnyside Power Plant size makes 

efficiency improvements unlikely. 

Commenters stated that in 2014 PacifiCorp filed a Fossil Fuel Heat Rate Improvement Plan 

(Plan) with Utah's Public Service Commission. Commenters stated that in the Plan, PacifiCorp 

indicates that a 1.3% average heat rate improvement across all its coal fired power plants 

between 2014-2023 is likely achievable and that this is significantly less than the EPA 6% heat 

rate improvement EPA assumes is possible. Commenters stated that accordingly, the 

contribution heat rate improvements could make towards meeting Utah's 2030 emissions is 

small. Commenters stated that if all Utah's coal-fired units were able to achieve the 1.3% heat 

rate improvements assumed in Pacific's heat rate improvement analysis, the emissions rate 

reductions would total 19 lbs/MWH reducing Utah's compliance gap to 372 lbs/MWH.

Commenters stated that the EPA incorrectly assumes that coal plants can operate six percent 

more efficiently although they already have every reason to operate as efficiently as possible. 

Commenters stated that EPA has not sufficiently supported its assumption that a fleet-wide six 

percent heat rate improvement is possible.

Commenters stated that Wisconsin utilities cannot meet the proposed six percent improvement in 

the heat rate of coal units and that most of the utilities already implement HRI programs to 

capture efficiency gains, leaving little room for additional improvement. Commenters stated that 

in addition, other EPA emission reduction mandates in existing programs and mandates set forth 

in this proposal actually negatively impact net heat rate.

Commenters stated that in order to provide affordable power to their members' ratepayers, they 

hold ownership interests in several coal-fired power plants located outside of California and 

therefore, has a strong interest in the assumptions about emission reductions from coal-fired 

EGUs that the EPA is using to establish state targets. Commenters stated that the EPA proposes 

that all coal-fired steam EGUs could reduce their emission rate by 6% by 2020 by employing a 

combination of equipment upgrades and operational "best practices." Commenters stated that 

although they cannot comment on the accuracy of these assumptions in the U.S. as a whole, it 

does not appear that the EPA's assumed coal-fleet-wide reduction of 6% is achievable for their 

units.
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Commenters stated that EPA's conclusions are unfounded. Commenters stated that while six 

percent may be technically feasible at a single point in time, at certain units, and under ideal 

conditions, in practice, the best heat rate improvements achievable for such upgrades and 

practices are significantly lower. Commenters stated that for example, one of their members is 

making equipment upgrades to two EGUs (which already employ best operating practices) to 

improve heat rates that, when completed, will increase efficiency by approximately a maximum 

of four and a half percent overall.

Commenters stated that the majority of coal-fired EGUs already have implemented the types of 

equipment upgrades and best practices on which EPA bases its six percent heat rate improvement 

estimate. Commenters stated that these plants cannot achieve the additional six percent heat rate 

improvement that EPA is proposing. Commenters stated that while these plants may be able to 

attain an additional one to two percent heat rate improvement, the work required to achieve this 

incremental improvement would be uneconomical. Commenters stated that for example, frequent 

turbine overhauls are not practical or economical, because these procedures require the unit to be 

out of service for an extended period of time.

Commenters stated that EPA makes a blanket assumption that all coal-fired EGUs are capable of 

achieving a six percent heat rate improvement. Commenters stated that in doing so, EPA ignores 

the real-world conditions faced by coal-fired EGUs and that most coal-fired units in the U.S. 

already undergo regular maintenance and upgrades to improve efficiency as part of good 

business practices. Commenters stated that improving heat rates makes units more competitive 

from a cost perspective and thus unit owners regularly evaluate and have already implemented 

opportunities to improve efficiency and performance. Commenters stated that to assume that all 

coal units could improve their performance by six percent ignores the fact that many units have 

already completed all economically feasible unit upgrades and improvements. Commenters 

stated that furthermore, even where additional efficiency may be achievable, it is unrealistic to 

assume companies will make the major capital investments necessary to achieve further 

reductions in the face of the reality that coal plants will operate less.

Commenters stated that efficiency gains, unlike emission reductions, cannot be continually 

ratcheted down beyond a certain point and as Einstein said, "Energy can neither be created nor 

destroyed..." Commenters stated that the USEPA proposal in Building Block 1 relies on the 

assumption that energy will be created by regulation, which may be a noteworthy and unique 

goal, but that does not make it physically possible. Commenters stated that the goal for Building 

Block 1 should be reduced to a more realistic and attainable level. 

Commenters stated that the utility industry has already performed many of the plant efficiency 

improvements included in the CPP's justification and cannot achieve an additional 6% 

improvement and that the goal of an additional 6% heat rate improvement is not achievable and 

the CPP should use a more realistic 1% -2% goal. Commenters further stated that most projects 

under consideration will realize a heat rate improvement between 0.05% -0.68% and therefore 

they recommended modifying the heat rate improvement target in building block 1 between1%-

2%. 

Commenters stated that EPA has proposed a 6% increase in fossil fuel efficiency based on a 

national assessment of the capabilities of the industry to improve plant efficiency (~2%) and to 
140

improve operational efficiency (~4%), however, EPA's assessment of national capabilities does 

not appear to be sufficiently rigorous or granular to conclude that such a reduction is indeed 

attainable. Commenters stated that their analysis suggests that EPA's assessment is not only 

incorrect, but asserts it will also be reasonable to conclude that fossil plant efficiency will 

actually decrease under the CPP.

Commenters summarized BB1 and stated that for a number of reasons, they believe EPA's 6 

percent figure is unrealistic and inappropriate for coal-fired steam EGUs in Indiana. 

Commenters stated that in calculating a state's emission rate goal, EPA assumes that, in 

aggregate, all coal-fired steam EGUs within the state can achieve a 6% efficiency (heat rate) 

improvement, consisting of a 4% improvement via "best practices to reduce hourly heat rate 

variability" as a "best-practices opportunity," along with a 2% improvement via "equipment 

upgrade opportunity" based on a 2009 Sargent & Lundy (S&L) report. Commenters stated yet 

EPA provides no data showing that an average 6% improvement has been demonstrated to be 

available for all coal-fired units within a state (or even for a large set of units) and that the BSER, 

for purposes of establishing standards of performance, must be "adequately demonstrated" and 

"achievable" - not simply an "opportunity " and unless a heat rate improvement value is 

achievable, it cannot be part of the BSER. 

Commenters stated that EPA's building block one would require a significant improvement in the 

efficiency of coal-fired electric generating units by requiring those units on average, to reduce 

their heat rate by 6 percent. Commenters stated that EPA concluded that a 6 percent 

improvement was possible by identifying two categories of actions that EPA claims utilities can 

use to cost-effectively improve the efficiency of their generating units, namely (i) operation and 

maintenance (O&M) "best practices" and (ii) capital projects. Commenters stated that although 

the activities EPA identified can have some beneficial impact on the heat rate for coal-fired units, 

EPA's analysis contains many unsupported assumptions that in any event have little relation to 

the analyses EPA claims to have conducted. Commenters stated that EPA has made no effort to 

assess potential (or achievable) heat rate improvement opportunities at lignite-fueled EGU's in 

North Dakota or elsewhere and, in reality, the commenters believed that a 6 percent heat rate 

improvement "across the board" is not feasible. Commenters stated that further, the building 

blocks together will almost certainly cause a deterioration in coal unit efficiency, rather than an 

improvement. 

Commenters stated that the emission reductions EPA has proposed under block one are clearly 

not achievable either for the industry as a whole or for them in particular. Commenters stated for 

example, in their case, the previous investments in efficiency upgrades and the ongoing 

efficiency improvement programs already ensure that their units are consistently operating as 

efficiently as possible. Commenters stated that heat rate improvements at the level of 6% are 

clearly not attainable, and even marginal improvements beyond current heat rates would be 

extremely costly

Commenters stated that the environmental limits that are in place now are obtainable, but the 

ones that they see, in this new law, are not, where the technology that's in place, from operating 

these units for 38 years.
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Commenters stated that in Building Block 1 of the Clean Power Plan, the administration makes 

the assumption that a 6 percent efficiency improvement is possible with all existing units, and 

such is not realistic for their coal plant. 

Commenters stated that they have not heard of a generator anywhere that can say that they can 

do even 1 percent and that six percent is extremely aggressive. 

Commenters stated that EPA's proposed Building Block #1 ("BB1") is unreasonable because it 

seeks to require unachievable HRI from coal-fired EGUs of 4-6%. Commenters stated that EPA's 

assumption that 4-6% HRI levels are achievable is unfounded as the Agency assumes that 4% 

HRI can be achieved by the entire fleet of coal-fired EGUs through the adoption of heat rate 

variability best practices and an additional 2% HRI can be achieved by equipment upgrades. 

Commenters stated that these HRI's are not possible. 

Commenters stated that EPA's selection of a 6% HRI is arbitrary and fails to provide an accurate 

picture of realistically achievable heat rate reductions at any given coal-fired EGU. Commenters 

stated that in proposing a 6% HRI, EPA calculated the average heat rate for coal-fired EGUs 

nationwide to be 9,753 Btu/kWh based on gross generation. Commenters stated that EPA arrived 

at its 6% goal by requiring 4% HRI from best management practices ("BMP") and 2% HRI from 

equipment upgrades. Commenters stated that while an average of 6% HRI might be possible 

when spread across the country, a 6% HRI is likely unachievable at individual EGUs covered by 

the Proposed Rule. Commenters stated that accordingly, emissions targets are unfairly lowered 

for states that cannot technically or economically achieve the full 6% HRI. 

Commenters stated that they operate coal-fired units in Wyoming and placed each of the units 

into service between 1995 and 2010, and none are greater than 100 MW in capacity. 

Commenters stated that these relatively new and small units are efficient. Commenters stated that 

they retained Black & Veatch to analyze the suggested equipment and operational modification 

options suggested in the Sargent & Lundy study used by the EPA to support its proposed six 

percent efficiency improvement to existing coal generating units. Commenters stated that the 

analysis estimated the heat rate improvements and associated capital costs of implementing 

EPA's suggestions to their four coal-fired power plants at the Neil Simpson Complex in Gillette, 

Wyoming. Commenters stated that the results from that study, coupled with their own internal 

analysis, show that the range of achievable operating efficiency improvements is well below the 

six percent target included in the proposed rule - and likely no greater than two percent. 

Commenters' internal analysis included consideration of relevant risk factors, such as those 

associated with New Source Review (NSR) permitting and potential enforcement actions. 

Commenters stated that in light of this assessment, they suggest EPA factor efficiency 

improvements of less than 2 percent, along with an expedited NSR permitting process. 

Commenters stated that EPA's methodology for determining the 6% heat rate improvement at 

coal-fired Electrical Generating Utility Systems (EGUs) is flawed and did not take into account

the heat rate penalty due to the installation of emission controls to meet the Mercury and Air 

Toxics Standards (MATS) and other requirements. Commenters stated that heat rate penalty, as a 

result of these requirements, should be factored into the guidelines for building block 1. 
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Commenters stated that the Proposed Rule assumes that a state's affected coal-based EGU fleet 

could achieve, on average, a six percent improvement in heat rate leading to a six percent 

reduction in CO2 emissions ("Building Block 1"). [See 79 Fed. Reg. at 34861]. Commenters 

stated that however, EPA fails to support this assumption with facts, as explained herein, and 

thus its BSER for Building Block 1 is arbitrary and capricious.

Commenters expected that generators will not move to make such HRIs if and until the rule is 

finalized and the State Implementation plans are finalized. Commenters stated that this would be 

expected to be mid 2017 or 2018 according to EPA's timeline and given the need to review and 

prepare plans, order materials, do required engineering, and install the plant improvements, 

Commenters believed that the early reductions sought by Building Block 1 likely cannot be 

achieved. 

Commenters stated that the 6% emission rate reduction goal-setting for coal units is applied 

everywhere, but is not achievable at most units 

Commenters stated that Virginia's EGUs have already implemented the heat rate improvements 

that are "technically feasible and of reasonable cost." Commenters stated that EPA says "building 

block 1 encourages the spread of more advanced technology to EGUs currently using 

components with older designs." [79 Fed. Reg. at 34,882]. Commenters stated that Virginia's 

EGUs have already evaluated "more advanced technology" and continue to apply it where the 

cost is "reasonable." Commenters stated that a mandated further 4-6 percent improvement in heat 

rate efficiency at Virginia's existing EGUs is simply not feasible. Commenters stated that as EPA 

notes, "Heat rate improvements pay for themselves at least in part through reductions in fuel 

costs." [79 Fed. Reg. at 34,856]. Commenters stated that Virginia's EGU owners know this and 

have already reduced their fuel costs by implementing all cost-effective heat rate improvements 

and in short, heat rate improvements have already been implemented in Virginia, and there are 

no further technology retrofits that can be applied to Virginia's EGUs at a reasonable cost. 

Commenters stated that EPA's methodology of determining 6 percent HRI is

flawed. Commenters briefly described EPA's methodologies for HRIs.

Commenters stated that EPA overestimated the 6 percent heat rate improvement and a case-bycase assessment must be made to determine each unit's true heat rate improvement potential. 

Commenters stated as a result, EPA has inappropriately established the Best System of 

Emissions Reduction ("BSER"). 

Commenters stated that EPA should recalculate emission rate goals, applying technologically 

feasible and demonstrated heat rate improvements at existing coal-fired units. Commenters stated 

that EPA has not adequately demonstrated that existing EGUs can realize a six percent 

improvement in efficiency as assumed by EPA in the current goal setting methodology.

Commenters stated that they commissioned the engineering firm Burns & McDonnell ("BMcD") 

to conduct a technical assessment of EPA's building block 1, and that assessment uncovered 

many errors in EPA's analysis and found that EPA's projected improvements in heat rate are not 

achievable. Commenters stated that as discussed in the attached Heat Rate Technical Support 

Document, BMcD found that EPA's assumed 6% heat rate improvement (building block 1) is not 
143

possible for their units and at best, the overall heat rate improvement that could be achieved at 

their units is less than 1%, accepting EPA's premise that heat rate improvements the EPA and 

others have alleged trigger New Source Review ("NSR") should not be considered. Commenters 

stated that, as NERC concluded in its initial assessment of EPA's proposal, the heat rate 

improvements required by EPA "may be difficult to achieve" because "many plant efficiencies 

have already been realized and economic heat rate improvements have been achieved."

Commenters stated that EPA's analysis - mostly data and literature review, with no actual unit 

assessments - does not adequately demonstrate that 6% improvements can be achieved. 

Commenters stated that indeed, their unit-specific analysis shows that such a drastic reduction in 

heat rate from existing units simply is not feasible or achievable at Texas EGUs. Commenters 

stated that neither is EPA's "alternative" of a 4% total improvement.

Commenters stated that, as described in the Heat Rate TSD, the overall reasonable heat rate 

improvement for their coal-fueled fleet for the projects outlined by S&L and NETL ranges from 

only 0.02% to 0.38% after considering technical feasibility, permitting implications associated 

with NSR, and economic feasibility. Commenters stated that for their specific units, the longterm, overall heat rate improvement would likely be less than a 1% improvement under the best 

circumstances. Commenters stated that this level of heat rate improvement would be more 

typical for all plants across their fleet, not EPA's arbitrary assumption of 6%. 

Commenters disagreed with EPA's assumption under "Building Block 1" that existing coal-fired 

electric generating units can achieve a six percent heat rate improvement through the "adoption 

of best practices" and "equipment upgrades " and stated this claim is unfounded. 

Commenters stated that EPA's assumes that coal-fired power plants can reduce their emissions 

by 6% by implementing heat rate improvements, ignoring efficiencies already achieved and 

mistakenly counting each efficiency improvement as additive. Commenters stated that EPA's 

assumptions are inaccurate. Commenters stated that achievable heat rate targets should be

established by the states based upon unit specific criteria and encompass or credit prior 

efficiency improvements. 

Commenters stated that Building Block 1 assumes that existing coal-fired power plants can 

achieve an average overall heat rate improvement of 6% through technology upgrades and 

implementation of best operating practices. Commenters stated that this assumption, however, 

ignores the inherent technological limits to heat rate improvements because with current 

technology, there is a finite amount of efficiency improvements that can be made to existing 

generators and the level of available improvements depends on the improvements that have 

already been made to a plant. Commenters stated that when starting with a plant that was built in 

the 1960s or 1970s and that has not since made efficiency improvements, a 6% heat rate 

improvement may very well be feasible but the same is not true for more recently constructed 

plants or plants that have undergone prior efficiency upgrades, which may only be able to 

achieve an efficiency improvement of 3-4% at most. 

Commenters urged EPA to reconsider its application of heat rate improvements in "Building 

Block 1" to establish the Best System of Emissions Reduction ("BSER") for CO2 emission 

reductions in Puerto Rico. Commenters stated that in its supplemental Proposal, EPA has again 
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simply imported the assumed, across-the-board heat rate improvement of 6% (or in the 

alternative, 4%) that EPA has proposed for United States-based facilities in its existing source 

performance standards proposed rule ("ESPS proposal") and assumed that same 6% 

improvement in heat rate could be achieved at their facility. Commenters stated that the 

improvement in heat rate, EPA contends, would be achieved by changes in power plant 

operations and significant new capital projects. Commenters stated that EPA did not consider the 

actual technical capabilities of the commenters' power plant or the rights and obligations arising 

under their PPA with PREPA. 

Commenters stated that Kansas City BPU is the only municipal electric utility in Kansas that 

owns and operates coal-fired generation and as such, they defer to KCBPU comments in regards 

to the feasibility of EPA's assumed six percent heat rate improvement applied to all coal-fired 

power plants. Commenters stated that however, it is their understanding that such an ambitious 

goal is not even remotely achievable across the entire fleet of affected units in Kansas. 

Commenters stated that the assumption that a 6 percent efficiency improvement is possible with 

all existing units is not realistic for their plant. 

Commenters stated that the environmental limits that are in place now are obtainable, but the 

ones that they see, in this new law, are not, where the technology that's in place, from operating 

these units for 38 years.

Commenters stated that they conducted an extensive stakeholder outreach which has confirmed 

their analysis and conclusions with regards to the technical infeasibility and impracticality of 

U.S. EPA's nationwide application of a 6% HRI goal. Commenters stated that external to their

stakeholder outreach, they would encourage U.S. EPA to carefully consider those comments 

submitted to the docket by EPRI on October 20, 2014 and the references contained therein. 

Commenters stated that EPRI has substantial technical expertise in power generation and 

distribution research, and many of EPRI's comments mirror those concerns and conclusions 

expressed by their organization. Commenters stated that EPRI concludes that while there may be 

potential HRI available, these will be unit specific and should take into account recent U.S. EPA 

environmental control regulations; also those HRI available may not be additive, and again will 

be highly dependent on unit characteristics, such as age, design, and environmental controls. 

Commenters stated that EPRI also notes that many potential HRI projects are not conducted 

based on the financial risks associated with new source review (NSR), and that such an 

impediment to HRI projects should be considered by U.S. EPA in its calculations. Commenters 

stated that EPRI recognizes that increased penetration of renewables and increased use of NGCC 

units may cause some coal-fired plants to operate as load-following units, potentially degrading 

any potential for HRI. Commenters reiterated that through its own analysis, extensive 

stakeholder outreach, external research such as the EPRI comments referenced above, and the 

clear statement issued by Sargent and Lundy concerning the misapplication of their 2009 HRI 

study by U.S. EPA in the development of this proposal. Commenters stated that the assumption 

of a nationwide 6% HRI across the coal-fired fleet is technically infeasible and impractical and 

should not be used without further research and validation to form state CO2 intensity goals. 

Commenters stated that EPA proposes heat rate improvements at coal-fired EGUs of six percent, 

which EPA claims can be achieved through the adoption of best practices to reduce heat rate 
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variability and implementation of equipment upgrades at coal-fired EGUs. [79 Fed. Reg. at 

34,861]. Commenters stated that EPA's claim is unfounded and while six percent may be 

technically feasible at a single point in time, at certain units, and under ideal conditions, in 

practice, the best heat rate improvements achievable for such upgrades and practices across the 

industry are significantly lower. 

Commenters stated that Block One's 6% heat efficiency improvement assumption is unrealistic 

because the heat rate efficiency of a plant is impacted by a variety of factors, all of which must 

be considered in order to determine whether the efficiency of a given coal-fired plant can be 

increased. Commenters stated that these factors include, but are not limited to: the plant's 

thermodynamic cycle; the rank and quality of the coal being burned; the plant's size, with 

increased efficiency stemming from increased physical size; the pollution control systems in 

place; the operating and maintenance practices, such as combustion optimization and equipment 

maintenance; the cooling system; the geographic location and ambient conditions; the load 

generation flexibility requirements; and the plant components, such as the ability to use the 

optimum number of feedwater heaters, high-efficiency electric motors, variable speed drives, and 

better materials for heat exchangers. 

Commenters stated that EPA concedes that all of the improvement technologies discussed cannot 

necessarily be implemented at every existing coal-fired facility in the U.S., nor can the existing 

coal fleet do much, if anything, about certain design configurations and other site-specific factors 

that would result in greater efficiency. Commenters stated that a review of the "GHG Abatement 

Measures" technical support document does little to answer these questions. Commenters stated 

that for example, will the efficiency updates necessitated by the Plan trigger a new source review 

("NSR"). Commenters stated that this question is not addressed, yet even more relevant given 

that EPA has brought enforcement suits against utilities for similar upgrades. Commenters stated 

that also, there is no indication that the power plants were assessed state-by-state, making it 

impossible to tell whether the technologies mentioned could be applied to a state's existing units. 

Commenters stated that conversely, what should be done if a state's plants have already 

implemented the suggested efficiency protocols.

Commenters stated that utilities already have every incentive to run their plants efficiently, and 

have made significant strides to do so. Commenters stated that in fact, West Virginia's Longview 

power plant in Morgantown was named the most efficient coal-fired plant in the U.S. fleet in 

2011. Commenters stated that yet without recognizing the differences between plants, EPA 

asserts that a 6% improvement across-the-board is reasonable. Commenters stated that 

furthermore, if utilities have already completed the efficiency upgrades that are cost-effective, 

the Plan disincentivizes them from undergoing efficiency measures that are more costly. 

Commenters stated that as the President and EPA have made clear, the object of this Plan is to 

phase out coal-generated power. Commenters stated that it is therefore unreasonable to think that 

utilities will spend money on costly upgrades to their plants when the plants are being phased 

out. Commenters stated that also, given the regulatory atmosphere, there is no guarantee that 

these improvements will not be stranded. Commenters stated that even a pro-Plan discussion 

paper authored by West Virginia University and the activist group Downstream Strategies 

("WVU Discussion Paper") called into doubt the state's ability to reach a 6% heat efficiency 

improvement. Commenters stated that the WVU Discussion Paper assesses that West Virginia 

may be able to achieve a 3% efficiency increase, after taking into account the fact that some of 
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the efficiencies proposed by the Clean Power Plan have already been implemented in West 

Virginia. Commenters stated that Block One simply makes too many assumptions for a global 

6% heat efficiency improvement to be achieved. 

Commenters stated that for Building Block 1, EPA proposed to find that "a six percent reduction 

in the CO2 emission rate for coal-fired EGUs in a state, on average, is a reasonable estimate of 

the heat rate improvements that can be implemented at a reasonable cost." 79 Fed. Reg. 34861. 

Commenters stated that an overall 6% heat rate improvement, however, is not feasible for 

utilities that regularly maintain their power plants to retain original design efficiency and have 

likely already implemented cost effective heat rate improvements. Commenters stated that the 

target heat rate improvement should be established on a case-by case basis, considering the 

design and existing efficiency of the units.

Commenters stated that most electric utilities generally maintain their power plants to retain 

efficiency. Commenters stated that indeed, most utilities already implement ongoing heat rate 

improvement programs to capture the efficiency gains that EPA is assuming in the "best 

practices" portion of Building Block 1. Commenters stated that numerous routine maintenance 

projects occur every year as a means of retaining power plant efficiency. Commenters stated that 

larger, less frequent maintenance projects must be evaluated with respect to prevention of 

significant deterioration (PSD) and new source review (NSR) air quality permitting 

requirements, which may trigger more stringent control requirements unrelated to the proposed 

maintenance project.

Commenters stated that as noted in one of the technical support documents considered in this 

rulemaking, they have taken steps to maintain the efficiency of their units. Commenters stated 

that as discussed in a document entitled Review of Potential Efficiency Improvements at CoalFired Power Plants, dated April 17, 2001, in the 1990s they undertook several projects which 

resulted in significantly improved heat rates at their coal fired units in Wisconsin. Commenters 

stated that the heat rate improvements at the individual plants ranged from 2.9% - 4.1%. 

Commenters stated that while they were able to achieve this level of improvement in the 1990s, 

it would not be able to see such an improvement now because those specific actions can only be 

taken once. Commenters stated that almost all forms of heat rate improvement will degrade over 

time, requiring ongoing maintenance efforts, such as a turbine overhaul, to return the unit to near 

design conditions. Commenters stated that these maintenance activities, however, would not 

result in the same level of heat rate improvement that one would see when first undertaking the 

projects. Commenters stated that plus, emission control systems that have been installed or are 

expected to be installed will degrade heat rates by approximately 1.5% to 1.75%.

Commenters stated that there are other factors that affect the ability of EGUs to achieve a heat 

rate improvement of 6% on average. Commenters stated that a significant driver of average heat 

rate is the capacity factor of a unit, and it is unlikely that an average heat rate improvement of 

6% could be achieved and sustained on coal units that may be dispatched at reduced load points 

in the future in order to meet an emission reduction goal, or because of increased utilization of 

NGCC units (Building Block 2) or increased renewable generation (Building Block 3).

Commenters stated that a case-by-case evaluation of the potential for, and cost-effectiveness of, 

heat rate improvement projects at individual EGUs would be a more appropriate mechanism than 
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the application of a uniform assumption as proposed by EPA. Commenters stated that indeed, the 

federal rules addressing the development and submittal of state plans under Section 111(d) 

contemplate that states may make case-by-case determinations in certain instances, including 

when the application of a less stringent standard is "significantly more reasonable." See 40 

C.F.R. Section 60.24(f). Commenters stated that additionally, new units, for which heat rate 

improvements are likely not possible, should be excluded from the target calculation. 

Commenters stated that EPA's proposal is based upon a complex web of assumptions - many of 

them implausible - about future energy demand, dramatic shifts in generation sources, the 

addition of more intermittent sources for generation and reductions in energy use in 48 states and 

each of these assumptions - what EPA ironically calls "building blocks" - rests upon a weak 

foundation. 

Commenters stated that EPA assumes that coal-fueled plants can achieve a 6 percent heat rate 

improvement by 2020 through a combination of recommended operation and maintenance 

practices (4%) and capital investments (2%). Commenters stated that the regression analysis 

used by EPA to assume a 4 percent heat rate improvement lacks sufficient technical data and 

fails to account for differences in coal rank, boiler type and boiler age, all of which have 

significant effects on heat rate efficiencies. Commenters stated that an analysis by Energy 

Ventures Analysis (EVA) using an algorithm that incorporates the factors EPA omits shows no 

incremental heat rate improvements were possible from additional practices. Commenters stated 

that the 2 percent improvement from capital investments rests upon a single 2009 study, 

however, EPA's reliance upon that study is misplaced. Commenters stated that the study did not 

conclude that all coal plants can improve heat rates - let alone by 2 percent from 2008. 

Commenters stated that at the same time, EPA's MATS rule issued two years ago requires 

extensive retrofits of existing plants that will make them less efficient by increasing their 

parasitic load and moreover, the present proposal will force many coal plants to run at reduced 

and sub-optimal levels which in turn will also make them less efficient. 

Commenters stated that, with regards to proposing six percent (6%) average heat rate 

improvement for all existing coal-fired steam generating units, they support OPC comments 

regarding concerns for the viability of Building Block 1. Commenters stated that based on thirdparty, expert analysis, they also believe that the EPA's proposal and assumptions," ... diverges 

significantly from what is actually achievable at most units and what is within EPA's statutory 

authority..." 

Commenters stated that EPA fails to adequately justify or disclose its assumptions for each of the 

four building blocks used to establish BSER. Commenters stated that in building block one, EPA 

makes a blanket assumption that all coal-fired electric generating units ("EGUs") are capable of 

achieving a six percent heat rate improvement and in doing so, EPA ignores the real-world 

conditions faced by coal-fired EGUs. Commenters stated that most coal-fired units in the U.S. 

already undergo regular maintenance and upgrades to improve efficiency as part of good 

business practices and improving heat rates makes units more competitive from a cost 

perspective and thus unit owners regularly evaluate and have already implemented opportunities 

to improve efficiency and performance. Commenters stated that to assume that all coal units 

could improve their performance by six percent ignores the fact that many units have already 

completed all economically feasible unit upgrades and improvements. 
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Commenters stated support for industry comments indicating that the 6 percent coal unit heat 

rate target is not adequately justified, with considerable variation among units and difficulty for 

some units to improve heat rate. 

Commenters stated that Building Block One is the first step in determining the rate-based goals. 

Commenters stated that the EPA assumes that, by improving the heat rate efficiencies of coalfired EGUs by 6%, the emission rates of coal plants can be equally reduced. Commenters stated 

that the EPA is not making any assertions about specific units or plants and is simply suggesting

that the BSER assumption of a 6% heat rate improvement for the coal fleet can be achieved on 

average at the state level. Commenters stated that the assessment concluded that coal units can 

achieve up to a 4 percent heat rate improvement through the use of best operational practices, 

and an additional 2 percent through capital upgrade investments. Commenters stated that most 

utilities do not believe that a 6% heat rate improvement is achievable, in fact, as a result of 

improvements and upgrades it already has made, Ameren Missouri, the largest utility in 

Missouri, believes only a 1% to 2% improvement on average would be realizable, and only at 

great cost. 

Commenters stated the EPA's assumption that better operational practices and equipment 

upgrades can cut the amount of fuel burned to produce a kilowatt of electricity (the heat rate) by 

6 percent has also been brought into question by the NERC. Commenters stated that EPA 

suggests that thermal efficiency could be boosted by regular steam turbine overhauls, while 

NERC warns that the outage time for such procedures means that regular turbine overhauls are 

generally neither practical nor economical. Commenters stated that the NERC also thinks that the 

agency has overestimated the potential to make easy and cost-effective improvements; and that 

the NERC notes that energy producers already have plenty of price and cost incentives to run 

their units as efficiently as possible. 

Commenters stated that in the application of building block 1, EPA estimated the total technical 

potential for heat rate improvements from adoption of best practices to reduce heat rate 

variability and implementation of equipment upgrades to be six percent. Commenters stated that 

the baseline for the six percent improvement is assessed by the EPA as the average net unit heat 

rate for each EGU in calendar year 2012. Commenters stated that this assumption is based, in 

part, on a report, Coal-Fired Power Plant Heat Rate Reductions, prepared by Sargent & Lundy 

(S&L) in 2009. Commenters stated that when applying building block 1, EPA applied the 

estimated six percent heat rate improvement to all coal-fueled EGUs, regardless of any particular 

unit's technical potential for such improvements.

Commenters stated that to assess the feasibility and achievability of EPA's conclusions for their

own resources, they reviewed their coal-fueled EGUs on a unit by unit basis in light of EPA's 

analytical assumptions. Commenters stated that as with many utilities, they have an economic 

incentive to improve operating efficiencies and therefore already exercise best operating 

practices and implementation of heat rate improvement projects where necessary and 

economically justified to improve plant efficiency. Commenters stated that cost-effectively 

minimizing heat rate (maximizing unit efficiency) is a key operating objective for their coalfueled EGUs and implementation of heat rate improvements must balance cost effectiveness, 

while ensuring compliance with all environmental and regulatory requirements and optimizing 

the reliability and efficiency of the coal-fueled EGUs over their respective remaining lives.
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Commenters stated that in practice, a number of the improvements suggested in S&L's report 

were already implemented on their generation units during or before 2012. Commenters stated 

that as a result of their previous heat rate improvements, they estimate that a 2.6 percent 

improvement in its average fleet-wide heat rate of their coal fired units may be economically 

practicable and/or technically feasible if all identified opportunities were ultimately 

implemented. Commenters provided a table identifying these opportunities for each of their coalfueled EGUs. Commenters stated that modifying the heat rate improvement potential would help 

to ensure that EPA's BSER assumptions regarding heat rate improvements are achievable in 

practice and supportable by actual implementation rather than theoretical potential. 

Commenters stated that they believe the projected goal of 6% heat rate improvement for all 

existing generators is overly ambitious. Commenters stated that heat rate improvements of 6% 

from 2012 levels are simply unattainable. Commenters stated that the efficiency gains of the past 

ten to twenty years would be impossible to replicate going forward. Commenters stated that the 

Agency should recognize that utilities systematically analyze potential projects for heat rate 

benefits and, accordingly, that all of the low-hanging fruit has been exhausted. Commenters 

stated that it is impossible to extract an additional 2%, 4%, or 6% efficiency improvement from a 

unit that has already been the subject of, for example, a turbine or fan motor efficiency retrofit. 

Commenters stated that a six percent heat rate improvement at existing coal-fired power plants is 

an overly aggressive heat rate improvement for states to achieve by 2020 and should not be 

raised further. Commenters stated that the State of Montana's discussions with EGU operators in 

Montana since the draft rule was published and that it suggest that a six percent heat rate 

improvement is unlikely to be cost-effectively achieved at some, if not all, of the affected EGUs 

in Montana. Commenters stated that this is especially true considering that recent heat rate 

improvements at those affected EGUs will not count toward the six percent if they were done 

before 2012 and as a result, additional reductions in the carbon emission rate will need to be 

generated from fuel switching, renewable electricity, energy efficiency, and other options 

available to the state. Commenters stated that any increase to building block #1 would only 

exacerbate the discrepancy between EPA's proposed heat rate improvement and what is 

achievable in Montana, further driving up compliance costs for the state while potentially failing 

to deliver any further carbon emission reductions. 

Commenters stated that EPA's assumptions of achievable HRI are based on its false 

interpretations of the Sargent & Lundy report, a 2009 study by the engineering firm Sargent & 

Lundy, and its uninformed assumptions of determining factors in its own sixteen unit study. 

Commenters stated that based on its faulty assumptions derived from these studies, EPA cannot 

adequately justify the feasibility of a 6% HRI for all coal-fired EGUs. 

Commenters stated that this building block is particularly problematic because of how increasing 

penetrations of increased utilization from the other building blocks will affect coal fired power 

plants. Commenters stated that EPA has deemed a 6% heat rate improvement across the board as 

feasible, however, the EPA needs to consider the research on this subject in light of the current 

state of the electricity market. Commenters stated that coal fired power plants are retiring due to 

age (median age is 42 years), pending environmental legislation, cheap natural gas, and 

increasing penetrations of renewables. Commenters stated that given the current state of the 

market and the how the above building blocks will hurt coal plants - revenue, they find it very 
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unlikely that coal plants will be able to economically justify new capital costs, legal costs of New 

Source Review, revenue lost by shutting down the power plant for construction, and other 

expenditures necessary to extend the plant lifetime. Commenters stated that to determine this 

building block's feasibility, the EPA needs to identify newer, inefficient power plants that will 

continue to have a high capacity factor once the above building blocks are in place. 

Commenters stated the EPA's fundamental assumption in block 1 is that every fossil power plant 

- especially every coal plant - is capable of achieving an additional 4%-6% heat rate 

improvement. Commenters stated that indeed, their calculations on which it imposes the goals 

established by the Clean Power Plan assume that across the board, all fossil-fueled power plants 

will achieve a 4%-6% heat rate reduction, but this assumption is wrong.

Commenters stated that Laramie River Station (LRS) is consistently operated as efficiently as 

possible and as consumer-owned utilities, the co-owners are motivated to optimize efficiency as 

a matter of sound economic business principles, and are not required to wait on approval from a 

state regulatory commission to undertake such projects. Commenters stated that in recent years, 

the owners of LRS have taken significant steps to improve the heat rate, including the following 

projects, along with the noted improvement in heat rate: 

• Turbine upgrades, 200 Btu/kWh

• Hydrojet installation to clean the boiler walls, 40 Btu/kWh

• Installation of an intelligent soot blowing program, 20 Btu/kWh

• CO monitors / combustion optimizer, 25 Btu/kWh

Commenters stated that in addition, LRS has a deliberate maintenance program to ensure that the 

heat rate is maintained and does not degrade more rapidly than normal and other significant 

maintenance activities to maintain the heat rate include:

• Condenser wall repairs

• Cooling tower maintenance

• Condenser Air in leakage testing and repairs

• Ductwork repairs

• Pulverizer maintenance (Babcock & Wilcox assured stock program)

• Feedwater heater replacements

• Steam trap surveys and maintenance

• Condensate subcooler replacements

• Compressed air system leakage surveys and maintenance
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Commenters stated that taken together, these efforts have improved the overall efficiency about 

three percent (3%) and they also demonstrate an ongoing effort to operate LRS as efficiently as 

economically possible, a practice that is undertaken consistently by the industry in 

general. Commenters stated that further, discussions with states in the region also indicate that it 

appears EPA's best practices have already been implemented by a majority of coal-fired power 

plants in Region 8, providing further proof that this building block is unrealistic. 

Commenters stated that EPA's assumptions on heat rate improvements for Building Block 1 are 

invalid because EPA incorrectly assumes that all existing coal-fired power plants can achieve an 

additional 6% heat rate improvement. 

Commenters stated that under no circumstance should EPA base the state emission rate standards 

on an arbitrary uniform heat rate improvement of 6% that is unsupported in practice or EPA's 

record. 

Commenters stated that the Proposed Rule asserts that a 6 percent improvement was possible by 

identifying two categories of actions that EPA claims utilities nationwide can use to costeffectively improve the efficiency of their generating units, namely (i) operating and 

maintenance (O&M) "best practices" and (ii) capital projects. Commenters stated that the 

Department consulted with operators of coal-fueled EGUs in North Dakota and understands that 

heat rate improvements of up to 2 percent may be possible. Commenters stated that EPA, 

however, has made no effort to consider these circumstances at EGUs in North Dakota. 

Commenters stated that assumptions by the EPA in its BSER building blocks have been major 

topics of discussion within the Energy Coalition. Commenters stated that they anticipate that

other stakeholder members will provide the EPA with the technical details related to the 

feasibility of the building blocks, however, they would like to point out two major issues related 

to heat rate and natural gas re-dispatch. Commenters stated that it is uncertain if a six percent 

heat rate improvement (fleet-wide average) could even be achieved and maintained at a coalfired unit in South Carolina. Commenters stated that if this level of improvement was achievable, 

it likely would have already been done for economic reasons. Commenters stated that several 

utility stakeholders have also stated that without significant physical plant modification it would 

be impossible to achieve this improved rate. 

Commenters stated that in calculating a state's emission rate goal, EPA assumes that, in 

aggregate, the coal-fired steam EGU fleet within each state can achieve and maintain indefinitely 

a 6 percent efficiency (heat rate) improvement. Commenters stated that the proposed 6 percent 

improvement consists of 4 percent improvement via "best practices to reduce hourly heat rate 

variability" along with a 2 percent improvement via "equipment upgrade opportunity" based on a 

Sargent & Lundy (S&L) report. Commenters stated that this is, simply put, hand waiving. 

Commenters stated that EPA provides no data showing that an average 6 percent improvement 

has been demonstrated to be available for all coal-fired units within a state (or even for a 

moderate set of units). Commenters stated that BSER, for establishing standards of performance, 

must be "adequately demonstrated" and "achievable" - not simply an "opportunity." Commenters 

stated that unless a heat rate improvement has been demonstrated, it cannot be part of the BSER. 
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Commenters stated that the 6% heat rate improvement is not generally achievable. Commenters 

stated that steam generating units should be evaluated on a plant by plant basis for possible heat 

rate improvements.

Commenters stated that EPRI expressed the following concerns relating to the Proposed Rule in 

their comments to EPA filed on October 20, 2014: 

"Estimates of heat rate improvements at existing coal EGUs are very dependent on 

individual unit characteristics (age, design, maintenance history, type of coal, etc.) and 

are difficult to apply a national fleet-wide heat rate goal. In estimating mitigation

potentials, EPRI recommends that the estimates should be based on current studies and 

data that take into account recent EPA environmental control regulations. Regional or 

state-specific research and data should be used as the basis for estimating potential heat 

rate improvements rather than use of a national average for all. States differ widely in the 

characteristics and operating performances of their respective generating fleets. While 

EPRI studies indicate there may be opportunities to achieve a variety of heat rate 

improvements at an EGU in the range of 0.5% - 5% on a net generation basis, these 

values may not be additive and their applicability and realized savings are highly 

dependent on the characteristics of an individual unit."

Increased penetration of renewable power and greater use of natural gas combined-cycle 

(NGCC) units, as called for in the proposed rule, will lead to potential heat rate increases in coal 

units associated with lower utilization of these units, and the need for these units to engage more 

often in flexible operations (e.g., load following, extended low output generation, cycling), rather 

than "baseload" operations. In addition, there are potential wastewater-related impacts that 

should be recognized as flue gas desulfurization (FGD) wastewater treatment may be negatively 

impacted with large swings in FGD water chemistry resulting from increasing flexible 

operations. EPA's use of gross heat rate data for estimating heat rate improvement-related carbon 

dioxide (CO2) mitigation for building block 1 is inconsistent with the use of the net emission 

accounting used in the state goals computation. This leads to inconsistencies, confusion, and 

possible overestimation of the heat rate improvement-related mitigation potential. EPRI 

recommends that EPA use a consistent approach for net heat rate estimation and accounting 

through the proposed rule."

Commenters stated that EPA requested comment on all aspects of their analyses and findings 

related to heat rate improvements. Commenters stated that after numerous consultations with 

stakeholders, including the KCC and utility representatives, they concluded that EPA's assumed 

6% heat rate improvement as applied to all coal-fired power plants in EPA's proposed building 

block 1 is not achievable across the entire fleet of affected units in Kansas. Commenters 

requested that EPA consider the following and adjust building block 1 in the goal computation 

procedure accordingly:

• An EGU's heat rate is not constant. Heat rate varies with such parameters as 

process design, equipment design, maintenance, cleanliness, weather conditions, 

fuel energy content, fuel delivery, process water temperatures, and cooling water 

temperatures.
153

• Heat rate improvements are not uniform or universal. What works for one EGU 

may not work for another.

• Heat rate improvement projects are limited for new and well-maintained units. 

Some units have been proactively engaged in heat rate improvement efforts, 

including implementation of best practices, yet they receive no credit for these 

efforts prior to 2012 according to EPA's Clean Power Plan. For these units, it will 

not be economically or technically feasible to achieve an additional 6% 

improvement.

• Heat rate improvement projects are not permanent. Performance deteriorates over 

time due to age and operation of the unit.

• New Source Review (NSR) rules discourage utilities from larger, more 

significant, efficiency improvement projects. A major impediment to the type of 

boiler or turbine upgrade projects that could achieve significant heat rate 

improvements is the fact that they would likely trigger a Best Available Control 

Technology (BACT) review as part of a Prevention of Significant Deterioration 

(PSD) permit process. If a plant were not yet equipped with a Selective Catalytic 

Reduction (SCR) unit to control NOx, a heat rate improvement project that might 

cost $5 million could tum into an SCR project for NOx reductions with a price tag 

of $100 million. Smaller scale heat rate improvement projects that would not 

trigger a BACT review would not be able to achieve the 6% goal contained in this 

building block.

• Heat rate improvements made at coal-fired EGUs will be offset by dispatch 

changes implemented pursuant to building block 3, re-dispatch of electricity 

production to new renewable resources. EPA's proposal is aimed at reducing 

utilization of fossil-fuel fired EGUs, particularly coal-fired units. Increased redispatch to renewable energy providers, inherently variable resources, will result 

in coal-fired units cycling up and down and running at minimum loads for which 

they were not designed. This will have an adverse effect on heat rate. 

Commenters stated that an improvement in heat rate is a good policy and should be encouraged 

in all types of energy production, however, EPA's analysis to reach 6% heat rate improvement is 

flawed. Commenters stated that as shown in this submittal, the addition of air pollution control 

equipment, capacity factors, and changes in fuel have a significant impact on changes in heat rate 

and EPA should have considered these components of heat rate in their analysis. Commenters 

stated that in addition, EPA should not have used the S&L report on heat rate without making 

adjustments or changes. 

Commenters stated that it is not technically feasible to reduce heat rate 6 percent on their coal 

burning units. Commenters stated that EPA's assumption that utilities can increase efficiency by 

4% by utilizing best management practices ignores the utility industry's current practices and 

incentives to optimize heat rate. Commenters stated that for example, it has been their business 

practice to maintain and/or reduce heat rates over the life of the operating units and they use their

extensive experience and knowledge base, as well as testing, to schedule and perform 
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maintenance activities. Commenters stated that these activities restore equipment efficiency 

and/or improve equipment efficiency while balancing customer costs and reliability. 

Commenters stated that as routine maintenance occurs, efficiency is restored or increased, and 

the amount of degradation in heat rate is minimized. Commenters stated that in addition, EPA's 

assumption that an additional 2% in efficiency gains can be obtained through equipment 

upgrades also is incorrect. Commenters stated that they have seized the opportunities to increase 

efficiency on major equipment when economics have dictated, particularly in response to 

increased parasitic load from environmental controls installed in the recent past. 

Commenters stated that numerous uncontrollable factors impact the efficiency of a coal-fired 

facility and load variability is one significant factor. Commenters stated that additionally, other 

factors lead to unit degradation and make heat rate improvements difficult to sustain over the 

long term. Commenters stated that EPA has not considered the impact of these factors in its 

suggestion that a further heat rate improvement of 6 percent is achievable, and the commenters

further stated that even if a coal-fired unit's efficiency were improved, Building Block 2 lowers 

its dispatch, thereby diluting the efficiency improvements. Commenters stated that furthermore, 

if their coal-fired units are retired before 2018 as per EPA's Option 1, the capital investment 

associated with such improvements would become stranded investment. 

Commenters stated that one Iowa EGU owner/operator began a program of efficiency and 

emission control improvements at a coal generation plant in 2012, and the work is still in 

progress. Commenters stated that once these improvements are completed, the utility thinks that 

total heat rate improvement at full load could possibly achieve 6% compared to a 2011 reference 

point, including an offset for the impact of new emission control systems. Commenters stated 

that however, realistically, the utility expects an achievable average improvement to be 3-5%. 

Commenters stated that the utility has said that additional efficiency improvement at that plant is 

not achievable because it will have already implemented all currently identified opportunities to 

significantly improve heat rate. Commenters stated that additionally, the utility expects the plant 

improvements to degrade over time, which will require additional future investment just to 

restore the heat rate to near design conditions. 

Commenters stated that EPA fails to adequately justify or disclose its assumptions for each of the 

four building blocks used to establish BSER. Commenters stated that in building block one, EPA 

makes a blanket assumption that all coal-fired EGUs are capable of achieving a six percent heat 

rate improvement and in doing so, EPA ignores the real-world conditions faced by coal-fired 

EGUs. Commenters stated that most coal-fired units in the U.S. already undergo regular 

maintenance and upgrades to improve efficiency as part of good business practices. Commenters 

stated that improving heat rates makes units more competitive from a cost perspective and thus 

unit owners regularly evaluate and have already implemented opportunities to improve 

efficiency and performance. Commenters stated that to assume that all coal units could improve 

their performance by six percent ignores the fact that many units have already completed all 

economically feasible unit upgrades and improvements. 

Commenters stated that even if permissible, it is not at all clear that it is feasible for states to 

meet the proposed required emissions reductions. Commenters stated that under building block 

one, EPA posits that a 6 percent improvement in heat rate is possible with 4 percent coming from 

adopting operating and maintenance best practices. Commenters stated that EPA presumes that 
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plant operators do not already run and maintain their facilities according to best practices so as to 

minimize unit power production costs. Commenters stated that that seems illogical and unlikely. 

Commenters stated that in all likelihood, projects improving operating efficiency have already 

been completed since the power industry has economic incentives to operate units at peak 

efficiency. 

Comment 4: Comments asserting that, with respect to the supplemental proposal for affected 

power plants in Indian Country and U.S. territories, a 6% HRI is not feasible, sustainable, or 

adequately demonstrated.

Response 4: See section V.C. of the final rule preamble of the CPP and Chapter 2 of the GHG 

Mitigation Measures TSD supporting the final CPP for EPA’s response to this comment. As 

described in these documents, the EPA’s assessment of average potential heat rate improvement 

is based on an analysis of historical performance—i.e., what actual existing coal-fired EGUs 

have previously achieved—and has been lowered since the proposal. This backward-looking 

assessment provides a conservative estimate of the potential heat rate improvement (and 

accompanying reductions in CO2 emission rates) that affected EGUs can achieve on an average 

basis, as described in section V.C of the preamble and Chapter 2 of the GHG Mitigation 

Measures TSD. The precise amount of heat rate improvement feasible at individual EGUs will 

vary.

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

Commenters stated that because many factors impact the heat rate of a coal-fired power plant 

and because owners are already motivated to improve heat rate, determining how much more can 

be done is a very challenging question, and the Navajo Nation appreciates the effort that EPA 

has made in trying to answer this question. Commenters stated that improvement possible for 

any given facility will vary somewhat based upon the characteristics of the facility, its fuel, and 

how it is operated and in fact, comments by the Electric Power Research Institute ("EPRI") 

stated that: "While EPRI studies indicate there may be opportunities to achieve a variety of heat 

rate improvements at an EGU in the range of 0.5%-5% on a net generation basis, these values 

may not be additive and their applicability and realized savings are highly dependent on the 

characteristics of an individual unit." Commenters stated that in other words, the heat rate 

improvement possible at any particular facility needs to consider that facility's circumstances and 

because larger, base-loaded units tend to have the lowest heat rates and smaller, low capacity 

factor units tend to have the highest heat rates, one would expect the average potential for heatrate improvement over the entire coal fleet is likely to be near the lower end of the 0.5%-5% 

range indicated by EPRI and would on average likely be about 2% or less

Commenters stated that a 6 percent improvement in heat rate is not achievable at Navajo

Generating Station (NGS) or Four Corners Power Plant (FCPP). Commenters stated that EPA 

has received numerous and detailed comments to the June Proposal relating to the problems 

associated with EPA's use of this extremely high value in adjusting the emission rate goal under 

building block 1. Commenters encouraged EPA to establish a lower heat rate improvement 
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requirement for building block 1 taking into consideration unit-specific factors at NGS and 

FCPP.

Commenters stated that the Navajo Nation does not believe that the 6% heat rate reductions are 

feasible. Commenters stated that there may be improvements possible at NGS and FCPP, 

however, this is a site-specific matter and the Navajo Nation will defer to the plant operators to 

determine how much of an improvement is possible. 

Commenters stated that based on information from their wholesale power supplier, EPA's 

suggestion that power plant heat rates, or efficiency, can be increased by 6 percent is unrealistic 

and cannot be achieved in Colorado. Commenters stated that all utilities, including electric coops, are motivated to run their plants as efficiently as possible, and the Plan does not account for 

the measures that have already been implemented at existing coal plants to improve heat rates 

and maximize operational efficiency. Commenters stated that since the purported benefits of this 

building block are illusory, the overall emission reduction goal should be reevaluated to account 

for a realistic expectation of power plant efficiency for Colorado's coal generation resources. 

Commenters stated that EPA's goal of a 6 percent heat-rate (the amount of power used to 

generate electricity) improvement at coal plants by 2020 is unrealistic since power plants already 

have an incentive to operate as efficiently as possible. Commenters stated that as explained by 

NERC: The "assumed improvements may not be realized across the entire generation fleet since 

many plant efficiencies have already been realized and economic heat rate improvements have 

been achieved," NERC further stated: "Multiple incentives are in place to operate units at peak 

efficiency, and periodic turbine overhauls are already a best practice. Site-specific engineering 

analysis would be required to determine any remaining opportunities for economic heat rate 

improvement measures." Commenters stated that under EPA's "best" system, coal generation in 

general would decline dramatically and indeed would be zeroed out in 12 states. Commenters 

stated that according to NERC, assumptions about energy efficiency could also prove perilous 

for the EPA's plan since poor estimates in this case could mean that more coal-fired power plants 

would have to be retired to make up for the lag in energy efficiency gains. Commenters stated 

that indeed, the EPA analysis has not incorporated the effect of retrofits to existing plants made 

due to the EPA's MATS rule, which have made existing plants less efficient by increasing their 

parasite load. Commenters stated that they further characterize the EPA's approach to Block 1 as 

being "arbitrary".

Comment 5: Comments stating that the alternative 10% heat rate is infeasible

Response 5: EPA is not finalizing a building block 1 figure of 10% heat rate improvement. See 

section V.C. of the final rule preamble of the CPP and Chapter 2 of the GHG Mitigation 

Measures TSD supporting the final CPP for an explanation of our methodology.

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

Commenters stated that EPA should not use the alternative 10% heat rate improvement as BSER 

under Building Block 1. Commenters stated that a 6% heat rate improvement as BSER is an 

overestimation of what is feasible for many EGUs; therefore, the alternative suggestion of 10% 
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is even more infeasible and the costs associated with the assumptions for this higher rate make 

this unreasonable and likely technically impossible for New Mexico's facilities. 

Comment 6: Comments stating that 6% cannot be achieved and that CO2 emissions reductions 

must be met through other means.

Response 6: See section V.C of the final rule preamble of the CPP and Chapter 2 of the GHG 

Mitigation Measures TSD supporting the final CPP for EPA’s response to this comment.

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

Commenters stated that EPA's proposed CPP fails to consider what will occur if the heat rate 

improvements provided for in Building Block 1 are not achieved. Commenters stated 

presumably these CO2 emissions reductions must be met through other means and operation of 

some coal-fired units will be further curtailed or even retired earlier than otherwise anticipated in 

order to achieve the CPP's CO2 emissions goals.

Comment 7: Comments stating that 6% HRI is achievable or can be increased.

Response 7: For the reasons discussed in section V.C of the preamble of the CPP and in Chapter 

2 of the GHG Mitigation Measures TSD supporting the final CPP, the EPA has identified a 

conservative estimate of the quantity of heat rate improvement achievable by affected coal-fired 

EGUs. The EPA agrees that building block 1 does not account for all heat rate improvement 

measures that are technically achievable at each and every affected coal-fired EGU.

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

Commenters stated that greater reductions than those proposed by the EPA are possible through 

the application of the best system of emission reduction. Commenters noted that for example, the 

use of the target of eight to ten percent heat rate improvements for the existing fleet is supported 

by the existing literature and the low cost per ton of carbon dioxide.

Commenters stated that EPA's Building Block 1 analysis omits considerable opportunities for 

additional reductions through the employment of overly conservative discount factors when 

evaluating opportunities for improvements through use of best practices and equipment

upgrades. Commenters stated that efficiency improvements are readily available and have been 

documented in numerous studies by Sargent and Lundy, the National Energy Technology 

Laboratories, Resources for the Future, DOE and others. Commenters stated that EPA's target of 

a six percent reduction in average heat rate can be exceeded. Commenters stated the NETL 

analysis determined that a ten percent improvement in fleet-wide efficiency is a "reasonable 

average efficiency target" based on "a combination of aggressive refurbishment and improved 

operation maintenance." based on NETL's consultations with industry experts validated this 

conclusion, identifying over 50 opportunities to improve thermal efficiency and finding that 

"there is headroom for efficiency improvements among all plants including those that currently 
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operate at below average, average, and above average efficiency levels." Commenters stated that, 

in addition, consultations also identified multiple institutional, regulatory, and market barriers 

that help explain why many coal-fired EGUs have failed to implement all cost-effective options 

for improving efficiency. Commenters stated that EPA's own analysis takes a far more 

conservative approach to quantifying the average efficiency improvement that can reasonably be 

achieved by assuming that power plants can reduce only 30% of the difference between their 

own hourly heat rate and the heat rate of the top 10% of comparable power plants, resulting in 

substantially lower heat rate improvements than NETL's own analysis, which concluded that 

existing coal-fired power plants could achieve or exceed the performance of the top 10% of their 

peers through upgrades or operational improvements. Commenters stated that EPA's approach 

leaves potentially cost effective emissions reduction opportunities on the table. Commenters 

referred to NETL's alternative analysis in which it assumed that each existing coal-fired EGU 

simply returned to its own best level of performance over the period from 1998 to 2008 - without 

considering any potential for refurbishments or equipment upgrades. Commenters stated that 

even this narrower assessment resulted in an average fleet-wide improvement in efficiency of 

over six percent, more than fifty percent higher than the level EPA proposes for operational 

improvements under Building Block 1, whereas EPA's projected four percent improvement in 

heat rate from best operating practices is equivalent to requiring only that each existing coal-fired 

power plant return to its best three-year average performance during the period from 2002 to 

2012.

Commenters supported the 6% emission reductions for coal-fired power plants now included in 

Block 1 of the Proposed Rule. Commenters urged EPA to sharply increase this target, which 

EPA itself describes as "conservative" because the agency has not adequately accounted for heat 

rate improvements from operational and maintenance measures as well as from plant upgrades 

that are adequately demonstrated. Commenters stated that the agency has determined that 

implementation of all operational and maintenance best practices ("O&M") together with 

equipment upgrades identified in a 2009 study by the engineering firm Sargent & Lundy, can 

provide total heat rate improvements at coal-fired power plants of up to 12%. Commenters stated 

that these best practices and equipment upgrades include common-sense measures such as 

turning off unneeded pumps at reduced loads, installation of digital control systems, more 

frequent tuning of existing control systems, and earlier like-kind replacement of worn 

components. Commenters stated that EPA also determined a high and sustained correlation 

between the implementation of equipment upgrades and actual heat rate performance data, yet, 

EPA requires no more than a 6% improvement for coal-fired power plants in Block 

1. Commenters stated that while it is understood that not all O&M best practices and equipment 

upgrades can be implemented at every plant, EPA's halving of the achievable emissions target is 

not justified or sufficiently explained. Commenters stated that requiring efficiency improvements 

through best maintenance practices and equipment replacements and upgrades at established 

intervals, rather than relying on spotty, infrequent and voluntary implementation of such 

practices, yields consistent and sustained results and is cost effective, and EPA should include 

each of these measures in BSER.

Commenters stated that specifically, they incorporated the Sierra Club's comments concerning 

the appropriate BSER target for heat rate improvements to power plants. Commenters stated that 

those comments demonstrate that a 6% heat rate improvement is adequately demonstrated based 

on better O&M practices alone and further, the Sierra Club comments show that plant upgrades 
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can reduce emission rates by an additional 4%.Commenters stated that these comments support 

and amplify the result of the Sargent & Lundy study and provide robust support for a 10% 

emission reduction target based on best O&M practices and equipment upgrades 

alone. Commenters stated that many of the units in the existing fleet of coal-fired plants will 

continue to be used during the rulemaking period, and EPA must ensure that they are used in the 

most efficient and least-polluting manner possible. 

Commenters stated that EPA should encourage states to require individual EGUs to improve 

their heat rates beyond the 6%. Commenters stated that EPA indicates that individual EGUs, on 

average, could achieve total heat rate improvements of 10% at a reasonable cost, a 6% rate 

improvement attributable to adoption of best practices for operation and maintenance, and a 4% 

rate improvement attributable to equipment upgrades. Commenters recommended that EPA 

modify Building Block l by increasing to 10%, the average amount of heat rate -improvements 

that should be achievable by individual EGUs.

Commenters stated that EPA's analysis of the potential for heat rate improvements from 

equipment upgrades is also highly conservative only including one half of the opportunity 

identified for equipment upgrades - reducing the potential improvement in heat rate from an 

average of 4 percent to just 2 percent. Commenters further stated that in addition, EPA's 

assessment of equipment upgrades examined only the four most cost-effective types of 

equipment upgrades identified in the 2009 Sargent and Lundy report whereas, NETL's own 

technical workshops with industry experts identified over 50 different heat rate improvement 

measures which would afford opportunities for greater efficiency not captured in EPA's analysis.

Commenters stated that EPA should encourage states to require individual EGUs to improve 

their heat rates beyond the 6%. Commenters stated that EPA indicates that individual EGUs, on 

average, could achieve total heat rate improvements of 10% at a reasonable cost, a 6% rate 

improvement attributable to adoption of best practices for operation and maintenance, and a 4% 

rate improvement attributable to equipment upgrades. Commenters stated that as such, they

recommend that EPA modify Building Block 1 by increasing to 10%, the average amount of heat 

rate improvements that should be achievable by individual EGUs. 

Commenters concluded that the 6 percent heat rate improvement targeted by Building Block One 

is both reasonable and achievable on a fleet-wide basis, and may even extend the economic 

useful life of aging coal-fired EGUs. Commenters further stated that although independent 

experts have concluded that the EPA's goal is technically feasible, the proposal does not mandate 

that every state or every coal-fired EGU engage the 6 percent HRI as a compliance strategy. 

Commenters stated that indeed, the flexibility afforded by the proposal allows the states to forgo 

this building block altogether; should a state elect HRI as a compliance strategy, the proposal 

expressly anticipates fleet-wide averaging, thereby facilitating greater opportunities at a lower 

cost compared to the treatment of plants on an individual basis.

Commenters stated that the 6% HRI being perceived as presenting a near-term challenge is 

incorrect due to 1) unit retirements resulting in significant emission reductions during the 111(d) 

compliance timeframe, 2) investments in aging units as part of state emission reductions will also 

serve to increase the lifespan of these units, and 3) flexibility afforded to states by the CPP 

provides an opportunity to demonstrate compliance through any number of pathways, which may 
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not even include an HRI investment strategy. Commenters stated that they stress that flexibility 

for purposes of compliance is a welcomed opportunity, but that accountability should not give 

way to flexibility for purposes of state goal computations. Commenters stated that the 6% HRI 

assumption should be retained in the final CPP.

Commenters stated that EPA's proposed targets can and should be strengthened. Commenters 

stated that pollution reductions could be greater at a reasonable cost in both the near term and the 

long term and that it is important to note, though, that the amount of reductions identified as 

feasible for each block does not indicate the amount that block should or will be relied on for a 

state, meaning for a state to meet its target. Commenters stated that each block is simply an 

inventory of the available tools to cut power sector carbon pollution and when EPA admits or 

underestimates the potential contribution of a block, it's underestimating the amount of pollution 

cleanup that's feasible in a state when a state has significant flexibility in terms of the tools it 

uses to achieve the standard. Commenters stated that in terms of block one, coal plant 

efficiency, this block is currently limited to coal plant efficiency improvements of 6 percent, but 

it ignores capital projects such as turbine wind replacements or co-firing of other fuels. 

Commenters stated that they are in the process of reviewing EPA's analysis to determine whether 

higher levels of efficiency and other operational changes at power plants should have been 

included.

Commenters believed that based on their assessment of the current fleet, and with currently 

available technologies and products (including those reasonably anticipated):

• Commenters stated that a 6% gross heat rate improvement on average across the 

fleet is technically possible, if costs are not a limitation and the impact of other 

potentially lower cost dispatchable sources is ignored;

• Commenters stated that a 4%-5% gross heat rate improvement on average is 

economically possible, when costs are taken into account, however, the actual 

potential may be less as they do not know how many of these improvements may 

already have been implemented by owners and the availability of potentially 

lower cost dispatchable sources may also limit these opportunities; and

• Commenters stated that a 1% gross heat rate improvement on average is the likely 

potential, with some units electing to undertake significant improvements but 

most units electing to implement minimal, if any, upgrades. Commenters stated 

that undertaking HRI projects requires the investment of capital that plant owners 

must be able to recover with a return and this recovery becomes difficult if the 

remaining lives of the coal plants could be reduced by regulatory requirements 

under any Section 111(d) final rule or if the generation from the coal plants 

declines, thereby reducing the revenue available to pay for the capital investment.

Commenters believed greater overall carbon emission reductions can be achieved through the 

permanent retirement of Texas's oldest and dirtiest facilities. Commenters stated that this does 

not obviate the EPA's obligation to re-evaluate and accurately calculate the heat rate 

improvements achievable under building block 1 at all remaining Texas coal plants. Commenters 

stated that based on its review of the CPP assumptions and the data upon which the EPA relied, 
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they are confident that Texas can achieve at least an average 6% heat rate improvement across its 

coal-fired EGU fleet. Commenters stated that while the EPA's estimate is supported by numerous 

studies, the Agency has acknowledged that its estimated 6% heat rate improvement is a 

conservative one. Commenters urged the EPA to further evaluate and incorporate the industry 

studies attached to these comments to catalog the types of heat rate improvements that are 

achievable at coal plants in Texas and across the country, and to rebut industry assertions that 

only minimal improvements are possible. Commenters stated that indeed, as these studies 

indicate, the EPA excluded from its projection some of the most effective techniques for 

improving heat rate efficiency, such as turbine blade replacements. Commenters stated that in 

any event, a cursory review of the current heat rates at existing coal-burning power plants 

suggests that Texas coal plants can achieve a 6% heat rate improvement as averaged across the 

fleet. Commenters provided a table with Existing Coal Plant Heat Rate Data and as the table 

indicates, Texas's coal-burning power plants vary in their heat rates, from 9.77 MMBtu/MWh at 

JK Spruce's relatively new units to 11.69 MMBtu/MWh at the early 1970s vintage Monticello 

units. Commenters stated that many of those aging 1970s plants, however, can almost certainly 

improve their heat rates. Commenters stated that a 6% improvement for Monticello, for example, 

would require a resulting heat rate of 10.99 MMBtu/MWh - well within the range of units of 

similar vintage in Texas. Commenters stated that given the disparities between heat rate 

efficiencies above, Texas EGUs can almost certainly achieve at least a 6% heat rate 

improvement (and likely better) as averaged across the state's coal-fired fleet. Commenters stated 

that in fact, Texas EGUs can likely do better. Commenters noted that the EPA selected only four 

specific technologies on which to base the Block 1 heat-rate improvements: economizer 

replacements, acid dew point controls, variable frequency drives for use with fans, and turbine 

blade overhauls. Commenters stated that as demonstrated in the technical literature attached, 

however, there are numerous additional upgrades that the EPA excluded, including condenser 

cleaning, intelligent soot blowers, electrostatic precipitator modifications, boiler feed pump 

rebuilds, air heater and duct leakage controls, neural networks, modifications of criteria pollutant 

control systems (selective catalytic reduction equipment and flue-gas desulfurization 

configurations), and advanced packing at cooling towers. Commenters stated that the EPA 

should re-examine and incorporate these potential upgrades into the rule. 

Commenters stated that the EPA appropriately considered the potential for increased efficiencies 

at existing coal-fired power plants and conservatively determined that coal-fired power plants 

can reduce their emissions by at least 6% through efficiency improvements. Commenters stated 

that while they strongly believe that investments in energy efficiency and renewable energy 

programs are the best ways to comply with EPA's emission reduction guidelines, and will urge 

Pennsylvania to pursue these routes, they also recognize that transitioning from coal to natural 

gas is a compliance pathway that will be pursued. Commenters stated that moreover, they

recognize that such a transition will result in significant reductions in combustion emissions of 

carbon dioxide as well as in dangerous co-pollutants from coal combustion such as mercury, 

NOx, SOx, and particulates.

Commenters stated that EPA should encourage states to require individual EGUs to improve 

their heat rates beyond the 6 percent. Commenters stated that EPA indicates that individual 

EGUs, on average, could achieve total heat rate improvements of 10 percent at a reasonable cost, 

a 6 percent rate improvement attributable to adoption of best practices for operation and 

maintenance, and a 4 percent rate improvement attributable to equipment upgrades and as such, 
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they recommend that EPA modify Building Block 1 by increasing to 10 percent, the average 

amount of heat rate improvements that should be achievable by individual EGUs.

Commenters stated that the Proposal essentially requires that any coal plants that will continue 

operating must optimize their operating practices to meet the highest standards of performance 

currently achieved. Commenters stated that this is a quite reasonable way to accomplish carbon 

emission reduction and should be pursued. Commenters stated that it would be reasonable to 

assure states and coal plant owners that, if the most stringent improvement considered (six 

percent) is adopted, no further improvements in plant performance will be mandated before 

2030. Commenters stated that this would quite certainly not be enough to eliminate the political 

objections from states with substantial coal production and use. Commenters stated that it is a 

good start. 

Commenters recommended that EPA modify Building Block 1 by increasing to 10%, the average 

amount of heat rate improvements that should be achievable by individual EGUs.

Commenters stated that based on their analyses of heat rate performance opportunities at their 

existing EGUs, they estimated that it may be possible to achieve an additional 1-2 percent heat 

rate improvement on their existing plants, but this improvement will come at significant cost.

Commenters supported the 6 percent coal fleet heat rate improvement assumption and 

recommend that it be maintained. 

Commenters stated that all the goals that EPA is looking for are very achievable. Commenters 

believed they can be even better. 

Commenters believed that greater reductions than those proposed by the EPA are possible 

through the application of the best system of emission reduction - for example, the use of the 

target of eight to ten percent heat rate improvements for the existing fleet is supported by the 

existing literature and the low cost per ton of carbon dioxide.

Commenters stated that while EPA data shows that the 6% improvement rate is a moderate 

assumption compared to reductions that have already been demonstrated, a few other 

commenters argued that certain facilities have already adopted such measures and cannot achieve 

additional reductions. Commenters stated that Pennsylvania's Department of Environmental 

Protection (DEP) has made a similar argument in regard to its waste coal plants that have high 

carbon emissions but provide some environmental benefits by helping to remove waste piles that 

have been leaching pollutants into the surrounding land and water for decades.

Commenters stated that for the purposes of EPA's rule, it is necessary to show that the target is 

achievable through the best system of emission reductions and independent calculations 

performed by PennFuture and those provided by Synapse's Clean Power Plan Planning Tool 

confirm that the proposed system provides enough flexibility for Pennsylvania to meet the 

proposed target without achieving a 6 percent reduction at every affected facility. Commenters 

stated that for this reason, even if some individual plants cannot meet a building block's goal, 

that is not sufficient justification for EPA to reduce overall targets and urged EPA to retain this 

goal. 
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Commenters stated that EPA assumes that coal plants can improve their heat rate efficiency by 

6% on average through onsite upgrades, maintenance, and operational modifications. 

Commenters supported this averaging approach because it will encourage states to maximize 

efficiencies from each facility to meet the state-wide average. 

Commenters stated that they strongly support a reduction of emissions from dirtier coal plants 

through building blocks 1 and 2 and that this will reduce carbon emissions while at the same 

time delivering important co-benefits including the reduction of sulfur, mercury, and nitrogen 

pollution. Commenters stated that the range of CO2 reduction rates across all 50 states is 0 -

38%. Commenters stated that EPA's initial proposal appropriately encourages re-dispatch from 

coal to existing natural gas combined cycled (NGCC) units which is a phenomenon already 

occurring due to market forces.

Commenters stated that when setting state targets, the rule should account for the lowest 

emission rate actually achieved by coal-fired power plants over the past decade. Commenters 

stated that EPA's proposal identifies opportunities for improvements that can be made based on 

specific power plant upgrades and for operational and maintenance changes. Commenters stated 

that EPA determined that coal-fired power plants could achieve at least a six percent 

improvement in performance. Commenters stated that this is a conservative estimate. 

Commenters stated that analysis of carbon emissions at coal plants shows that even greater 

reductions would be available if power plants simply had to match the lowest emission rate 

actually achieved by the plant over the past decade. 

Commenters stated that the draft rule's Building Block 1 (upgrading plants to increase their 

efficiency) is based on EPA's estimate that existing plants can see efficiency improvements of 6 

percent. Commenters stated that they believe upgrades to plants can achieve average heat rate 

efficiencies greater than 6 percent. 

Commenters stated that one of the ways to reduce emissions as part of EPA's proposed Clean 

Power Plan is to improve the operation of coal-fired power plants. Commenters stated that EPA 

finds that the heat rate - the heat content of fuel input per unit of electricity output - at existing 

plants can be reduced by 6 percent on average across the fleet which would correspond to an 

equivalent reduction in emissions rate. Commenters asked if this goal is attainable.

Commenters stated that empirical evidence from research at RFF suggests the following:

1. EPA's goal is technically plausible.

2. The costs could be low, at least for modest heat rate improvements of 1 to 2 percent.

3. The cost of a 6 percent improvement in heat rate (while holding utilization constant) 

could be significant at many plants.

4. However, the opportunity to co-fire with biomass at coal plants could double the 

reduction in the emissions rate (which is closely related to heat rate) for coal plants at the 

same marginal cost.
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5. The flexibility of this proposal to average across plants and to shift generation to more 

efficient plants means that greater opportunities may be available at lower cost, compared 

to when plants are examined on an individual basis.

Commenters stated that they examined data on the performance of coal plants in 2008, sorting 

plants by boiler type and other characteristics and the results indicate that the average heat rate 

would be reduced by 5.5 percent - without changing the utilization of individual plants - if each 

plant improved to match the operating performance of the best 10 percent in its group. 

Commenters stated that this indicates that EPA's goal is technically plausible.

Commenters stated that in its technical documents, EPA examines the operation of plants over 

many years and finds substantial variation in heat rate at individual plants on an hourly basis. 

Commenters stated that this suggests that improvements are possible if that variation could be 

reduced. Commenters stated that EPA suggests that 4 percent improvement could be achieved on 

average through changes in maintenance and operation at individual plants at low cost or no cost, 

and another 2 percent could be achieved through capital investments at individual plants.

Commenters stated that they examined 25 years of operation of coal plants to see how their heat 

rates responded to changes in relative fuel prices while holding constant the utilization of the 

plants. Commenters stated that findings support EPA's claim that costs are low, at least for 

modest heat rate improvements of 1 to 2 percent. Commenters stated that larger changes are 

outside the range of variation observed very frequently, and it is difficult to extrapolate, but 

clearly the marginal costs would increase with increasingly stringent improvements.

Commenters stated that if poor heat rates waste fuel, why would such opportunities for heat rate 

improvements exist across the fleet. Commenters stated that there are multiple possible 

explanations, at least in the short run. Commenters stated that these include automatic fuel 

adjustment clauses in some states that may reduce the incentive to save fuel costs, liquidity 

constraints in some systems that may make it difficult to fund investments, and the so-called new 

source review test - which is the threshold where investments to improve a plant's operation 

could enable its greater utilization and thereby increased emissions of other pollutants. 

Commenters stated that this test could trigger a requirement for tens of millions of dollars in

expenditures to improve controls for other pollutants, a cost that may deter investments to 

improve heat rates.

Commenters stated that nonetheless, opportunities to reduce costs should not go unrealized in the 

long run. Commenters stated that while the results from Linn et al. suggest the cost of a 6 percent 

improvement in heat rate (while holding utilization constant) could be significant at many plants, 

a central characteristic of the Clean Power Plan is that stringency is built on EPA's findings of 

what is technically possible. Commenters stated that EPA does not require specific measures to 

be taken, that is, a heat improvement of 6 percent on average in the operation of the coal fleet 

does not require a 6 percent improvement at any given plant. Commenters stated that one way 

this is relevant is that large capital investments, which EPA suggests could lead to a 2 percent 

improvement in heat rate on average across the fleet, may result in improvements of 10 percent 

at an individual plant. Commenters stated that for example, investments such as major overhaul 
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of a plant's turbine are expensive and would only be observed at some plants - but they would 

lead to substantial reductions in heat rate. 

Commenters stated that in conclusion, the evidence suggests EPA's finding that a 6 percent 

reduction in heat rate from 2012 levels is technically plausible and economically reasonable -

given that the agency adopts a flexible approach to achieve compliance. 

Commenters stated that EPA determined that coal-fired power plants can achieve at least a six 

percent improvement in performance. Commenters stated that this is a conservative estimate. 

Commenters stated that analysis of carbon emissions at coal plants shows that even greater 

reductions would be available if power plants simply had to match the lowest emission rate 

actually achieved by the plant over the past decade. 

Commenters stated that EPA's identification of "Best System of Emission Reduction" for the 

coal plants located on the Navajo Nation is inadequate, arbitrary, and capricious. Commenters 

elaborated (verbatim) 1. Building Block 1: EPA must mandate a 6% heat rate improvement at 

each operating unit at Four Corners Power Plant and NGS. Under building block 1 of the CPP, 

EPA has generally assumed that under coal plants can achieve a 6% heat rate improvement. At a 

minimum, EPA should stringently apply this requirement to all operating units at FCPP and 

NGS. Commenters stated EPA should also give full consideration to whether greater heat rate 

improvements can and should be achieved at the plants.

Commenters continued there is ample evidence to support EPA's determination that a six percent 

average improvement in heat rate is feasible, without even considering co-firing with natural gas; 

moreover, the flexible structure of the proposal allows states to average the emissions rates of 

existing fossil fuel-fired EGUs, and comply by using various emission reduction strategies. 

Commenters said this allows for compliance by all units, regardless of the potential variability in 

the opportunity for heat rate improvements. Commenters said the record also demonstrates that 

there are many opportunities for heat-rate improvements at affected facilities beyond the 

particular measures that were the focus of EPA's analysis, and that existing coal-fired power 

plants whose owners believe they cannot achieve the six percent reduction in heat rate could also 

easily meet the anticipated reduction in emissions through modest co-firing with natural gas. 

Commenters concluded that EPA's target for average heat rate improvements is "achievable" 

under section 111.

Commenters stated nearly all stakeholders agree that EPA may include entirely inside-the-fence 

measures in a BSER formula. Commenters said heat rate improvements at individual EGUs, 

which are the basis for Building Block 1, are precisely such measures since they can be 

implemented on-site at each individual unit. Commenters added the HRI that EPA has proposed 

for Block 1 meet the legal standards for a BSER determination under section 111. Commenters 

said these measures are achievable and adequately demonstrated. Commenters said EPA expects 

units to achieve the HRI under Block 1 through two well-demonstrated techniques: enhanced

operation and maintenance practices and a number of specific equipment upgrades that have 

been identified in the technical literature and undertaken at plants around the world
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Comment 8: Applicable to the supplemental proposal for Tribal and Territorial - 6% HRI is 

achievable or can be increased

Response 8: For the reasons discussed in section V.C of the preamble of the CPP and in Chapter

2 of the GHG Mitigation Measures TSD supporting the final CPP, the EPA has identified a 

conservative estimate of the quantity of heat rate improvement achievable by affected coal-fired 

EGUs. The EPA agrees that building block 1 does not account for all heat rate improvement 

measures that are achievable for all affected EGUs.

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

Commenters stated that excessive carbon dioxide emissions compromise the health and wellbeing of tribal members and the Proposed Rule represents a great first step toward regulating 

CO2 emissions from each electricity generating unit (EGU) in Indian Country. Commenters 

stated that however, the Tribe is disappointed with the Proposed Rule's permissible level for 

emission of carbon dioxide for the Bonanza Plant and believe that performance goals established 

for the Bonanza Plant should be more stringent. Commenters stated that stricter compliance and 

enforcement mechanisms are necessary to account for Deseret Power's history non-compliance 

with existing pollution controls.

Commenters stated that another improvement would be the reduction in the carbon intensity of 

the Bonanza Power Plant that is greater than 6% as is currently proposed. Commenters stated 

that in the June 18, 2014 Proposed Rule, EPA indicated that individual EGUs, on average, could 

achieve total heat rate improvements of 10% at a reasonable cost, a 6% rate improvement 

attributable to adoption of best practices for operation and maintenance, and a 4% rate 

improvement attributable to equipment upgrades. Commenters stated that the Bonanza Power 

Plant has been given a free pass far too often and requiring higher rate improvements would 

remarkably reduce emissions on the Reservation while also creating more than nominal GHG 

reductions.

Commenters stated that BB1 suggests reducing the carbon intensity of generation at individual 

EGU's though heat rate improvements on the average of 6%. Commenters stated that they

strongly support this building block, and encourage the EPA to propose even greater reductions 

of carbon emissions through this venue. Commenters believed that greater requirements will help 

spur technological developments and economic investments that look ahead to the future of 

energy production. Commenters stated that reduction of CO2 emissions will also lead to the 

reduction of co-pollutants, many of which are also a concern to their members (i.e. SO2, NOx, 

PM, and mercury). Commenters stated that they feel that a heat rate improvement rate of 10% 

(average) from individual EGU's would be more desirable than the 6% that is proposed, with 6% 

coming from adoption of best practices for operation and maintenance, and an additional 4% 

possible due to equipment upgrades. 

Comment 9: Comments regarding alternative approaches to determining the HRI component of 

the BSER.
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Response 9: See section V.C of the final rule preamble of the CPP and Chapter 2 of the GHG 

Mitigation Measures TSD supporting the final CPP for the EPA’s response to these comments. 

The EPA appreciates commenters’ support, suggestions, and constructive criticism. Where 

appropriate, the EPA has refined its methodology accordingly. For the reasons stated in the 

above-referenced portions of the preamble and TSD, the EPA believes that the methodology 

described in the above-referenced portions of the preamble and TSD provides the best method of 

determining the heat rate improvement component of the BSER, and that this methodology is 

based on sufficient information.

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

Commenters stated that the Proposal underestimates emissions reductions achievable through

HRI at Coal-Fired EGUs, and should instead require poorer-performing units to meet emissions 

rates achieved by top-performing units within the industry. Commenters stated there is wide 

variability in carbon emissions rates between coal-fired steam EGUs and as their analysis 

demonstrates, the top performing 20% of units (in terms of carbon emissions) emit about 22% 

less CO2 than the poorest-performing units, and 9% less CO2 than the middle-performing units. 

Commenters stated that by setting state goals based on the CO2 emissions rates achieved by top 

performing units within the industry, EPA could achieve much greater reductions than reflected 

in the current Proposed Rule and if all facilities were required to achieve the rate of CO2 

emissions achieved on average by the best-performing 20% of units, this would achieve an 

average 10.08% improvement in CO2 emission rate across the study population. Commenters

stated that this improvement would reduce carbon emissions by 136 million tons of CO2 per 

year, and comply with the legal mandate of section 111(d), that EPA set state goals which reflect 

the best system of emissions reduction, adequately demonstrated.

Commenters stated that given the wide variability in heat rate performance and carbon emissions 

between units, EPA should calculate potential CO2 emissions rate improvements by comparing 

the poorer-performing facilities in the industry with the best-performing facilities, rather than 

comparing poorer-performing facilities against their own past performance records. Commenters 

stated that EPA requested comment on the use of estimates of up to six percent to represent heat 

rate improvement attributable to implementation of best practices. Commenters stated that based 

on their own analysis of data reported to the Energy Information Administration (EIA) and EPA 

for the years 2009 through 2013, they believed that even a 6% HRI is overly conservative and 

should be revised upward to reflect improvements achievable by the industry as a whole, rather 

than by individual units. 

Commenters stated that if all facilities were required to achieve the rate of CO2 emissions 

achieved on average by the best-performing 20% of units, this would achieve an average 10.08% 

improvement in CO2 emission rate across the study population and this improvement would 

reduce carbon emissions by 136 million tons of CO2 per year. Commenters stated that assuming 

EPA's model predicts CO2 emissions reductions proportional to HRIs, applying EPA's proposed 

reductions to their dataset would yield a reduction of only 95 million tons of CO2 per year. 

Commenters stated this amounts to a full 41 million fewer tons of CO2 emissions than under the

commenters’ proposed approach.
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Commenters stated that significant reductions in carbon emissions, beyond those estimated by 

EPA, could therefore be achieved if the poorer performing units were required to meet the 

emissions rates achieved by the top performing units and these numbers represent what could be 

achieved without anticipating any improvement in the top performing sources. Commenters 

stated that the commenters’ analysis is based on annualized data, and thus does not capture heat 

rate improvements that can be achieved at top performing sources by reducing hourly variability 

and as such, it is reasonable to expect that additional reductions could be achieved.

Commenters stated that this approach finds support in literature reviewed by EPA in its 

rulemaking and specifically, studies by the National Energy Technology Laboratory (NETL) 

suggest that a fleet-wide improvement ranging from 9% to 15% is theoretically possible if the 

bottom performing 90% of EGUs were required to improve their heat rate to meet the average 

performance of the top 10% for each group examined, based on plant efficiency. [GHG 

Abatement Measures at 2-13.] Commenters stated that moreover, these estimates do not take into 

account the retirement of poorer-performing or redundant EGUs within the implementation 

period which would boost the average heat rate achievable by the study population as a whole 

and as such, even if EPA were to set BSER at a level that requires EGUs to meet the level of 

emission reduction currently demonstrated on average by the top 20% of facilities, states would 

still have the flexibility to meet their goals by relying on greater reductions from Building Block 

One if reductions anticipated from other Building Blocks do not come to fruition.

Commenters stated that coal-fired EGUs are capable of meeting the proposed reductions, 

irrespective of immutable characteristics such as capacity factor, boiler type, and age of the 

facility. Commenters stated that the CAA requires EPA to consider emissions reductions that can 

be achieved, technically and in terms of cost, by the industry as a whole rather than at individual 

facilities, and in addition to looking across the industry, EPA may look to technology that can 

"fairly be projected for the regulated future, rather than the state of the art at present." Portland 

Cement Ass'n, 486 F.2d at 391. Commenters stated that each of these characteristics of the 

BSER determination is critical to the technology-forcing purposes of the statue and by assessing 

each EGU based on its own past performance, however, EPA underestimates the emissions 

reductions that could be achieved if poorer-performing EGUs were required to meet the 

emissions rates achieved at better-performing facilities. Commenters stated that moreover, the 

standard presumes there will be no improvement beyond each unit's best demonstrated 

performance within the 2002-2012 study period. Commenters stated that given that these 

standards will be implemented over the next 15 years, it is reasonable to expect both that poorerperforming sources approach the levels of emissions reduction demonstrated by betterperforming sources, and that all sources, including better-performing sources, will improve upon 

their own past performances. Commenters stated that in order to ensure that both forms of 

improvement take place, and to fulfill the technology-forcing purpose of the statute, EPA must 

recognize that HRIs beyond the proposed 4-6% for coal-fired steam EGUs are reasonably 

achievable, and should form the basis of EPA's BSER determination.

Commenters stated that their own analysis confirms that heat rate and carbon emissions vary 

widely across coal-fired steam EGUs operating under similar circumstances. Commenters stated 

that they looked at emissions and generation data from 601 units over the period from 2009-2013 

and found that many of the factors outside of the control of operators that might be expected to 

affect carbon emissions actually play only a marginal role in determining a unit's efficiency. 
169

Commenters stated that they divided units into three groups representing plants operating within 

different ranges with respect to capacity factor - those operating at 30% to 50%, those operating 

at 50% to 70%, and those operating at 70% to 100% and then they broke the same data into five 

groups of 120 units each, based on each unit's CO2 emission rate. Commenters stated that in the 

resulting distribution, Group One represented the best-performing units (those with the lowest 

CO2 emissions rates), and Group Five represented the worst-performing units (those with the 

highest CO2 emissions rates) and a comparison of units based on capacity factor grouping 

reveals that within a given capacity factor range, there are units falling within both the bestperforming, and worst-performing groups with respect to CO2 emissions rate.

Commenters concluded that because reductions achievable through individual Building Blocks 

are non-binding on states, it is critical that state goals, accurately reflect the emissions reductions 

that can reasonably be achieved by coal-fired steam EGUs over the course of the implementation 

period. Commenters stated that setting state goals which are too lenient will undermine the 

forward-looking nature, and technology-forcing purpose of section 111(d) and that EPA's 

estimate that heat rate at affected EGUs can be improved by 4-6% is overly conservative, and 

does not take into account the wide variability of carbon emissions rates among coal-fired EGUs. 

Commenters stated that significant additional reductions could be achieved if coal fired units 

were required to meet carbon emissions rate achieved by best performing sources. Commenters 

stated that in accordance with the definition of "standard of performance" in section 111(a), EPA 

should therefore set state goals that reflect the level of carbon emissions reduction achievable by 

the industry as a whole.

Commenters stated that this demonstrates that heat rate performance is not collinear with 

capacity factor and as such, facilities which operate at a lower capacity factor due to dispatch 

decisions outside of the operator's control are not categorically unable to achieve lower CO2 

emissions rated. Commenters stated that similarly, they compared CO2 emission rates from the 

same population of units with respect to the year in which boilers at those units came on-line. 

Commenters stated that comparing the emissions rate of boilers that came on-line each decade 

between 1950 and 2010, there is no discernible correlation between what year a boiler came 

online and what CO2 emission rate group a unit will fall within.

Commenters stated that this finding demonstrates that older units are just as capable of achieving 

CO2 emissions reductions as newer units. Commenters obtained similar results with respect to 

boiler type. Commenters identified units by boiler type (with the vast majority of units operating 

tangential firing or opposed firing boilers) and again noted that there was no strong correlation 

between the type of boiler and the level of CO2 emissions.

Commenters stated that the findings with respect to boiler type demonstrate that significant 

emissions reductions are achievable regardless of the facility's individual configuration and that 

moreover, individual EGUs have already demonstrated themselves to be capable of greater 

improvements. Commenters stated that looking again to emissions data from the period 2009 to 

2013, they calculate that a 4.41% improvement in carbon emissions rate over the five-year 

average rate would be possible in the study population overall if each EGU were required to 

meet its best single-year carbon emissions rate demonstrated over the five-year period.
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Commenters stated that this combination of findings suggests that many of the factors within the 

control of operators, such as emissions control equipment and operating and maintenance 

procedures, rather than immutable characteristics such as age, boiler type, and capacity factor, 

are responsible for an individual unit's CO2 emissions rate. Commenters stated that in other 

words, their proposed method for calculating state goals would not penalize older facilities, or 

require certain operators to achieve a disproportionate share of emissions reductions based on 

factors outside of the operator's control. Commenters stated that coal-fired steam EGUs of all 

varieties are capable of achieving improvements beyond those mandated by the Proposed Rule. 

Commenters stated that statewide emission rates in the Proposal are based in part on the 

assumption that coal-fired EGU's can achieve an average 6% improvement in heat rates (MMBtu 

per megawatt hour). Commenters stated that that determination was based on the Agency's 

analysis of the best (i.e., lowest) heat rate obtained by each coal fired EGU over the past eleven 

years and that EPA further assumed that gas-fired units were not capable of improving heat rates 

over the next fifteen years.

Commenters stated that their own study evaluated an alternative based on emission rates already 

achieved by the best performing coal and gas fired units within the past five years and required:

1. determining the heat rates and emission rates achieved by the best performing 20% of 

coal and gas fired EGU's, compare those to the rates achieve by other EGU's,

2. evaluating the emission reductions that could be obtained if coal or gas fired EGU's 

achieved heat rates or emission rates comparable to those already achieved by the best 

performing 20% of the industry today;

3. comparing the results - in terms of heat rate improvements and carbon reductions - to 

EPA's proposal.

Commenters then described the study universe which identified 601 coal-fired units for further 

analysis, selecting EGU's with a minimum nameplate net Summer capacity of 100 MWh, and a 

minimum capacity factor of 30% or higher averaged over the five year period between 2009 and 

2013). Commenters stated that the annual capacity factor for each coal-fired unit was calculated 

by dividing the net generation of a given year by the theoretical generation assuming each unit 

ran at summer capacity for an entire year (8,760 hours). Commenters stated that Summer 

capacity data is from the EIA-860 Schedule 3 Generator Data, while annual net generation is 

based on information available through EIA 923. Commenters stated that they then calculated 5-

year average capacity factors for each unit, and placed units into one of three capacity factors 

groups depending on the unit's 5-year average capacity factor. Commenters stated that the study 

is limited to coal and gas-fired units for which generation, heat rate, and emissions data were 

available for each of the five years between 2009 and 2013.

Commenters stated that next (CO2 Emissions Rates and CO2 Emissions Rate Groups), they 

determined annual CO2 emission rate for each calendar year between 2009 and 2013 for each of 

the selected units by dividing the annual CO2 emissions reported to CAMPD for a given year by 

the annual net or (for gas units) gross generation for the same year and as noted above, net 

generation data for each coal-fired unit was obtained from the EIA-923 Monthly Generating Unit 
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Net Generation Time Series File for years 2009 through 2013, while gross generation was 

obtained from CAMPD. Commenters calculated the annual CO2 emission rates averaged over 

the five year period for the units in both the coal and gas analyses, ranked the units from the 

lowest to highest rates, and sorted the data into quintiles.

Commenters stated that then, to determine heat rate, CAMD data was used to identify the annual 

heat input (MMbtu) data from 2009 through 2013 (inclusive) for all coal and natural gas-fired 

units included in each analysis and heat rates for coal-fired units was calculated by dividing the 

heat input by the net generation reported in EIA-923 Monthly Generating Unit Net Generation 

Time Series File. Commenters determined heat rate for natural gas-fired units by dividing the 

heat input by the gross generation, both of which were reported in the CAMPD.

Commenters then calculated possible improvements in CO2 and heat rate using scenarios based 

the percent change formula found in EPA's GHG Abatement Measures Technical Support 

Documents for Carbon Pollution Guidelines for Existing Power Plants. Commenters calculated 

percent change by subtracting a new number (X2) from an old number (X1), dividing the total by 

the old number and multiplying by 100 to yield the percent change between the two values.

((X1 - X2)/X1) * 100 = % Change

Commenters then estimated potential CO2 reductions by assuming that each unit could meet the 

annual average emission rates achieving by the best performing 20% within each category 

between 2009 and 2013. 

Commenters stated that EPA should focus on 1) improving heat rates where technically and 

economically feasible and 2) maintaining the current operational efficiencies already achieved 

rather than trying to pursue additional marginal efficiencies at the risk of rendering units 

economically non-viable. Commenters stated that while EPA's methodology is fraught with 

inequities, inappropriate assumptions and insufficient data, means exist to address these 

shortcomings. Commenters stated that for the purpose of calculating the standard attributed to 

Building Block 1, EPA should establish a heat rate target that is specifically tailored to a 

technically feasible target inside the fence line at each EGU using actual plant data rather than 

utilizing a statistical approach. Commenters stated that this alternative will require EPA to 

undertake an evaluation of the potential HRI available at each unit that is subject to 111(d). 

Commenters stated that they recognize that a unit-by-unit analysis would be a significant 

undertaking for EPA and require the commitment of significant resources and the commenters

recommended that EPA consider delegating this responsibility to the individual states as part of 

their compliance plans. Individual states are best positioned to do a thorough analysis of the units 

inside their borders, both from a resource and familiarity standpoint. Commenters stated that 

EPA should also take into consideration the remaining useful life of the EGU and avoid 

requiring the installation of costly modifications at a facility nearing retirement and that this is 

the most accurate and equitable means for establishing HRI goals under Building Block. 

Commenters stated that in the event EPA determines that a unit-by-unit analysis is unfeasible, 

EPA should allow states to achieve an average annual heat rate of less than, or equal to, a 

specified target heat rate level, not a unilaterally applied, arbitrary percentage 

reduction. Commenters stated that this would establish a standard of performance for lower 

performing units without penalizing higher performing units. Commenters stated that one 

logical standard of performance is EPA's calculated national average of 9,753 Btu/kWh or 
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another number based on the median of the heat rate data underlying EPA's calculation of the 

national average. Commenters stated that States that already operate below the target heat rate 

would be deemed to have already met BSER, thus eliminating the need for further HRI that 

might be technically infeasible or that might render units uneconomical. Commenters stated that 

under this methodology, states already in compliance with the target heat rate would have no 

emissions reductions attributed to Building Block 1. Commenters stated that this methodology is 

consistent with the technical feasibility average concept that EPA uses in Building Blocks 3 and 

4, however, this methodology will still produce a standard that is not technically or economically 

feasible for units that have already maximized HRI opportunities.

Commenters provided estimates of the theoretical technical potential for total HRI opportunity 

from Best Practices. Commenters stated that the fact that the best practices have been adequately 

demonstrated in the existing coal-fired steam fleet in part, suggests that many of the individual 

HRI options identified in Table A-1 (titled: “Gross HRI Options for the Typical 500 MW 

Existing Coal-Fired Steam Unit”) in App A have already been implemented at a number of 

EGUs in the fleet today. Commenters stated that any reasonable assessment of the potential for 

HRI on the fleet must take into account HRIs that have already occurred to avoid double 

counting. Commenters stated a challenge that the EPA and they share is that a comprehensive 

tracking of HRI products and services across the fleet does not exist and it is, therefore, difficult 

to make assumptions regarding the penetration of specific HRIs on specific EGUs.

Commenters stated that even with a detailed history of "Best Practices" performed for each EGU 

in the fleet, many of these HRIs require ongoing monitoring and maintenance in order to sustain 

the efficiency gains, further complicating any attempts to assess the effective penetration of HRIs 

in the coal fleet at any given point in time.

Commenters stated that because it is unknown which EGUs have implemented (specific) HRIs, 

or which HRIs have deteriorated over time due to lack of ongoing maintenance, the commenters

chose to use a generalized approach to assess the technical potential, utilizing a three-stage 

process.

Fleet-wide Assessment of Technical Potential; three-stage approach:

• Stage 1: Identify the theoretical technical potential for generic coal-fired units 

• Stage 2: Estimate the penetration of HRIs in the coal-fired EGU fleet

• Stage 3: Adjust 2013 fuel burn and recalculate fleet-wide heat rate

Stage 1: Identify theoretical technical potential for generic coal-fired EGUs

Commenters stated that Table A-1 lists all of the best practice HRIs (and upgrades) available to a 

coal-fired steam boiler EGU, assuming the EGU has not implemented any of the best practices. 

Commenters stated that the heat rate savings potential for each EGU and HRI varies based on a 

number of factors, some of which are detailed in section 1 of this document. Commenters stated 

that they identified a range of efficiency gains for each HRI, bound by low and high estimates in 

the 4th column of table A-1 and for the assessment of technical potential across the fleet, they 

applied the average of the low and high HRI estimates to eligible EGUs. Commenters stated that 
173

their technical assessment identified that heat rate improvement potential varied by the EGUs 

size. Commenters stated that a summary of their best practices analysis across all EGUs size 

categories can be found in table A-2 (titled: “The Average HRI is from 5.8% - 6.8%”), which 

presents a low, average, and high HRI value for three MW ranges based on the technical 

potential). Commenters stated that the criteria used to identify eligible EGUs will be outlined in 

the following paragraph. 

Stage 2: Commenters stated that estimating the penetration of HRIs in the coal-fired EGU fleet 

they assumed a "Best in Class" net full load heat rate (FLHR) of 9,400 Btu/kWh, HHV. 

Commenters stated that any EGUs with full load heat rates at or better than 9,400 Btu/kWh were 

assumed to have implemented all available best practice and upgrade HRIs and thus, have no 

further potential for improvement. Commenters stated that EGUs with FLHRs higher than the 

best in class were assumed to have all the HRIs identified in table A-1 and summarized in table 

A-2 available, up to the point where the unit's adjusted FLHR reaches the best in class FLHR of 

9,400 Btu/kWh. Commenters stated that Figure A-1 outlines the assumed HRI available to a 

given unit, based on its reported FLHR. Commenters stated that for example, if a 500 MW coal 

unit has a 9,800 Btu/kWh FLHR, their average HRI for 500 MW EGUs in table A-2 suggests 

that a 500 MW unit could achieve a 6.2% HRI by implementing all of the options listed in table 

A-1; however, their best in class assumption caps an EGU's potential FLHR at 9,400 Btu/kWh, 

which is only 4% lower than the original 9,800 Btu/kWh. Commenters stated that therefore, the 

generalized approach assumes that a 500 MW EGU with a net FLHR of 9,800 Btu/kWh has 

already implemented ~1/3 of the HRIs on the best practice list and the technical potential for this 

particular unit is 4%.

Commenters stated that units with FLHRs greater than the best in class 9,400 Btu/kWh + the 

maximum HRI savings identified in table A-2, given the EGUs size class, are assumed to have 

all of the best practice HRIs available as technical potential. Commenters stated that using the 

500 MW unit as an example again, any 500 MW EGUs with FLHRs greater than or equal to 

10,021 Btu/kWh [10,021*(1 - 0.062) = 9,400] will have the full list of HRIs available as 

technical potential which would result in a 6.2% HRI from the reported FLHR.

Commenters stated that EGUs smaller than 200 MW were excluded from consideration in their

assessment of technical potential. Commenters stated that while this is, in part, a limitation more 

suited for the economic potential, this cohort of EGUs represents less than 4% of the reported 

generation from coal fired EGUs in 2013 and is thus, not a particularly consequential 

assumption.

Commenters stated that additionally, coal-fired steam boiler EGUs used in cogeneration 

applications and coal units that have announced or are likely to retire were excluded from the 

pool of eligible EGUs for HRIs. 

Commenters noted that they recognize that the generalized assessment does not take into account 

variation in HRI entitlement across the fleet of EGUs based upon variation in plant design, 

technology used and plant configurations, but expects that this variation is less than the 

significant distribution of reported FLHR across the fleet. Commenters stated that the 

generalized approach likely overestimates the potential for some plants that are closer to the 
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Best-in-Class FLHR of 9400 Btu/kWhr and underestimates the potential for some plants that are 

much further from the Best-in-Class FLHR of 9400 Btu/kWhr.

Stage 3: Adjust 2013 fuel burn and recalculate fleet-wide heat rate

Commenters stated that to assess the impact of coal HRIs on the fleet-wide heat rate, they used 

the reported generation72 and fuel burn from coal-fired EGUs73 in 2013. Commenters stated 

that because the relationship between coal and gas prices in 2013 is more consistent with their 

long-term outlook on fuel prices in the US (vs. other recent years), they believed 2013 will be 

most representative of the coal dispatch in future years. Commenters stated that for each coalfired steam boiler unit in the US fleet, the HRI % identified in stage 1 was applied to the fuel 

burn of all units identified in stage 2 as having HRI potential, capping the improvement at the 

best in class, 9,400 Btu/kWh FLHR.

Impact of the technical potential analysis on fleet-wide heat rate:

Commenters stated that holding the 2013 reported dispatch constant, the fuel burn was reduced 

to account for the efficiency improvements identified as the technical potential. Commenters 

referred to Figure A-2 (bar chart of MMBtus Coal Burn in 2013 vs. Full Load Heat Rate) which 

highlights the change in fuel burn for the low, average and high estimates of HRI from stage 1. 

Commenters stated that this analysis shows that the technical gross potential could range from 

2.5% to 7% HRI, with a most likely scenario that a gross 5% heat rate improvement is 

technically possible from best practices solutions.

Commenters referred to Table A-3 (2013 Generation weighted average heat rate of US coal-fired 

EGUs and their gross heat rate improvement potential) contains a summary of the fleet-wide heat 

rates before and after the technical potential analysis. 

Commenters stated that an implied assumption made by EPA is that power plant owners are not 

sufficiently motivated to utilize "best practices" to reduce heat rate absent a CO2 mitigation rule. 

Commenters suggested that the reasonableness of this assumption could be tested using EPA's 

policy analysis tools and that this could be done by permitting the option of heat rate 

improvements when running the Base Case with the Integrated Planning Model (IPM). 

Commenters stated that if running the IPM Base Case while allowing heat rate improvements 

results in most units applying heat rate improvements, then this will demonstrate that many of 

the improvements that EPA relies on for Building Block One of this rule have already been 

realized. 

Commenters suggested, as an alternative to the methodology used by EPA, evaluating historical 

annual average heat rates of units and, adjusting for equipment added such as scrubbers that 

impact heat rate and perhaps other important factors such as annual average capacity factor, 

using the average of the best three or four years as a heat rate going forward. 

Commenters believed that the statistical analysis used by EPA (and that by Linn, et. al.) should 

not be relied upon for this rulemaking and as a result, the conclusion drawn by EPA from this 

statistical analysis - that a 4% heat rate improvement is widely achievable on average through no 

or low cost "best practices" that improve facility control - is questionable. 
175

Commenters stated that because EPA has neither performed nor identified any case studies on 

base-load EGUs that comply with the ARP, CAIR, CSAPR, and MATS, and instead relied on 

unsubstantiated statistical exercises and an outdated study, states are presented with a capricious 

and technically infeasible Building Block 1 requirement to reduce the average heat rate by six 

percent. Commenters stated that West Virginia EGUs cannot meet this mark, as they have 

already minimized heat rate variation and operate at high boiler efficiencies. Commenters stated 

that to limit heat rate variability and consequent CO2 emissions from coal-fired EGUs, BSER 

should be limited to best practices of operation and maintenance. Commenters stated that the 

study upon which EPA bases its Building Block 1 goal, Sargent & Lundy, recommends 

performing a site-specific power plant energy audit that would identify cost-effective equipment 

upgrades that result in significant heat rate improvements. Commenters stated that then, 

implementation of audit recommendations that are cost-effective for each EGU on a case-by-case 

basis would assure that each EGU is achieving the best heat rate that is practicable, economical, 

and achievable for that unit. Commenters stated that for some EGUs, the result may be greater

than EPA's six percent standard and for others, it may be less, but in either event, EPA could be 

assured that each EGU is operating at maximum practical efficiency using the legally required 

BSER standard that takes both cost and energy requirements into consideration. Commenters 

stated that EPA failed to follow the recommendation made by the study upon which it bases its 

calculations of its proposed Building Block 1 goal 

Commenters stated that heat rate improvements can be cost-effective ways to reduce CO2 

emissions, or to mitigate increases in CO2 emissions, over the life of a fossil-fueled generating 

unit, regardless of fuel type or unit design but that however, given the inherent variability in heat 

rate due to duty cycles and other uncontrollable factors, and the lack of an effective real-time 

heat rate measurement technique, it is infeasible to establish traditional emission limitations or 

standards based on improved heat rates. Commenters suggested that EPA should collect 

sufficient information about the techniques that could potentially be adopted to varying degrees 

at existing units (considering costs, lack of physical space, degree of prior adoption, remaining 

useful life, and other factors) and formulate a proposed guideline for a work practice standard 

that would allow for periodic evaluation of cost-effective heat rate improvement opportunities on 

a unit-specific basis, that can then be integrated into regularly planned outages across the 

existing fleet. Commenters stated that such a measure would ensure sustained adoption of 

available efficiency improvements within the existing fleet, which is the "best system of 

emission reduction" for these designated facilities.

Commenters stated that EPA established the Block 1 generating unit efficiency improvement 

targets for Minnesota and neighboring states at 6%, considering statistical analysis of heat rate 

improvements achieved during maintenance outages and by referencing a Sargent and Lundy 

study of plant efficiency improvement options. Commenters stated they recommend that states 

be allowed to hear petitions from utilities for accepting a unit as delivering adequate heat rate 

performance, giving consideration to cost effective deployment of heat rate improvement 

measures. Commenters stated that upon state approval of the unit's petition, the state's target 

would be adjusted to reflect the change in the state's Block 1 stringency such that other units are 

not compelled to provide for additional efficiency measures. Commenters stated that absent a

means for giving relief to state target-setting when individual units demonstrate they cannot cost 

effectively meet a 6% efficiency improvement, EPA's CPP target-setting process would be 
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compelling units owned or operated by different utilities to outlay additional funds to 

compensate for EPA BSER cost effectiveness or feasibility assessment errors. 

Commenters stated that they view Building Block 1 as a foundational building block in the 

BSER formulation and it is important that EPA provide as much technical support in the record 

as possible for the heat rate improvement targets adopted in the final rule based on feedback 

from plant owners and operators, as well as from independent experts. Commenters stated 

that recognizing that not all companies have implemented heat rate improvements, they share 

other stakeholders' concerns that the proposed six percent improvement target may not take into 

account efficiency improvements that have been already implemented to improve efficiency and 

reduce fuel costs at existing coal-fired units, which could limit the ability of a unit to implement 

an additional six percent improvement. Commenters recommended that EPA provide a 

mechanism to recognize recent investments that have resulted in improved power plant 

efficiency and to that end, they would support a standardized process for states to demonstrate 

that owners/ operators of specific, in-state units have made recent investments that resulted in 

clear efficiency improvements within a time-frame defined by EPA. Commenters stated that if 

states were to make such a demonstration, EPA would then adjust the assumed availability of 

heat rate improvements in that state. Commenters stated that however, they would only support 

such a review and adjustment if the process was completed prior to EPA finalizing the rule in 

June 2015 because after the rule is final, they do believe that any changes to the state emission 

targets should be made. 

Commenters briefly described EPA's 6% goal assumptions. Commenters stated that while 

Renewables does not operate any coal-fueled units, it has reviewed EPA's analytical assumptions 

since unachievable assumptions made for coal-fueled units in the states where Renewables 

operates will make compliance in those states more challenging. Commenters believed that 

EPA's analytical assumptions for heat rate improvement projects are not practicable and in some 

cases technically infeasible. Commenters stated that minimizing heat rate (maximizing unit

efficiency) is a key operating objective for any coal-fueled generating unit operator; however 

implementation of heat rate improvements must balance cost effectiveness while ensuring 

compliance with all environmental and regulatory requirements and optimizing the reliability 

and efficiency of the coal-fueled generating units over their respective remaining lives. 

Commenters stated that utilities have an economic incentive to improve operating efficiencies 

and therefore well-run utilities already exercise best operating practices and have implemented 

heat rate improvement projects where necessary and economically justified to improve plant 

efficiency. Commenters stated that this is evidenced by the wide range of CO2 emission rates for 

the affected coal-fueled units. Commenters presented a chart that shows an inverse relationship 

between CO2lb/MWh and number of coal-fueled power plants increase. Commenters stated that 

as the chart implies, a number of the improvements suggested in Sargent & Lundy's report have

already been implemented by the best performing coal-fueled generating units during or before 

2012. Commenters stated that clearly the worst performing coal-fueled units (for example, those 

with CO2 emission rates above 2,250 lb/MWh, or approximately 50% of the coal plants) have 

the greatest opportunity to make the noted equipment and operational changes to improve 

efficiencies; whereas those below this level do not. Commenters stated that EPA should consider 

a tiered structure which would assume greater efficiency improvements were available for the 

least efficient units (i.e. 3%-4%), and lower efficiency improvements were available for the most 
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efficient units (i.e. 1%-2%), as these more efficient units have likely already implemented a 

number of the best practices and equipment upgrades outlined in the Sargent & Lundy report.

Commenters proposed a new methodology and time period for determining BSER for Building 

Block 1. Commenters stated that this new methodology would incorporate 4 parts: 1. Establish a 

multiple year period (e.g., 2010-2012) to define baseline conditions. 2. Examine the coal EGUs 

with the lowest heat rate value for actual BSER practices and equipment upgrades to be applied 

on a case by case basis (consistent with the CAA), rather than relying on a statistical approach. 3. 

Use net heat rate rather than gross heat rate since the rule uses net electricity generation to 

calculate the state allowable CO2 rate. 4. Allow a state to take into consideration the statutory 

elements for developing BSER including the remaining useful life of an existing source to which 

the standard applies. Commenters stated that such a change would re-structure which units are 

required to implement Building Block 1, which HRI methods to implement, and the level of 

improvement HRIs would be required to meet and establish a true the BSER. Commenters stated 

that this approach strengthens this rule by making it:

1. More legally defensible (should it be 4%, 6%, or 10% HRI? Why is one of those values 

significantly less arbitrary and capricious than another?)

2. More equitable (those that already made HRIs would have less to do, those that have not 

made HRIs would have more to do)

3. More cost-effective (those that already made HRIs would not be forced to implement 

more costly HRIs, while those that have not implemented HRIs would have a list of cost 

effective options)

Commenters stated that States should be allowed to adjust the heat rate improvement goals 

within their states based on a detailed analysis of coal-fired EGUs in their specific state.

Commenters stated that though they do not operate coal-fired steam EGUs, they recognize the 

importance of these units to maintain system reliability and their contribution toward fuel 

diversity. Commenters stated they are supportive of revisions to the rule that will ensure that this 

resource will be able to achieve reductions yet remain viable. Commenters suggested 

modifications include an incremental approach stipulating that no reductions associated with coal 

plant heat rate improvements will be required for states that generated less than 10% of their total 

annual energy from coal from the end of 2012 as well as providing a mechanism to account for 

improvements that have already been made. 

Comment recommended that EPA amend Building Block 1 stipulating that no reductions 

associated with coal plant heat rate improvements will be required for states that generated less 

than 10% of their total annual energy from coal. Commenters stated that there are many reasons 

EPA should exclude states with limited coal production from Building Block 1. Commenters 

stated that first and foremost those states with less than 10% of their total energy generated from 

coal have already undergone a significant change in the energy mix. Commenters stated that the 

coal currently operating in New York is performing a needed function as it helps to address local 

reliability issues and in many instances is operating because those units must run for local 

reliability needs.
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Commenters recommended reevaluating this 6% heat rate reduction potential on a smokestackby-smokestack basis to determine how much reduction is actually achievable at plants that have 

already been designed and retrofitted for emissions reduction and efficiency purposes.

Commenters stated that their analysis clearly demonstrates EPA's building block 1 presumes 

actions that will not yield additional HRI for Wisconsin EGUs. Commenters stated that to 

address this problem, EPA must use a unit-by-unit, bottom-up approach to assess the 

applicability of the identified HRI actions to each EGU and determine a building block 1 value 

specific to each state. Commenters stated that EPA should also allow each state to make 

adjustments to building block 1 based on what is technically achievable at each EGU. 

Commenters stated that finally, EPA should decrease Wisconsin's HRI requirement to reflect the 

results of such a bottom-up analysis; based on the preliminary analysis presented above, the real 

HRI is anticipated to be lower than 2.3% and may range as low as 0.5% on a gross heat input 

basis. 

Commenters stated that they do not agree that a 6% average heat rate improvement is feasible for 

all coal units and that many utilities have already retired their least efficient units and upgraded 

turbines and other equipment on remaining units because this makes economic sense. 

Commenters stated that EPA's asserted basis for its 6% number does not account for this. 

Commenters stated that States should be allowed to set efficiency improvement targets based on 

unit specific factors and costs including remaining useful life, previously-upgraded equipment, 

added environmental controls, and other factors. Commenters stated that those other factors 

should include the adverse impacts that result from other building block activities that States may 

choose and the emission guidelines should be adjustable based on the states' analysis of 

achievability of Building Block 1. 

Commenters requested that EPA provide a mechanism to recognize investments that have 

resulted in improved power plant efficiency, such as that EPA could create a mechanism for 

states and companies to submit information on recent investments that would result in a revision 

in the default heat rate improvement applied through Building Block 1. 

Commenters stated that EPA erroneously assumes that all coal-fired units can implement 

efficiency projects that will yield a six percent improvement in the unit's heat rate and 

accordingly, EPA must use a more realistic approach to representing the heat rate reductions 

available to coal-fired sources. 

Commenters stated that EPA highlights that hourly ambient temperature and capacity factor 

together explain 26 percent of the change in heat rate for the study population. Commenters 

stated that however, EPA also notes that there is considerable variability within the sample set 

and that at some EGUs, typically load-following EGUs, capacity factor explains more than 50 

percent of the change in heat rate. Commenters stated that adding the 10 percent associated with 

temperature to the 50 percent associated with capacity factor suggests that among load-following 

units capacity factor and temperature explain more than 60 percent of the change in heat rate. 

Commenters stated that as a result, if a state were to make a showing that the majority of in-state 

coal units operate as load-following units, EPA could consider that that the state will have less 

opportunity to make heat rate improvements across the fleet. 
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Commenters stated that they would like to propose the following recommendations to the EPA 

as it considers all of the comments received and revises the proposed rule accordingly.

• Fix technical deficiencies inside CPP modeling, and re-run building block 

assumptions and goals, incorporating the effects of one block's goals and 

assumptions on another.

• Fix the errors in the heat rating assumptions formulated in building block 1. 

Commenters stated that the assumed 6% heat rate improvement outlined in Building Block #1 is 

not achievable for their facility, because the studies used to support the heat rate improvement 

assumptions assessed significantly larger power plants (over 200 MW) and facilities where no 

significant prior efforts had been made to improve heat rate. Commenters stated that larger 

power plants have an advantage with economy of scale and many of the projects and associated 

heat rate improvements listed in the EPA Technical Support documents are not achievable in a 

smaller plant, like their facility. Commenters stated that as a municipal utility, decisions about 

plant improvements and upgrades are made at the local level and stated that they do not have to 

wait on a state agency to approve increased rates before undertaking plant improvements and 

projects that made economic sense and improved heat rate have already been completed. 

Commenters stated that of the example projects discussed in the Technical Support documents, 

many have already been undertaken at their facility; and of those left, the costs are high, 

outcomes not clear, and regulatory burdens complex (such as New Source review (NSR) or other 

complicated permitting, and the unknown potential costs for BACT required due to NSR). 

Commenters stated that it is fundamentally flawed for EPA to design a rule ignoring logistics, 

costs, and outcomes. Commenters requested that all units less than 250 MW nameplate output be 

specifically exempted from inclusion in the Building Block #1 calculations or alternatively, the 

Rule could exempt all units from entities with portfolio capacities less than 1,000 MW. 

Commenters stated that each state should require coal-fired power plants to submit a HRI report 

to identify measures that have already been implemented and those that may still be 

accomplished and adjust their interim carbon intensity targets accordingly. 

Commenters stated that while U.S. EPA has relied on specific data regarding the CO2 emissions, 

generation, and heat rates reported by EGUs through the Clean Air Markets Database to 

determine the overall efficiency potential of heat rate improvement (HRI) projects for existing 

units, U.S. EPA assumptions from this data are too broad and do not take into account unitspecific designs. Commenters stated that before U.S. EPA sets an efficiency goal for coal-fired 

units under Building Block 1 or state CO2 targets, Indiana recommends U.S. EPA issue an 

information collection request (ICR) to all fossil-fuel fired EGUs and Load Serving Entities 

(LSEs), or electric utilities, to determine the following:

• What HRI projects each coal-fired EGU has already installed. 

• The date of any such HRI installations. 

• Any operation and maintenance measures each coal-fired EGU already employs 

that assist the unit in operating more efficiently.
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• If the coal-fired EGU uses some of its fuel to supply steam to other customers.

• If the coal-fired EGU is owned by a regulated utility, then the expected retirement 

year of the unit according to the utility's last approved depreciation study. 

• If a coal-fired EGU is owned by a merchant power producer or an unregulated 

utility, the planned date for the next major unit overhaul for the purpose of 

determining an appropriate retirement date.

• For load-serving entities (LSEs), or electric utilities, the generation source, type, 

and location.

• Capacity of generating units. 

• Power supplied through purchased power agreements in 2012 (or any historical 

years eventually used as a baseline for setting CO2 targets).

• Renewable Energy Credits (REC) inventories as of December 31, 2012 (or as of 

the end of any historical years used in the baseline for setting CO2 targets).

Commenters stated that Indiana believes this information is crucial for U.S. EPA 

to know and consider, as it will provide the agency with specific heat rate 

improvements already conducted at EGUs and their expected retirement dates. 

Commenters stated that Indiana notes that U.S. EPA has issued ICRs in past 

rulemakings to determine a reasonable and achievable emission limit that is 

technically and economically attainable for sources within a particular source 

category. Commenters stated that Indiana recognizes that such a request will take 

time to execute and analyze the data, but such an endeavor is necessary to 

determine a realistic efficiency improvement goal for existing coal-fired EGUs 

and appropriate generation targets in each state. 

Commenters recommended two modifications to the proposal with respect to building block 1. 

Commenters stated that first, EPA should adjust the heat rate improvement goal to within a range 

of 1% to 2%. Commenters stated that several utilities have made cases demonstrating achievable 

heat rate improvements in the range of 0.8% to 2%, additional to what they have already 

implemented but for which they do not receive credit in the proposed rule. Commenters stated 

that second, EPA should provide an exemption to NSR applicability for projects solely related to 

efficiency improvements at EGUs. Commenters stated that utilities will be more likely to 

implement efficiency improvement projects if they do not have to worry about the risk of vast 

permitting requirements and cost. 

Commenters stated that South Dakota has discussed building block 1 with other states and it 

appears EPA's best practices have already been implemented by a majority of coal-fired power 

plants in EPA Region 8. Commenters stated that this makes EPA's 6 percent heat rate 

improvement goal unrealistic, not only for South Dakota but for most states in Region 8.

Commenters stated that the alternative to building block 1 is for each individual coal-fired power 

plant to be analyzed on a case-by-case basis to determine the heat rate improvement that is 
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realistic for establishing a state goal. Commenters stated that each state can require coal-fired 

power plants to submit a heat rate improvement report to identify what they have already 

implemented and what may still be accomplished. Commenters stated that this alternative will 

actually give states the flexibility to establish realistic heat rate improvement goals in each state 

based on the varying and unique circumstances of each generating unit. Commenters stated that 

further, any next generation technologies that are developed in the future to improve a plant's 

heat rate could be implemented by the coal-fired power plant and used to demonstrate 

compliance. 

Commenters stated that under the Acid Rain Program, sources were afforded the opportunity to 

choose a baseline year from among several years for determining the baseline emission rate. 

Commenters stated that if EPA were to adopt this approach for the Clean Power Plan, sources 

would likely select the year with the highest emitting rate, and any emission reductions under 

Block 1 via heat rate improvements would be largely illusory. Commenters stated that however, 

choosing either the average or the reported lowest emission rate, which might be five percent less 

than the average rate, would lead to concerns that the requirement is infeasible. Commenters 

stated that moreover, the heat rate achieved by the unit is partially dependent on the load factor 

of the unit, which is a function of weather, dispatch priority, and other factors. 

Commenters stated that to address these concerns, they suggest that each source should be 

required to submit an engineering analysis of the measures that it intends to undertake to achieve 

the required efficiency improvement and conduct reference method tests before and after 

implementing those measures to document that the required improvement has been attained.

Commenters stated that to aid in identifying the most cost-effective hardware upgrades and to 

minimize gaming by regulated entities, detailed reporting of the cost and performance of 

engineering upgrades should be required and made publicly available. Commenters stated that 

thereafter, CO2 CEMS and enhanced fuel input and electrical output monitoring would be 

employed, along with annual reference method testing, to document that the required 

improvement is being maintained. Commenters stated that a Compliance Assurance Monitoring 

("CAM") response plan would require an engineering analysis and additional measures to be 

adopted if the source's compliance margin fell below a set value. 

Commenters stated building block 1 is not consistent with section 111 (d) of the CAA as it 

arbitrarily defines improvements in heat rates without regard to the statutory factors. 

Commenters said EPA has taken a simplistic "one size fits all" approach to a complicated caseby-case engineering analysis.

Commenters stated EPA should adopt a bottom-up approach letting states implement the 

building blocks using state-specific (and, for building blocks 1 and 2, unit-specific) information. 

Commenters said this would allow the building blocks to accurately reflect both what a state has 

accomplished to date and what it can actually achieve in the future. Commenters said this 

approach also recognizes what EPA has acknowledged: that each state is starting in a different 

place and therefore must have a unique reduction goal. Commenters said unlike EPA's 

application of the building blocks, a bottom-up approach would recognize that forward-thinking 

states that took early action have already picked the "low-hanging fruit" and therefore have less 

they can reasonably achieve when compared to those that have done little. 
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Commenters stated that forcing units to operate at sub-optimal levels and shut down for periods 

in order to meet goals hurts performance and significantly and adversely affects a unit's heat rate. 

Commenters said that if EPA finalizes the rule as proposed the fossil fuel-fired power plants will 

emit more greenhouse gases per mWh than before ESPS Guidelines came into place. 

Commenters continued that EPA's proposal to curtail or cease emissions from existing plants 

should be incremental, as opposed to the proposed method.

Comment 10: Applicable to the supplemental proposal for Tribal and Territorial - Alternative 

approaches to determining the HRI component of the BSER.

Response 10: See section V.C of the final rule preamble of the CPP and Chapter 2 of the GHG 

Mitigation Measures TSD supporting the final CPP for the EPA’s response to these comments. 

The EPA appreciates commenters’ support, suggestions, and constructive criticism. Where 

appropriate, the EPA has refined its methodology accordingly. For the reasons stated in the 

above-referenced portions of the preamble and TSD, the EPA believes that the methodology 

described in the above-referenced portions of the preamble and TSD provides the best method of 

determining the heat rate improvement component of the BSER, and that this methodology is 

based on sufficient information.

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

Commenters stated that while there may be opportunities to improve heat rate through more 

widespread use of "best practices," the statistical methods used by EPA do not provide a reliable 

means to estimate what is possible and should not be used as a basis for the carbon standards 

rule. Commenters stated that in fact, EPA does not clearly identify in the TSD what "best 

practices" are. Commenters stated that one possible approach for the rule would be to establish 

work practice standards that define what "best practices" are and then require them in a similar 

manner to that which EPA has established for work practice standards in other rulemakings. 

Comment 11: Comments regarding "relative" or "absolute" heat rate reduction 

Response 11: For the EPA’s response to these comments, see sections V.A, V.C and VIII.G of 

the final rule preamble of the CPP and Chapter 2 of the GHG Mitigation Measures TSD 

supporting the final CPP. The final CPP quantifies heat rate improvement under building block 1 

in terms of absolute improvement.

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

Commenters stated that "the utilities may confuse a relative increase in efficiency with an 

absolute increase in efficiency". Commenters provided the example that an increase in efficiency 

from 36% to 39% is a relative increase of about 8% (3/36), but an absolute increase of only 3% 

(39-36). Commenters stated EPA's Building Block 1 refers to a 6% increase in the heat rate of an 

affected unit, and therefore requires only a relative 6% improvement and an absolute 

improvement of slightly over 2%. Commenters stated Associating Building Block 1 with an 
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absolute 6% efficiency improvement, as some utilities may be doing, exaggerates the reductions 

projected assumed under that Block. Commenters stated while it appears questionable whether 

Missouri utilities can meet the anticipated heat rate reductions given the efficiency projects 

already completed on Missouri's coal-fired fleet, it is clear there is confusion related to Building 

Block 1. Commenters stated at a minimum, Building Block 1 requires clarification in the final 

rules as to whether the heat rate reduction percentage is "relative" or "absolute". 

Commenters stated that EPA failed to provide absolute heat rates from the units contained in the 

sample size; and without such data, it is impossible to know if 2% HRI is achievable from 

equipment upgrades at EGUs performing substantially better than the cited national average heat 

rate. 

Comment 12: Comments comparing EPA’s proposal for building block 1 with EPA's proposed 

standards for modified and reconstructed EGUs

Response 12: The EPA disagrees with these commenters. Unlike the standards for modified and 

reconstructed EGUs, this rule does not establish emission reduction requirements directly 

applicable to any individual EGU. Rather, building block 1 is merely one component of the 

BSER, which itself is used to establish CO2 emission performance rates and state goals. The 

regional heat rate improvements under building block 1 are regional averages; some EGUs may 

be able to achieve more heat rate improvement, some may be able to do less. States have the 

flexibility under this rule to develop state plans with emission standards for individual affected 

EGUs. Additionally, the interim goals under this rule do not have to be met until 2022, whereas 

the standards for modified and reconstructed EGUs must be met by affected EGUs on a much 

quicker timeframe. Accordingly, comparisons between building block 1 and EPA’s proposed 

standard for modified and reconstructed EGUs are wholly inapt.

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

Commenters stated that EPA's building block one would require a significant improvement in the 

efficiency of coal-fired electric generating units by requiring those units, on average, to reduce 

their heat rate by 6 percent. As a matter of simple logic, EPA's 6 percent number makes no sense. 

Commenters stated that EPA's proposed standards for modified and reconstructed sources sets a 

standard of 2 percent CO2 emission reduction below the source's best historical performance.

Commenters stated that if there is a reason to conclude that existing unmodified and 

unreconstructed units can make better efficiency improvements than modified and reconstructed 

units, EPA doesn't say what it is. 

Commenters noted that EPA's block one assumptions are directly contradicted by the Modified 

Unit Proposal and under that proposal, EPA asserts that existing units should be expected to 

improve their emission rate by only 2 percent above historic levels -well below the 6 percent 

assumption that EPA proposes for existing units. Commenters stated that EPA has not explained 

why it believes that existing units-which are more constrained in terms of the actions they can 

take to modify their operations to reduce emissions -can achieve a 6 percent improvement, while 

units modified undertaking significant upgrades can only achieve a 2 percent improvement. 
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Commenters stated that under the modified and reconstructed proposal, U.S. EPA even 

acknowledges the possible need for a separate standard for load-following natural gas combined 

cycle (NGCC) EGUs where the more stringent standard would apply only during periods of high 

annual capacity factors and a less stringent standard would apply during intermediate load 

periods (e.g., when electric sales are between 33 to 60 % of potential electric output). 

Commenters stated that U.S. EPA states this would address the fact that certain NGCC are 

designed to be highly efficient when operated as load-following units, but due to the design 

characteristics efficiency is reduced at base load (and vice-versa). Commenters stated that 

additionally, NGCC units operating as load-following are inherently less efficient than base load 

units. Commenters stated that as stated in the comments on the modified/reconstructed proposal, 

they understand these concepts to be true for most fossil-fuel-fired generators, not just NGCC 

units, and thus, they find it difficult to rationalize why such considerations would potentially be 

given to natural gas units and not coal-fired boilers. Commenters stated that this is particularly 

perplexing when they understand that some coal-fired units may choose to modify or reconstruct 

to achieve compliance with the Section 111(d) requirements. Commenters stated that 

furthermore, coal-fired generators were largely engineered to operate at high capacity factors. 

Commenters stated that these proposed rules will force many coal-fired units to operate as load 

following units, outside of their design parameters and at the expense of efficiency. Commenters 

urged U.S. EPA to extend those considerations offered to NGCC units to coal-fired units, 

otherwise, it is clear that U.S. EPA is choosing a winning fuel, natural gas over a losing fuel, 

coal. 

Comment 13: Comments regarding the EPA's reliance on the CAMD data and lack of 

consideration of key factors in plant design, coal quality, load changes and retrofits to meet more 

stringent compliance standards

Response 13: See section V.C. of the final rule preamble of the CPP and Chapter 2 of the GHG 

Mitigation Measures TSD supporting the final CPP for EPA’s response to this comment.

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

Commenters stated that EPA erred in employing a statistical analysis of plant heat rate based on 

data reported to the Clean Air Markets Division - what this approach offers in terms of abundant 

hourly data, it lacks in its failure to consider key differences in plant design, and as a result, 

quantitative results from this analysis are unrealistic and are further compromised by the use of 

purely arbitrary assumptions. Commenters concluded that EPA employs purely arbitrary 

assumptions regarding the fraction of heat input that can be saved by deploying unspecified 

improvements in heat rate in order to support its claim that a 4% reduction in heat rate is 

possible. 

Commenters stated that after the review of the thirteen S&L measures, Commenters agreed with 

EPA's observation that, "The existing EGU design and other site-specific factors may prevent the 

technical feasibility of using a given technology." TSD, p. 2-6. Commenters urged the EPA to 

give more consideration to the implications of that fact, and to further consider its list of factors 

affecting EGU efficiency at a given facility. TSD, p. 2-4 to 2-5. Commenters stated that EPA's 
185

heavy reliance on its existing datasets - the 61,848,580 hourly records for 884 EGUs - seems to 

have distracted its attention from the virtual absence of data that would provide more 

conventional insight into what modifications are possible and valuable as a practical matter. 

Commenters also questioned the notion that every EGU is in a position to achieve its best three 

year performance (out of eleven years) through the adoption of best practices. Commenters 

stated that it is common knowledge in the industry that average capacity factors of plants and 

fleets decline with time, and the decline becomes more marked in the later years of the EGU's 

life. Commenters referred to E.g., Carl Bauer, presentation to Wyoming Infrastructure Authority, 

October 17, 2014, slide 9; Dr. Robert Peltier, Predicting U.S. Coal Plant Retirements, Power, 

May 1, 2011. Commenters pointed to Table 2-5 of the TSD which directly reflects on this issue, 

showing reported annual capacity factors ranging from highs of 70-71% in 2004-2008 which 

declined to a low of 53% in 2012. Commenters stated that EPA speculates that decline may be

due to the economy in general or to competing sources of electricity, but does not meaningfully 

address the effect of aging. TSD, p. 2-20. 

Commenters stated that more important, EPA has not made any effort to understand the broader 

set of circumstances which have changed over eleven years, and which may prevent an EGU 

from returning to earlier heat rates. Commenters stated that examples from the Commission's 

experience readily come to mind such as an EGU is served by a captive coal resource of 

declining quality. Commenters stated that a base load coal-fired EGU is regularly backed down 

to accommodate and support radically increased wind generation. Commenters stated that the 

EGU has been retrofitted to meet more stringent compliance standards and that none of these 

causes will be found in the 61,848,580 hourly records found in EPA's datasets, even though 

effects may be reflected there. 

Commenters stated concerns about the accuracy of data used in studies EPA relied upon to make 

assumptions across a portfolio of affected coal-fired units at the national level. 

Commenters stated that EPA identified 16 EGUs, of the 884 data sets examined, that reported a 

single year-to year heat rate improvement of 3% to 8% and in two of these cases, equipment 

upgrades were identified that were responsible for a 2% to 3% heat rate improvement. 

Commenters stated that in the remaining cases, EPA was not able to confirm any specific 

equipment upgrades, but EPA still concluded that equipment upgrades were the "most likely 

cause of some of the observed heat rate improvements." GHG Abatement TSD at 2-22. 

Commenters stated that it is unclear how this statistical analysis further supports the 

reasonableness of a 6% heat rate improvement and in evaluating annual data for 884 EGU's over 

a ten-year period, the analysis concluded that two (2) units demonstrated a single year-to-year 

heat rate improvement that could be attributed to equipment upgrades. Commenters stated that in 

these two instances, the documented heat rate improvement was 2-3% - well below the sustained 

6% that EPA proposes. 

Comment 14: Comments endeavoring to correct or add to the data used by EPA to assess the 

potential for heat rate improvement
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Response 14: We appreciate those commenters who have endeavored to offer corrections to, or 

identify errors in, the data used by EPA to assess potential heat rate improvement. Where 

appropriate, we have updated our methodology in response to these comments. For example, the 

final methodology uses heat rate rather than heat input. For a response to these comments and a 

thorough explanation of the EPA’s methodology, see sections V.C of the final rule preamble of 

the CPP and chapter 2 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 the coal EGUs in Alaska cannot achieve heat rate improvements through 

any reasonable measures and that if the Proposed Rule is applied to Alaska, EPA cannot assume 

any savings through heat rate improvements when calculating their goal. Commenters stated that 

further, if EPA applies the Proposed Rule to Alaska, corrections should be made to properly 

account for coal EGUs in the baseline. Commenters stated that Alaska's emission baseline and 

goal should be adjusted to reflect the actual emissions from Healy Unit 1. Commenters stated 

that EPA's materials contained conflicting data regarding the CO2 emission rate and total 

emissions from Healy Unit 1 in 2012; in one file, EPA reported an emission rate of 2,901.4 

lb/MWh and total emissions of 312,493.2 tons from the unit; in another spreadsheet EPA 

reported total emissions of 307,155.732 for the same unit over the same period. in a third file, 

EPA reported an emission rate of 2,852 lb/MWh. Commenters stated that however, GVEA 

measured, and reported an actual CO2 emission rate of 3,564.89 lb/MWh for Healy Unit 1 in 

2012. Commenters stated that Alaska's emission baseline and goal should be adjusted to reflect 

this rate. Commenters stated that Alaska's emission baseline and goal should also be adjusted to 

recognize Healy Unit 2. Commenters stated that the EIA materials incorrectly assign Healy Unit 

2 an "indefinitely postponed" status however GVEA anticipates commencing generation at this 

unit in 2015 or early 2016. Commenters stated that thus, if the Proposed Rule is applied to 

Alaska, the baseline should be adjusted to account for anticipated operations at Healy Unit 2 

because it is an existing unit to which the utility is financially committed. Commenters stated 

that they anticipate that Healy Unit 2 will operate at about an 85% capacity factor with an 

emission rate of approximately 2,700lbs/MWh. Commenters stated that an allowance for Healy 

Unit 2- generating approximately 391,000 MWh with an emission rate around 2,700lbs/MWhshould be included when calculating Alaska's 2012 baseline and targets if the Proposed Rule is 

applied to Alaska. 

Commenters stated that EPA relied on fuel consumption data from EIA Form 860 to calculate 

the net heat rates used in determining building block 1. Commenters stated that however, the 

EIA fuel consumption data is inconsistent with the fuel consumption data reported and certified 

by utilities to the CAMD database for some Wisconsin EGUs Commenters stated that the EIA 

fuel consumption data is also not required to be reported using the same quantification methods 

for all EGUs, as is required under the CAMD database. Commenters stated that to avoid the 

variations and inconsistencies that could result when using the EIA fuel consumption data, EPA 

should instead use the CAMD database fuel consumption values, which are reported for purposes 

of compliance and undergo a quality assurance and certification process. 

Commenters stated that EPA's data set is inappropriate, as it includes units that are not among 

those that would be subject to the Proposed Rule, such as the units at the Navajo Generating 

Station (NGS) and Unit 4 at the Sundt Generating Station. Commenters stated that variability in 
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hourly heat input or gross heat rate at units that will not be subject to the Proposed Rule is not 

indicative of an opportunity for heat rate improvement at coal-fired EGUs that would be subject 

to the Proposed Rule.

Commenters stated that Section 2.5.9 of the TSD cites 16 EGUs that EPA claim to have reported 

a single year-to-year heat rate improvement of between 3 and 8%. Commenters stated that 

Document ID EPA-HQ-OAR-2013-0602-0236 indicates that a their unit, Brame Energy Center 

Unit 2, is one of the 16 units EPA lists in support of its analysis, however, they have calculated 

the annual heat rate for Brame Energy Center Unit 2 over the years 2002-2012 using measured 

fuel input and measured generated electricity (gross).

Commenters stated that none of the changes in heat rate from one year to the next involve a 

change of two percent and in fact, these data contradict EPA's analysis entirely - whereas EPA's 

calculations suggest that the heat rate of the unit dropped well below 10,000 Btu/kWh, their fuel 

flow records confirm that the unit has not operated below that level, at least in the past 

decade. Commenters stated that regardless, they are not aware of any upgrades taking place 

during the time period that would account for any heat rate improvements referred to in the TSD 

GHG Abatement Measures. 

Commenters stated that EPA claims to have analyzed independently the improvements in gross 

heat rate that could be achieved by reducing variability in gross heat rate through adoption of 

best practices for operation and maintenance at each of the twelve coal-fired EGU's in Arizona 

[See, docket item EPA-HQ-OAR-2013-0602-0255.xlsx, "GHG Abatement Measures Units," at 

cells J46, J56, J193, J476, J545, J546, J551, J634, J794, J867, J973, and J1043.] Commenters 

stated that however, EPA did not take these unit-specific analyses into account in reaching a 

conclusion regarding the improvements in gross heat rate that could be achieved by reducing 

variability in gross heat rate through adoption of best practices for operation and maintenance at 

the fleet of twelve coal-fired EGU's in Arizona; instead, EPA based its assumption of what is 

purportedly achievable for the fleet of twelve coal-fired EGU's in Arizona on the results of its 

analysis for a larger "study population" of 884 coal- and petroleum coke-fired EGU's. [See, 

docket item EPA-HQ-OAR-2013-0602-17180, "GHG Abatement Measures," at p. 2-16.]

Commenters stated that, even if EPA's analysis were not fundamentally flawed, its results would 

be indicative only of the improvements in gross heat rate which may be achievable for the "study 

population" as a whole, not of the improvements achievable at the coal-fired EGU's in Arizona. 

Commenters stated that EPA's analysis is riddled with fatal errors. 

Commenters stated that EPA improperly interpreted differences in reported hourly heat input as 

reflecting differences in heat rate. Commenters stated that EPA attempts to hide this flaw by 

flagrantly mischaracterizing the analysis that it performed. Commenters referred to the preamble 

to the proposed rule, where EPA describes its analysis as follows.

Commenters used the hourly data to assess variability in the hourly gross heat rates of 

approximately 900 individual coal-fired steam EGUs over the period from 2002 to 2012. 

Commenters stated that specifically, the EPA evaluated the consistency with which individual 

EGUs maintained their hourly heat rates over time. 79 Fed. Reg. at p. 34,860.
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Commenters stated that elsewhere in the docket, in a general description of its "heat rate 

improvement assessment," EPA describes its analysis as follows: “The EPA developed unit-level 

statistics from over 60 million rows of hourly data. We evaluate each unit on its individual 

performance using heat rate variability as an indicator of the application of best practices and 

potential for improvement.” [See, docket item EPA-HQ-OAR-2013-0602-17180, "GHG 

Abatement Measures," at p. 2-16.]

Commenters stated that both of these characterizations are demonstrably false: EPA based its 

analysis on variability in hourly heat input not on variability in hourly gross heat rate and stated 

that variability in heat input is not a measure of efficiency at all.

Commenters stated that for example, in EPA's data set for Unit 1 at the Coronado Generating 

Station, there are 87 hourly records in the bin for 20 to 29 percent capacity factor and 50 to 59 

OF. Commenters stated that the p10 hour identified by EPA is 5/20/2002 at hour 1. Commenters 

stated that the heat input, gross load, capacity factor, and gross heat rate for this hour are 880.3 

MMBtu/hr, 95 MW, 21 percent, and 9,266 lb/MWh, respectively. Commenters stated that EPA 

uses this hour as the point of comparison and the basis for hypothetical improvements (i.e., 

reductions) in heat input for hours in the same bin but having greater heat input. Commenters 

stated that for example, one of the hours for which EPA calculates an improvement is 5/28/2002 

at hour 7. Commenters stated that the heat input, gross load, capacity factor, and gross heat rate 

for this hour are 1,051.5 MMBtu/hr, 114 MW, 25 percent, and 9,224 lb/MWh, respectively.

Commenters stated that notably, relative to the p10 hour, the gross load for the second hour is 

higher by 20 percent and the gross heat rate is lower (i.e., better) by 0.5 percent, however, 

because the heat input during this hour is higher than the heat input during the p10 hour by 19 

percent, EPA calculates an improved heat input for this hour of 1,000.1 MMBtu/hr. Commenters 

stated that EPA assumes that the heat input during this hour should be decreased by 4.9 percent 

while maintaining gross load, improving the gross heat rate to 8,773.2 MMBtu/hr. Commenters 

stated that astoundingly, EPA's sole basis for assuming this improvement in gross heat rate is 

achievable using "best practices" is the fact that the unit had previously operated for an hour at 

substantially lower load and with a slightly higher heat rate. Commenters stated that even 

without correcting for all other errors, simply performing the analysis in a manner that quantifies 

variability in gross heat rate, as EPA purported to do, rather than variability in heat input, as EPA 

actually did, would yield a much lower calculated value for the achievable reduction in CO2 

emission rate for the "study population" as a whole.

Commenters stated that EPA miscalculates the data distribution for certain units and certain 

load/temperature bins, yielding incorrectly identified p10 values and resulting in substantial 

overestimation of the variability in heat input. Commenters stated that for example, in EPA's 

data set for Unit 1 at the Coronado Generating Station, there are 256 hourly records in the bin for 

50 to 59 percent capacity factor and 30 to 39 degrees F. Commenters stated that the p10 hour 

identified by EPA is 11/3/2002 at hour 17 and the heat input for this hour is 1,988.2 MMBtu/hr. 

Commenters stated that using this hour as the point of comparison and the basis for hypothetical 

improvements (i.e., reductions) in heat input for hours in the same bin but having greater heat 

input, EPA calculates an overall 5.7 percent reduction in CO2 emission rate for the hourly 

records in this bin. Commenters stated that however, the hourly record identified by EPA is the 

12th highest heat input among the 256 hourly records in this bin, which does not represent the 

10th percentile. Commenters stated that the hourly record that should have been used is the 25th 
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highest heat input among the 256 hourly records in this bin, which is 2/3/2003 at hour 0. 

Commenters stated that the heat input for this hour is 2,115.6 MMBtu/hr. Commenters stated 

that using the correct hour as the point of comparison, without correcting for any other errors in 

EPA's analysis, yields an overall 4.3 percent reduction in CO2 emission rate for the hourly 

records in this bin. Commenters stated that if the analysis is performed using distribution and 

variability of gross heat rate hourly records rather than heat input hourly records, as discussed 

above, the calculation yields an overall 3.3 percent reduction in CO2 emission rate for the hourly 

records in this bin. 

Commenters stated that EPA's analysis, which corrects for ambient temperature and gross load, 

does not correct for a sufficient number of factors in order to reflect variability which might 

reasonably reflect an opportunity to improve heat rate through improved operating practices. 

Commenters stated that for example, Unit 1 at the Coronado Generating Station switched to PRB 

coal in 2007. Commenters stated that in EPA's data set for this unit, there are 256 hourly records 

in the bin for 50 to 59 percent capacity factor and 30 to 39 OF. Commenters stated that these 

include 166 hourly records in calendar years 2002 through 2006, with average heat input of 

2,356 MMBtu/hr, and 82 hourly records in calendar years 2008 through 2012, with average heat 

input of 2,633 MMBtu/hr. Commenters stated that EPA's assumption that variability in heat 

input or gross heat rate at this coal-fired EGU over this 11-year period is indicative of the level 

of achievable reduction in CO2 emission rate through application of "best practices," with no 

attempt to correct for the step change in heat rate occurring in conjunction with the 

commencement of PRB coal firing in 2007, is invalid. Commenters stated that the analysis 

described above, using distribution and variability of gross heat rate hourly records rather than 

heat input hourly records, but using only the 82 hourly records in this bin for calendar years 2008 

through 2012, yields an overall 1.5 percent reduction in CO2 emission rate. 

Commenters stated that with respect to this coal-fired EGU and this bin, as shown by the 

discussion above, the three significant flaws in EPA's analysis that can be readily corrected led 

EPA to overstate the achievable reduction in CO2 emission rate by a factor of four. 

Commenters stated that EPA erroneously labels any differences in hourly heat input which are 

observed in the data set for a particular EGU and which cannot be explained by differences in 

capacity factor or ambient temperature as "heat rate variability." Commenters stated that EPA 

assumes that this heat rate variability is "attributed to operation and maintenance practices" and 

is indicative of a "potential for heat rate improvement." [See, docket item EPA-HQ-OAR-2013-

0602-17180, "GHG Abatement Measures," at pp. 2-15 and 2-27.] Commenters stated that in 

other words, EPA assumed that each operating hour for which a particular EGU's heat input is 

greater than the heat input during other operating hours for that EGU with similar ambient 

temperature and capacity factor, represents an opportunity to improve upon the EGU's 

performance during that hour. Commenters stated that this assumption is not valid, as EPA's 

analysis did not attempt to take measurement error, and the potentially significant effects of this 

error, into account. Commenters stated that for example, reported hourly heat input data upon 

which EPA relies are based on both diluent concentration monitoring data and exhaust gas 

volumetric flow monitoring data collected pursuant to 40 CFR part 75. Commenters stated that 

the relative accuracy requirements under appendix A to part 75 are 10 percent for diluent 

concentration monitors and 10 percent for exhaust gas volumetric flow monitors. Commenters 
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stated that measurement error in either or both of these parameters has a significant effect on the 

hourly heat input data relied upon by EPA, as illustrated by the following example: 

Assume, at a particular EGU, there are two operating hours with precisely the same actual heat 

input, gross electrical generation, heat rate, exhaust gas oxygen concentration, and exhaust gas 

volumetric flow. The actual values are as follows: 

Exhaust gas flow - 45.00 million scfh

Exhaust O2 concentration - 2.00 percent

Heat input - 3,800 MMBtu/hr

Gross generation - 400 MW

Heat rate - 9,500 Btu/kWh

Commenters stated that the monitored exhaust gas flow and O2 concentration, reported heat 

input and gross generation, and calculated heat rate for the two operating hours are as follows:

Hour 1

Exhaust gas flow - 42.75 million scfh

Exhaust O2 concentration - 2.10 percent

Heat input - 3,591 MMBtu/hr

Gross generation - 400 MW

Heat rate - 8,980 Btu/kWh

Hour2

Exhaust gas flow - 47.25 million scfh

Exhaust O2 concentration - 1.90 percent

Heat input - 4,011 MMBtu/hr

Gross generation - 400 MW

Heat rate - 10,030 Btu/kWh

Commenters stated that each of these hypothetical data sets is entirely plausible and is 

representative of real-world conditions. Commenters stated that in the first hour, the monitored 

exhaust gas flow rate and exhaust gas oxygen concentration are high by 5 percent and low by 5 

percent, respectively; in the second hour, the monitored exhaust gas flow rate and exhaust gas 

oxygen concentration are low by 5 percent and high by 5 percent, respectively. Commenters 

stated that each of the measurement error levels reflected in these examples is well within the 10 

percent relative accuracy permissible under the regulations. Commenters stated that the apparent 

"heat rate variability" is a difference of 1,050 Btu/kWh (gross), or approximately 11 percent. 

Commenters stated that EPA's methodology would assume this variability represents an 

opportunity for heat rate improvement, while in fact it represents nothing more than 

measurement error, permissible under EPA's regulations. Commenters stated that although it 

completely ignores the effect of measurement error on variability in reported heat input and gross 

heat rate for purposes of this analysis, EPA recognizes the significance of measurement error 

elsewhere in the docket for the proposed rule. For example: 

During Relative Accuracy Testing Audits (RATA) testing for stack gas flow meters, Part 75 

allows units to use either the standard Reference Method 2 or an optional method in order to 

increase the accuracy of and to minimize over reporting of CEMS stack gas volumetric flow 

data.... 40 CFR Part 75 specifies that these alternative methodologies are optional. Therefore, 
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there may be inconsistencies between emissions or heat input values when a unit changes the 

reference method used during flow RATAs, which could impact comparisons between emissions 

and heat input between time periods under which different reference methods are used. [See, 

docket item EPA-HQ-OAR-2013- 0602-0461, "Technical Support Document: Part 75 

Monitoring and Reporting Considerations," at p. 7.]

Commenters stated that EPA's data set is inappropriate, as it includes units that are not subject to 

the proposed rule, such as the units at Navajo Generating Station and Unit 4 at the Sundt 

Generating Station (ORIS code 126). Commenters stated that variability in hourly heat input or 

gross heat rate at units that will not be subject to the proposed rule is not indicative of an 

opportunity for heat rate improvement at the coal-fired EGU's which would be subject to the 

rule.

Commenters stated that EPA's inferences with respect to a causal relationship between high 

variability in calculated hourly gross heat rate data and poor heat rate performance are without 

foundation. Commenters stated that EPA observes a positive statistical correlation between the 

level of variability in calculated hourly gross heat rate data and annual gross heat rate (i. e., a 

negative correlation between variability and efficiency). Commenters stated that from this 

observation, EPA draws a critical inference regarding causal relationship: 

Commenters stated that these results indicate that, other factors held equal, if an EGU reduces 

heat rate variability, generally heat rate performance will improve. [See, docket item EPAHQOAR- 2013-0602-17180, "GHG Abatement Measures," at p. 2-28.]

Commenters stated that however, as discussed previously, the "heat rate variability" on which 

EPA relies so heavily is not necessarily an indicator of actual changes in heat rate performance. 

Commenters stated that to at least an extent, this observed correlation is an indicator that units 

with better heat rate performance have more accurate part 75 monitoring systems. Commenters 

stated that while a laudable goal, improving the performance of part 75 monitoring systems is not 

a viable method of reducing CO2 emissions. Commenters stated that EPA's assumptions 

regarding the magnitude of improvements in gross heat rate achievable through adoption of best 

practices for operation and maintenance are invalid. Commenters stated that having incorrectly 

labeled all differences in hourly heat input or calculated hourly gross heat rate which are 

observed in the data set for a particular EGU and which cannot be explained by differences in 

capacity factor or ambient temperature as opportunities for potential improvement in gross heat 

rate, EPA assumes, without explanation, that these improvements are achievable through 

"practices such as turning off unneeded pumps at reduced loads, installation of digital control 

systems, more frequent tuning of existing control systems, or earlier like-kind replacement of 

worn existing components." [79 Fed. Reg. at p. 34,860]. Commenters stated that although it is 

incontrovertible that these practices are potential methods for improving heat rate performance at 

a given EGU at which they have not already been implemented, EPA has provided no data or 

information whatsoever connecting these practices to its assumptions regarding achievability, 

costs, and overall reasonableness of improvements in gross heat rate. Commenters stated that 

instead, EPA's estimate of a four percent across-the-board improvement reflects nothing more 

than a completely arbitrary fraction of the variability in hourly heat input which EPA erroneously 

believes it has observed in the data set for its "study population:" 
192

Commenters stated that assuming that between 10 percent and 50 percent of the deviation from 

top decile performance in each subset of hourly heat rate observations within defined ranges of 

temperature and load could be eliminated through adoption of best practices, the result is a 

corresponding estimated range of 1.3 percent to 6.7 percent technical potential for improvement 

in the average heat rate of the entire fleet of coal-fired EGUs. Commenters stated that based on 

this analysis, they believe a reasonable estimate for purposes of developing state-specific goals is 

that affected coal-fired steam EGUs on average could achieve a four percent improvement in 

heat rate through adoption of best practices to reduce hourly heat rate variability. Commenters 

stated that this estimate corresponds to the elimination, on average across the fleet of affected 

EGUs, of 30 percent of the deviation from top-decile performance in the hourly heat rate for 

each EGU not attributable to hourly temperature and load variation. [79 Fed. Reg. at p. 34,860]. 

Commenters stated that in addition to the analysis of hourly data discussed above, EPA offers 

another explanation for its arbitrary assumption that four percent improvement in gross heat rate 

is achievable, based on a more simplistic analysis of data for the same "study population:"

[I]f each unit achieved heat rate performance equal to its best three-year moving average, the 

study population as a whole would post a 3.9% heat rate improvement. [See, docket item EPAHQ-OAR-2013-0602-0437, "GHG Abatement Measures," at p. 2-34.]

Commenters stated that this explanation is similar to, and even less technically supportable than, 

the first. Commenters stated that the following example, involving a unit at which a change in 

coal source was implemented, will illustrate the utter lack of reason underlying EPA's 

conclusion. Commenters stated that at Coronado Unit 2, owned and operated by SRP, the 

average gross heat rate from 2004 through 2006 was 9,257 Btu/kWh, the best three-year average 

for this EGU during EPA's study period. Commenters stated that following a switch to PRB coal, 

the average gross heat rate from 2007 through 2011 was 9,827 Btu/kWh and this represents an 

increase in gross heat rate of approximately six percent, at least in part due to the higher moisture 

content of PRB coal. Commenters stated that the only sensible conclusions that can be drawn 

from these data with respect to "building block 1" are that switching to a high-moisture coal, 

such as PRB coal, causes an increase in heat rate which can be reversed by switching to a lowmoisture coal. Commenters stated that EPA incorrectly characterizes this change as "heat rate 

variability" which can be reversed through "practices such as turning off unneeded pumps at 

reduced loads, installation of digital control systems, more frequent tuning of existing control 

systems, or earlier like-kind replacement of worn existing components." 79 Fed. Reg. at p. 

34,860. Commenters stated that having failed to identify the cause of the increase in heat rate 

(i.e., switching to PRB coal) and the potentially available method of reversing it (i.e., switching 

to low-moisture coal), EPA completely fails to assess the economic and non-GHG environmental 

impacts of this technique for improving heat rate. 

Commenters stated that the flawed analysis described above is critical to EPA's conclusions with 

respect to reductions in CO2 emissions achievable in Arizona under "building block 1." 

Commenters stated that the goal computation for the State of Arizona must be corrected to 

remove the effect of unfounded assumptions regarding improved heat rate performance 

achievable through implementation of best practices for operation and maintenance of coal-fired 

EGU's. 
193

Commenters stated that the second part of EPA's heat rate building block was to look at units

EPA claims have achieved large heat rate improvements based on Acid Rain CO2 reported data. 

Commenters stated that it is interesting to note that RPS-2, a unit that EPA's IPM model has 

designated for retirement, was one of only sixteen units selected in an attempt to justify a 6% 

reduction target for heat rate and CO2 emissions in Building Block 1 of the proposed limit on 

CO2 emissions. Commenters stated that while the EPA's misinterpretation of RPS-2 data makes 

that unit's contribution to the EPA's analysis invalid, the EPA's reliance on data from a unit it has 

slated for retirement points out an even more widespread flaw in that the units most susceptible 

to any improvements are older units which would be more likely to be retired in order to achieve 

CO2 emission reductions. Commenters stated that extrapolating data from older units to newer 

units where control and turbine upgrades have already been installed is illogical, at best.

Comment 15: Comments regarding CEMS methodology changes and the potential impact on 

heat rate

Response 15: For the EPA’s response to these comments, see section V.C of the final rule 

preamble of the CPP and Chapter 2 of the GHG Mitigation Measures TSD supporting the final 

CPP. Furthermore, the EPA recognizes that the degree to which individual coal-fired EGUs can 

implement heat rate improvement measures will vary, but believes that its overall methodology 

is an appropriate way to develop a conservative estimate of what regional populations of EGUs 

are capable of achieving on average.

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

Commenters stated that the CPP should include in its evaluation of heat rate improvements the 

variability of continuous emissions monitoring systems (CEMS) in the heat rate improvements 

identified in the CPP's support documentation. Commenters stated that the use of CEMS is the 

most precise method of measurement for power plant stack emissions, however the method has 

many component changes and system characterization changes that impact data outputs and 

much of the heat rate improvement identified by the 16 plants used by the EPA resulted from 

changes to the CEMS air flow data measurement and calculation and not actual emission 

reductions or heat rate improvements. Commenters experienced the same results in prior years 

showing reductions in emissions by 3%-7% by replacing CEMS probes with newer more 

accurate equipment and re- characterization of the CEMS flow monitors and calculations and the 

more accurate data shows lower stack gas flows and therefore lower emissions. Commenters 

stated that the CPP should take out the variability of CEMS configuration changes in establishing 

h eat rate improvement targets.

Commenters stated that EPA used data reported to the Clean Air Markets Division (CAMD) over 

the period from 2002 to 2012 as the basis for its statistical analysis of heat rate variability. 

Commenters stated that originally designed to capture emission data to support the emission 

allowance trading program created by the 1990 CAA Amendments, the requirements for 

reporting data to CAMD have evolved significantly over time and many changes have occurred 

over this period that contribute to the variability in the heat rate data, yet these inherent sources 

of variability were not addressed in EPA's analysis:
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• Continuous Emissions Monitoring Systems (CEMS) Flow monitor 

changes/upgrades. Allowable switching between redundant monitors and 

acceptable calibration ranges could result in as much as a 3% change in flow.

• Measurement instrumentation and locations may have changed as a result of 

emissions controls retrofits or other changes which may have occurred on the 

units.

• In 2008 EPA changed its fuel-specific emission factor (F-factor) requirement for 

CEMS reporting. On units firing bituminous fuel, this change would be 

interpreted as a 2% increase in heat input (2.2% degradation of heat rate).

• EPA's QA/QC steps and overall processes for reporting data have evolved over 

the years. Data from 2009 forward is likely to be the most homogeneous because 

of more widespread use of Emissions Collection and Monitoring Plan System 

(ECMPS) by reporting sources.

• Allowable Relative Accuracy Test Audit (RATA) flow instrument recalibration is 

typically less than +/-7.5%, but can be +/-10% or more. 

Commenters stated that these changes contribute to the overall range of variability in unit heat 

rates calculated based on the CAMD data and undermine the validity of EPA's analysis to 

determine an across-the-board recommendation for heat rate improvement and that EPA made no 

effort to identify the effect of these changes in data reporting protocols, or to eliminate their 

impact before determining the range of potential heat rate improvement at coal-fired power 

plants.

Commenters stated that in EPA's GHG Abatement Measures Technical Support Document, EPA 

points to large heat rate improvements via equipment upgrades that could be replicated on other 

EGUs. Commenters stated that however, in many of the cases where EPA believed an efficiency 

improvement occurred, the reality is the perceived efficiency improvement was actually just the 

result of a change in continuous emission monitoring system reporting methodology and not the 

result of an equipment or operational change to lower heat rate. Commenters stated that the 

actual heat rates did not improve and that rather, a more accurate assessment of air flow through 

the stack caused the units to report an apparent improved heat rate.

Commenters stated that EPA relied on a data analysis of emissions from sixteen units that were 

reported to the Clean Air Markets Division, using Part 75 emissions data, to demonstrate that 

coal-fired units could achieve a 6 percent or greater improvement in heat rate. Commenters 

stated that the EPA reliance on this data apparently was misplaced because in an analysis 

submitted to EPA by UARG, at least 14 of the 16 units EPA looked at had undertaken no 

measures to improve heat rate, or they had undertaken such measures to partially counteract the 

heat rate penalty resulting from concurrently installing emission control technologies with 

parasitic loads. Commenters stated that the changes in heat rate that EPA identified were, 

apparently, associated with normal variations in the CEMS measurement/calculation of the gross 

heat rate from the units. Commenters stated that the unit owners all confirmed that there is little 
195

or nothing at the plants that would support the conclusion EPA reached regarding the heat rate 

improvement that EPA reached based on the emissions data alone.

Commenters summarized the EPA's use of the Sixteen Unit study as justification for the 

proposed 6% HRI Commenters stated that contrary to EPA's assertions, the Cichanowicz Report 

demonstrates that in most cases the reported heat rate annual reductions EPA associated with the 

sixteen units resulted not from heat rate-improving measures, but from changes in CEMS 

operation, thus belying EPA's claim.

Commenters augmented UARG's Sixteen Unit analysis with a separate study utilizing data from 

four cooperatives' generators operating nine coal-fired EGUs. Commenters stated that 

specifically, reported gross heat rates for nine units operated by Associated Electric, Basin 

Electric, Seminole Electric, and Sunflower Electric were examined and further stated that almost 

every unit exhibited gross heat rate reductions of 5% or more in any given year, over the period 

from 2002 through 2011. Commenters stated that in the majority of these cases, the reported 

gross heat rate reduction was due to a change in CEMS operation. 

Commenters stated that EPA incorrectly relied on 16 "reference units" to support their claims 

that a six percent heat rate improvement is achievable at all existing coal-fueled power plants and 

that after reviewing the reference units, EPA concludes that the units have already achieved a 

three to eight percent heat rate improvement. Commenters stated that however, of the 16 

reference units selected by EPA, an analysis of 14 of those units suggests that EPA's incorrectly 

interpreted the heat rate data from those units. Commenters stated that ten of the fourteen plants 

analyzed report that the heat rate improvements observed by EPA were not reflective of actual 

improvements in heat rate performance achieved by the plants, but instead represented variability 

in, or problems with, the accuracy of the Continuous Emissions Monitors (CEMS) from which 

heat rate improvement data was derived and that in addition, in some cases in which EPA 

determined heat rate improvement had occurred, improvements were later offset by installation 

of pollution control equipment required by subsequent regulations, like CSAPR and MATS.

Commenters stated that the "heat rate variability" upon which EPA heavily relies is not 

necessarily an indicator of actual changes in heat rate performance. Commenters stated that to at 

least an extent, this observed correlation is an indicator that units with better heat rate 

performance may have more accurate 40 CFR Part 75 monitoring systems, or are using alternate 

measurement methods allowed under 40 CFR Part 75; while a laudable goal, improving the 

performance of Part 75 monitoring systems is not a viable method of reducing CO2 emissions. 

Commenters stated that EPA's heat rate analysis is flawed. Commenters explained that to 

maintain Continuous Emission Measurement System (CEMS) certification, a Relative Accuracy 

Testing Audit (RATA) must be completed periodically. Commenters stated that if the stack flow 

reading differs from the reference method by more than 10%, then the stack flow meter must be 

recalibrated and another RATA must be completed. Commenters stated that even if the RATA is 

completed successfully, if the stack flow reading is less than the reference method, then a Bias

Adjustment Factor (BAF) must be multiplied to the stack flow real-time readings until another 

RATA is completed. Commenters stated that the application of the BAF offset presents an issue 

concerning the accuracy of the Heat Input rate calculations. Commenters stated that the reported 

Heat Input rate could be significantly larger than the measured Heat Input rate, which could 
196

falsely indicate potential for improvement. Commenters stated the EPA should revise its heat 

rate analysis to account for this positive CEMS based heat rate bias. Commenters further stated 

that EPA calculated unit heat rates incorrectly for units sharing a common stack and emissions 

monitoring system. Commenters stated that for example, their Colbert Fossil Plant (COF) units 

1-4 exhaust to the same single stack. Commenters stated that EPA used individual unit heat rates 

in their bin analysis, prorating each unit's load to assume heat rates for units 1-3 (included in 

EPA's sixteen units used as examples for potential heat rate improvements). Commenters stated 

that prorating the heat rate based on generation is invalid and assumes that all 4 units at COF 

perform at the same level. Commenters stated that EPA should revise its analysis and exclude 

units which share a common stack and emissions monitoring system. Commenters also stated 

that EPA incorrectly used gross heat rates instead of net heat rates when determining heat rate 

improvement potential. There are many actions that can cause gross heat rate to decrease while 

the net heat rate increases due to increasing station service (e.g., replacing steam jet air pumps 

with vacuum pumps, run pulverizers harder to increase the fineness of the coal, turn on an 

additional circulating water pump to promote better heat transfer in the condenser, etc.). 

Commenters stated that net heat rate accounts for the auxiliary power consumption required to 

operate the machinery in the plant. Commenters stated that this maintains a holistic view of plant 

performance and captures the effect of all changes, including emissions controls that change 

auxiliary power consumption. Commenters stated that EPA should base its heat rate analysis on 

net heat rate data to ensure that utilities can capture the impact of any efficiency improvement 

that reduces the amount of carbon per net unit of energy produced by the generating unit.

Commenters stated that EPA relies heavily on its analysis of historical CEMS-derived gross heat 

rate data from "16 EGUs that reported a single year-to-year heat rate improvement of 3-8%." 

GHG Abatement Measures TSD at 2-32; see also "GHG Abatement Measures Units with Heat 

Rate Changes," Docket ID No. EPA-HQ-OAR-2013-0602-0236 (listing the 16 identified units). 

Commenters stated that according to EPA, significant year-to-year improvements at all other 

units in the study population were due to "changes in capacity factor, reporting method, or other 

events." GHG Abatement Measures TSD at 2-32. Commenters stated that for two of the sixteen 

units, the Agency claims to have identified "equipment upgrades" that EPA speculates are 

"responsible for 2-3% heat rate improvement" based on estimates contained in the 2009 Sargent 

& Lundy report, while concluding that unspecified equipment upgrades were "the most likely 

cause of some of the observed heat rate improvements" at the remaining fourteen units. Id. 

Commenters assumed that EPA never contacted the owners of these units to determine what 

factors were responsible for the apparent reductions. Commenters stated that their consultants, 

however, contacted the owners of the sixteen units EPA singled out in the TSD in order to 

determine the cause of these reported year-to-year heat rate improvements. [J. Edward 

Cichanowicz & Michael C. Hein, "Critique of EPA's use of reference units to select heat rate 

reduction targets" (Nov. 25, 2014) ("Cichanowicz Reference Unit Report")]. Commenters also 

stated that based on discussions with the owners of these units, in virtually every case the EPAcalculated heat rate improvement was due to a change in stack flow monitor calibration or other 

unrelated sources of normal variability in CEMS measurements and were not the result of 

purposeful efforts to improve unit efficiency. [Id. at 1; Ralph L. Roberson, "Real Heat Rate 

Improvement or Measurement Variability/Uncertainty" at 8 (Nov. 25, 2014) ("Roberson 

Report") (Attachment G)]. Commenters included Figure 3 in their comments, which summarizes 

the reported causes of observed CEMS-derived heat rate improvements at each of the sixteen 

units. Commenters stated that the reported heat rate improvements do not reflect actual changes 
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in unit efficiency or reductions in unit CO2 emission rates. Commenters stated the owners of 

eleven units report that all changes are due to unrelated variability in the CEMS-based 

measurements. Cichanowicz Reference Unit Report at 1. Commenters stated that some units did 

report significant initial heat rate improvements from equipment upgrades, such as upgrading the 

steam turbine, but these improvements were generally more than offset by increases in net heat 

rate due to the retrofit of environmental controls. Id.

Commenters stated that two of the 12 owners whose combined 16 units were identified based on 

a statistical analysis of the hourly gross heat rate values for 884 electric generating units, 

refurbished the steam turbine and the boiler, and replaced legacy wet FGD equipment with a dry 

process - actions that historically have prompted EPA to designate these EGUs as a new source. 

Commenters stated that net heat rate increased from between one to several percentage points, 

primarily due to the higher auxiliary power required due to either or both environmental controls 

or cooling towers. Commenters further stated that EPA's analysis illustrates that CEMS-based 

heat input data are too variable to adequately quantify relatively small (e.g., 6%) annual changes 

in gross heat rate and that numerous observations demonstrate that CEMS-based heat input data 

can be influenced by numerous factors unrelated to actual changes in a unit's heat rate, including 

the allowed error inherent in all CEMS measurements, routine annual changes in stack gas flow 

monitor calibration to better equate to manual reference methods, changes in flow methods used 

in flow monitor calibrations to compensate for stack flow characteristics, physical changes in 

flue gas handling systems, and changes in CEMS and CEMS technologies. Commenters referred

to the 2014 RMB CEMS Uncertainty Analysis. Commenters took exception to the details of 

EPA's statistical analysis determining variability in heat rate of the 884 units in the national 

inventory, as observed from 2002 through 2012. Commenters stated that EPA ignores important 

factors such as changes in coal properties and the temperature of cooling water (as opposed to 

air) - factors admittedly difficult to generalize over the national inventory. 

Commenters stated that in RMB's experience, the determination of accurate volumetric stack 

flow rates is the most challenging and that all measurements have inherent error and uncertainty, 

and any one of the above factors can result in significant year-to-year variability in 

measurements. Commenters concluded that EPA's claim that it eliminated other possible 

explanations for the calculated heat rate improvements in its 16 reference units is both 

unsubstantiated, and directly contradicted by the very real sources of variability identified by the 

units' owners and the information they report to Part 75. Commenters asserted that had EPA 

gone to the effort to review relevant information in those reports, or acknowledged the very real 

and obvious sources of normal variability in the Part 75 heat input measurements, EPA would 

have realized that its analysis supporting a 6 percent heat rate improvement is not defensible. In 

reality, Commenters stated, EPA's analysis is quantifying nothing more than measurement 

variability. Commenters stated EPA's analysis is not measuring a real change in heat rate and 

certainly not an improvement in heat rate.

Commenters stated that EPA identified sixteen units it claims have exhibited reductions in heat 

rate varying between 3-8% over the period from 2002 through 2012. Commenters stated that the 

EPA's basis for designating these units as examples of available heat improvement range is 

flawed as most apparent reductions in heat rate are not actual improvements in performance but 

an artifact of changing stack gas measurement protocols. Commenters stated that trends in heat 
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rate vs. load for these units are examined despite concerns for the suitability of the CEMS data 

from which the heat rate trends are inferred.

Commenters stated that EPA's discussion in the GHG Abatement Measures TSD also relies 

heavily on 16 reference units that purportedly achieved large heat rate improvements via 

equipment upgrades that EPA assumed could easily be replicated elsewhere. Commenters stated 

that in virtually every case, the owners stated that the reported heat rate improvement was related 

to a change in CEMS reporting methodology and not the result of an equipment or operational 

change that was undertaken to lower heat rate. Commenters stated that the actual heat rates did 

not improve, rather, a more accurate assessment of air flow through the stack caused the units to 

report an apparent improved heat rate. Commenters stated that other units did attain modest 

improvements in heat rate through equipment upgrades, but these improvements were more than 

offset by decreased unit efficiency due to retrofit of environmental controls.

Commenters stated that EPA's calculation of heat rate requires knowledge of heat input and heat 

input is calculated and reported pursuant to Part 75 requirements using CEMS (usually a CO2 

monitor and a flow monitor). Commenters stated that in RMB's experience, the determination of 

accurate volumetric stack flow rates is among the most challenging air pollution measurements 

to make. Commenters stated that the observations that CO2 emissions for EGUs, which are 

calculated from CEMS measurements, contain inaccuracies is not unique to this memorandum 

(memorandum from RMB Consulting & Research, Inc. discussing the real heat rate 

improvement or measurement variability/uncertainty). Commenters stated that a peer reviewed 

paper critiquing CEMS-based CO2 emission data was published earlier this year. Commenters 

stated that given the uncertainty and variability associated with determining EGU volumetric 

flow rates, which ultimately are used to calculate heat input rates, EPA's analysis supporting a 6 

percent heat rate improvement is not defensible, rather in reality, EPA's analysis is quantifying 

nothing more than measurement variability. Commenters stated that EPA's analysis is not 

measuring a real change in heat rate and certainly not an improvement in heat rate.

Commenters stated that by calculating unit-specific heat rates using CEMS data, postcombustion controls including selective catalytic controls and flue gas desulfurization do not 

appear to have been considered. 

Commenters stated that EPA should also take notice that under Part 75 (the Acid Rain Program); 

the accuracy reading for flow monitor is +/- 7.5%. Commenters stated that with the variability of 

accuracy of the monitor being greater than the expected increased efficiency there could be 

technical issues demonstrating compliance. 

Comments providing unit specific data regarding CEMS-derived reported gross heat rate 

variability 

Commenters stated that they believe that the methodology used in Block 1 to determine heat rate 

improvement goal assumptions is faulty. Commenters stated that in determining the potential 

Block 1 heat rate improvement, EPA performed a statistical analysis of the hourly 40 CFR, Part 

75 reported heat input and load data from over 900 EGUs for the period from 2002 until 2012 

(Fed. Reg. Page No. 43860). Commenters stated that the 40 CFR, Part 75 methodology 

determines heat input by multiplying the CEMS measured stack flue-gas flow rate, times a fuel 
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specific carbon-based factor, times the CEMS measured CO2 concentration. Commenters stated 

that it is likely that most of the 900 EGUs used in the EPA Block 1 analysis began using a more 

accurate stack flow monitor Relative Accuracy Test Audit (RATA) reference test method during 

the evaluation period which resulted in artificial drops in unit heat rates opposed to actual heat 

rate improvement projects. Commenters stated that for example, their Rawhide Unit 101 began 

utilizing the more accurate RATA flow monitor (EPA Reference Method 2F/H) during the 

October 2006 RATA. Commenters stated that the change in flow monitor reference methods 

from EPA Method 2 to EPA Method 2F/H resulted in approximately 12% lower stack flow rate 

and consequently the same percent reduction in the Part 75 calculated unit heat input and gross 

heat rate. Commenters stated that the Craig EGUs began using the more accurate RATA flow 

monitor reference methods (EPA Method 2G/H) in 2003. Commenters stated that the change in 

RATA reference methods also resulted in lower Part 75 reported stack gas flow rates and Part 75 

calculated unit heat inputs and heat rates. Commenters stated that consequently, unless the EPA 

analysis included corrections to account for the RATA reference method changes its analysis is 

flawed and must be adjusted for the lower Part 75 flow monitor measurements resulting from the 

change in RATA reference method. Commenters stated that depending on stack characteristics 

and degree of cyclonic flow, the reference method change may have reduced Part 75 reported 

flow rates and heat inputs by upwards of 15%. 

Commenters noted facility specific data with regards to variability in CEMS-derived reported 

gross heat rate. 

Commenters reported that in two instances - for Colbert Units 1-3 and Gibson Unit 1 - EPA 

computed unit-level gross heat rate from reported common stack CEMS measurements that were 

apportioned to individual units based on load but because that apportionment procedure, which is 

allowed under Part 75, assumes that the units serving the common stack have identical heat rates, 

the CEMS data are not useful in evaluating individual heat rate.

Commenters listed eight owners of 11 units who report all changes are due either exclusively or 

almost exclusively to unrelated normal or routine variability in CEMS heat input measurements, 

where the most frequently cited source of variation is the routine recalibration of the stack flow 

monitor in conjunction with an annual RATA (as noted in a companion report to this analysis, 

stack flow monitor recalibration is a key - but not the only - contributor to CEMS measurement 

uncertainty.)

Commenters further listed several owners who reported significant changes as a result of using 

more accurate manual test methods when performing that recalibration 

Commenters referred to five owners of five units who report that upgrading the steam turbine 

lowers gross and/or net heat rate, with most deriving a payoff of approximately 3%. Commenters 

stated that in some cases (Dave Johnson Unit 4, Gibson Unit 1) the heat rate improvement was 

not recognized by the CEMS-derived gross heat rate but by coal consumption rate data, calling 

into question the ability of EPA's methodology to detect changes in heat rate.

Commenters stated that for three owners the heat rate payoff from steam turbine retrofit was 

negated by an increase in net heat rate due to retrofit of environmental controls and an increase 

in auxiliary power consumption; specifically, AES observed a net heat rate increase for 
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Petersburg Unit 2 in 2005, following retrofit of SCR in 2004. Commenters also reported that 

Duke Energy incurred higher net plant heat rate for Gibson Unit 1 starting in 2007, when FGD 

was retrofit and gas handling was changed to employ a single dedicated stack and, similarly, 

Xcel Energy incurred a higher net plant heat rate due to retrofit of dry FGD, associated gas 

handling equipment, and cooling towers.

Commenters further stated that the importance of abandoning gross heat rate and using net heat 

rate as the key metric is demonstrated by the experience of two units that both refurbished the 

boiler, upgraded the steam turbine, and replaced a 70s-era "first generation" wet FGD process 

with dry FGD. Commenters stated that Pacificorp Dave Johnston Unit 4 completed these actions 

and although CEMS-derived gross heat rate was reduced by over 10%, net heat rate lowered only 

1%. Commenters stated that the change in CEMS operating conditions from wet to dry may have 

contributed to the high reported reductions. Commenters stated that similarly, Xcel Energy 

refurbished Allen S. King Unit 1, an extensive project conducted under the auspices of a 

Minnesota state initiative x but that the project reported significant gross heat rate improvement, 

while net heat rate actually increased several percentage points due to the increase in plant 

auxiliary power, particularly due to cooling towers.

Commenters further stated that changes in coal characteristics such as fuel moisture content and 

furnace slagging can affect boiler thermal efficiency and unit gross and net heat rate, and the 

processing of ash and sulfur affect auxiliary power and net heat rate are believed to be important 

to net and gross heat rate but were not considered by EPA.

Commenters stated that EPA identified 16 units, based on the results of their statistical analysis, 

that EPA concludes are examples of equipment upgrades that achieved 3-8% gross heat rate 

reductions and that EPA claims that after accounting for "capacity factor, reporting method, or 

other events," these 16 units emerged from the national inventory and reported a single yearover-year improvement in gross heat rate of at least 3-8%. Commenters stated that the sixteen 

units, owned by twelve utilities, were identified in a table posted in the rulemaking docket. 

Commenters further stated that they contacted and received technical responses from 10 of the 

12 owners, addressing 14 of the 16 units, and that their investigation found that:

• Eight owners of eleven units report all changes are due either exclusively or 

almost exclusively to variability in CEMS heat input measurements. The most 

frequently cited CEMS-based action was the routine calibration of the stack flow 

monitor in conjunction with an annual relative accuracy test audit ("RATA"). The 

units reporting this experience are Rodemacher unit 2; Valmy unit 2; Southwest 

unit 1; Johnson unit 2; Sheldon unit 1; Bridger unit 3; Colbert units 1-3; Weston 

unit 3; and Gorgas unit 2.

• Southwest unit 1 upgraded its steam turbine in 2010, and a pre- vs. post-upgrade 

comparison suggests this action delivered a gross heat rate reduction of 2%. 

However, the accuracy of the CEMS-informed heat rate improvements is 

questionable - the same data suggested a 15% heat rate reduction from 2002 

through 2008, when no actions were taken. 
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Commenters stated that the preceding observations suggest that CEMS-derived heat rate data is 

more often influenced by changes to reporting methods, and not proactive steps to lower heat 

rate. Commenters further stated that AEP charted a similar experience at its Mountaineer Plant 

and that full load gross unit heat rates calculated from CEMS data were charted using hourly 

gross loads from the EPA dataset. Commenters presented a graph that shows a more significant 

reduction in heat rate occurred as a result of CEMS measurement procedure changes than 

occurred with efficiency improvement projects which coincided with the FGD installation.

Commenters stated that the gross heat rates from the 16 units, including Alabama Power's Plant 

Gorgas Unit 10, were calculated by EPA from heat input data reported to EPA under the Acid 

Rain Program using data from continuous emissions monitoring systems ("CEMS") that are 

subject to 40 C.F.R. Part 75 (specifically stack gas volumetric flow monitors and CO2 CEMS). 

Commenters stated that EPA appears to conclude, based on data from these 16 units, that a 

change in CEMS-based heat rates is the result of a change in unit efficiency when it may, in fact, 

just reflect a change in the relative accuracy of the CEMS.

Commenters stated that the Part 75 regulations require CEMS to undergo a Relative Accuracy 

Test Audit ("RATA") on either a semi-annual or annual basis, depending on the relative accuracy 

("RA") of the most recent RATA. Commenters described that a RATA compares a series of 

measurements from the CEMS to measurements using EPA reference method tests, that a RA of 

10.0 percent is required and that, from year to year or from one RATA to another, the RA can 

change plus or minus 10 percent and meet Part 75 requirements. Commenters stated that 

therefore, it is inappropriate for EPA to conclude that a change in CEMS-based heat rates is the 

result of a change in unit efficiency when it may more likely be a change in the relative accuracy 

of the CEMS.

Commenters further stated that their company and Alabama Power Company have researched 

EPA's finding regarding Plant Gorgas Unit 10. Commenters stated that, according to CEMSbased data, Plant Gorgas Unit 10 reported improvements in annual gross heat rate from 2003 to 

2004, and that they believe the improvement is largely due to the variability and relative 

accuracy associated with using CEMS-based heat input data. Commenters stated that EPA 

references an article which details air in-leakage repairs performed at Plant Gorgas Unit 10, and, 

while these repairs resulted in boiler efficiency improvements, the article highlights that the 

realized heat rate improvements were not in fact sustainable. Commenters stated that EPA 

ignores this critical point both in this particular case and generally across the industry.

Commenters stated that Dave Johnston Units 2 and 4, and Jim Bridger Unit 3 were cited as 

examples of units with significant improvements in heat rate during this period, but that 

however, the actual net unit heat rates calculated from coal consumed during this period show 

that the performance for these units did not increase significantly. Commenters stated that EPA's 

use of the CEM based gross heat rates for these units are in error for various reasons. In 

summary:

Dave Johnston Unit 2 - Commenters stated that gross unit heat rate appeared to improve because 

the CEM calculated gross unit heat input decreased when the stack temperature measurement 

was recalibrated in 2008
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Dave Johnston Unit 4 - Commenters stated that gross unit heat rate appeared to improve when 

stack gas flow measurement improved with the installation of a new scrubber and stack in 2012

Jim Bridger Unit 3 - Commenters stated that gross unit heat rate appeared to improve when the 

stack flow monitor was replaced and calibrated in 2005.

Commenters stated that when reviewing historical data, a typical overhaul of a generating unit 

may restore 2%-3% of a unit's net heat rate which has degraded since the previous overhaul. 

Commenters stated that a steam turbine upgrade may produce a step improvement in net unit 

heat rate of 3%-4% and a heat rate improvement of greater than 5% most likely indicates a 

measurement or calculation error.

Commenters stated that the EPA analysis calculated gross unit heat rate from CEM data. 

Commenters stated that the calculation uses generator megawatt (MW) output as recorded by the 

CEM and gross unit heat input (GUHI) as calculated by the CEM. Commenters stated that the 

GUHI is calculated from four measured variables: stack temperature, stack barometric pressure, 

stack gas flow, and stack gas CO2 content. Commenters stated that the EPA did not calculate net 

unit heat rate because the net unit MW output is not recorded in the CEM data. Commenters 

stated that utilities generally measure generating unit performance with net unit heat rate. 

Commenters stated that EPA assumes that a reduction in gross unit heat rate will also result in a 

commensurate reduction in net unit heat rate.

Dave Johnston Unit 2 - Commenters stated that monthly average gross heat rates calculated from 

the CEM data are plotted on Chart 1 which was prepared by J. Edward Cichanowicz, a 

consultant for UARG. Commenters stated that the chart shows an apparent improvement in heat 

rate of about 12% in early 2008. Commenters stated that Chart 2 is a plot of the net unit heat 

rates for the same period and the monthly net unit heat rates are calculated from reported coal 

consumed, coal heat content, and net unit output. Commenters stated that the scatter of monthly 

heat rate values is caused by:

• Number of shut downs and startups each month

• Different monthly load profiles

• Differences in coal inventories in unit silos or bunkers at the end of each month

• Differences in ambient conditions

• Equipment problems

• Book adjustments to fuel inventories

Commenters stated that the 24 month moving average reduces the scatter and shows the true 

trend of unit performance and the actual net unit heat rate was trending upward (becoming 

poorer). Commenters stated that the 12% improvement in heat rate in 2008 does not exist.

Commenters stated that Records of the Relative Accuracy Tests (RATA) were reviewed and the 

records indicate that the CEM stack temperature measurement was in error during 2007 and was 

indicating low. Commenters stated that this measurement error resulted in the GUHI being 
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overstated by approximately 12%. Commenters stated that the instrument error was corrected in 

early 2008 during a scheduled RATA test and this recalibration of the stack temperature 

measurement resulted in a step reduction in GUHI and a corresponding step improvement in heat 

rate calculated from the CEM data.

Dave Johnston Unit 4

Commenters stated that the venturi scrubber and short stack were replaced with a dry scrubber, 

baghouse, and new taller stack during the maintenance outage in early 2012. Commenters stated 

that the new stack and CEM arrangement enabled a more accurate measurement of flue gas flow 

in the stack. Commenters stated that the flue gas flow was overstated with the old arrangement. 

Commenters stated that monthly average gross heat rates calculated from the CEM data are 

plotted on Chart 3. Commenters stated that this chart was prepared by J. Edward Cichanowicz, a 

consultant for UARG and the chart shows an apparent improvement in heat rate of about 21% in 

early 2012.

Commenters stated that Chart 4 is a plot of the net unit heat rates for the same period. 

Commenters stated that the monthly net unit heat rates are calculated from reported coal 

consumed, coal heat content, and net unit output. Commenters stated that the steam turbine was 

overhauled in April 2009, the boiler and balance of plant equipment were overhauled during the 

April 2012 maintenance outage when the scrubber and stack were commissioned and net unit 

heat rate improved about 1% as a result of the April 2012 outage. Commenters stated that the 

improvement is attributed to:

• Replacement of venturi scrubber with spray drier and baghouse which reduced 

auxiliary power requirements 

• Overhaul of boiler and plant equipment which recovered heat rate degradation

Jim Bridger Unit 3

Commenters stated that monthly average gross heat rates calculated from the CEM data are 

plotted on Chart 5 which was prepared by J. Edward Cichanowicz, a consultant for UARG. 

Commenters stated that the chart shows an apparent improvement in heat rate of about 11% 

during calendar year 2005. Commenters stated that Chart 6 is a plot of the net unit heat rates for 

the period of 2002-2013.Commenters stated that the monthly net unit heat rates are calculated 

from reported coal consumed, coal heat content, and net unit output and this data shows an 

improvement of about 3.5% improvement; however, most of this "improvement" is the result of 

inventory adjustments. Commenters stated that if the inventory adjustments are removed, the 

actual heat rate trends down approximately 1.7%.

Commenters stated that there was no maintenance overhaul of the generating unit or change in 

operating practice that could have improved the actual unit heat rate in the manner indicated by 

the CEM data in 2005. Commenters stated that the stack flow monitor was replaced on March 8, 

2005 and a RATA test was performed shortly after the flow monitor was changed. Commenters 

stated that the heat input calculated by the CEM was higher than the heat input calculated from 

the measured coal consumed and measured coal heat content. Commenters presented a table 

showing that the CEM heat input was significantly higher than heat input calculated from booked 

values prior to the replacement of the flow monitor. Commenters stated that following the 
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installation and calibration of the new flow monitor the CEM calculated heat input was closer to 

the heat input calculated from booked values. Commenters stated that the replacement of the 

flow monitor accounts for the step change in heat input and, consequently, the step change in 

gross unit heat rate calculated from the CEM data. Commenters stated that the actual unit heat 

rate did not improve.

Commenters stated that the UARG report presented material obtained from owners of 14 of the 

16 units and showed that in most cases the basis for a reported large decrease in gross heat rate 

was a change in operation of the monitoring equipment and that the 16 units are all investorowned utilities or public power entities. Commenters stated that rural co-operatives have similar 

experiences which should be considered as part of mandating heat rate reductions to limit CO2. 

Commenters stated this report solicited experience from four owners and reported experience 

from seven units that corroborate UARG's claims by examining the year-by-year reported 

CEMS-derived gross heat rate reductions for the seven units (by proxy, representing a total of 

nine units). Commenters discussed these data with the owners of all seven units and solicited 

their assessment of what caused the observed heat rate change focusing on annual gross heat rate 

data; where available gross or net heat rate as provided by the owner and based on fuel 

consumption is also provided for comparison.

Commenters stated that four owners operating five generating stations that host nine units 

offered data to assess the validity of EPA's claims regarding heat rate and that the seven 

reference units represent a broad range of equipment design, environmental controls, and fuel 

source. Commenters presented a table that summarizes the owners and units, describes select 

unit features, and summarizes key observations. Commenters stated that at two stations 

(Seminole, Basin Electric) where similar units operated, each unit exhibited similar trends in heat 

rate data and consequently, only one unit was selected to represent the data trends at that station. 

Commenters stated that the Associated Electric Co-Operative operates New Madrid Units 1 and 

2, which began commercial service in 1972 and 1977, respectively and that the CEMS-derived 

heat rate for both units is presented in Figures 1 and 2. Commenters further elaborated that both 

units generate 600 MW, fire Powder River Basin coal in a cyclone boiler, and are equipped with 

a hot-side ESP. Commenters stated that selective catalytic reduction (SCR) NOx control was 

retrofit in 2000 and 2003 but initially operated for the 5-month "ozone" season; each began 12-

month operation in 2007. Commenters stated that Unit 1 CEMS-derived gross heat rate (shown 

in Figure 1) is relatively constant over the 11-year period from 2002 through 2012 but that a 

large reported decrease in heat rate was observed in 2002, but offset by an approximate 4% 

increase in 2003 when new CEMS flow monitors were installed. Commenters stated that in 2006

the boiler was retrofit with overfire air for NOx control, contemporaneous with an observed 

increase in heat rate and that, SCR operation expanded to 12 months in 2007. Commenters stated 

that no other proactive changes to the boiler or steam turbine were implemented over this time 

period.

Commenters stated that Unit 2 CEMS-derived gross heat rate is presented in Figure 2, which 

suggests gross heat rate decreases almost consistently on a yearly basis, from 2002 through 2010 

and that these data suggest a total reduction approaching 15% over this period.
205

Commenters stated that several factors related to CEMS operation or equipment status appear 

responsible for the notable decrease in Unit 2 heat rate and that the owner reports the CEMS 

flow monitor was re-characterized (i.e., recalibrated) in 2002, coincident with a 3% decrease in 

heat rate. Commenters stated that the following year a new monitor was installed, again coincident with a decrease - this time of almost 8% and following a 4% increase in 2004, the boiler 

was retrofit with overfire air and in 2007 SCR operation was extended to 12 months. 

Commenters stated that no other proactive changes to the boiler or steam turbine were 

implemented over this time period.

Commenters summarized that the most significant CEMS-reported changes in heat rate were due 

either to changes in flow monitor calibration, or replacement of the flow monitor and that these 

events prompted heat rate decreases of 4 and 8% in the same year for Units 1 and 2, respectively. 

Commenters stated that both the boiler retrofit with overfire air and extending SCR operation to 

12 months had a mixed impact - with gross heat rate either increasing or decreasing in the same 

year, depending on the unit and that the owner has deployed heat rate improving actions on both 

units but external to the period evaluated.

Commenters stated that the Associated Electric Co-Operative operates Thomas Hill Units 1 and 

2, which began commercial service in 1966 and 1969, respectively and that the CEMS-derived 

heat rate for both units is presented in Figures 3 and 4. 

Commenters stated that Units 1 and 2 generate 185 and 265 MW, respectively, fire Powder River 

Basin coal in a cyclone boiler, and are equipped with a hot-side ESP, and that the SCR NOx 

control was retrofit in 2000 and 2003, but began annual (i.e., 12 month) operation in 2007. 

Commenters stated that Unit 1 CEMS-derived gross heat rate (shown in Figure 3) exhibits a 

large number of "step" changes in both positive and negative directions and that reported gross 

heat rate decreases significantly from 2002 through 2008, and returns to 2002-observed levels by 

2012. Commenters stated that two of the largest decreases in reported heat rate (2004 and 2006) 

coincided with flow monitors either being replaced or repaired and that the largest year-to-year 

change in reported flow was observed in 2008, after the owner reported re-characterizing (e.g. 

recalibrating) the flow monitor.

Commenters further stated that Unit 2 CEMS-derived gross heat rate shown in Figure 4 also 

exhibits a large number of "step" changes and that most notable is the reported heat rate in 2002 

is almost 1,000 Btu/kWh lower than Unit 1 - even though both units are of similar design and 

fire the same fuel. Commenters stated that several large heat rate changes in 2004 and 2005 

coincide with either replacing or re-characterizing the flow monitors; or repairing a flow 

transducer and that large changes in 2007 and 2008 appear due to changes to the flow monitor; 

one calibration in 2008 revealed a 7% flow bias. Commenters stated that both units exhibit 

minimum heat rate in 2007, when SCR operation was extended from 5 to 12 months, followed 

by a large increase the subsequent year, when the owner reported recharacterizing the flow 

monitor. Commenters stated that the owner has deployed heat rate improving actions on both 

units but not in the timeline studies.

Commenters summarized that similar to the New Madrid station, the most significant CEMSreported changes in heat rate were due either to changes in flow monitor calibration, replacing a 

transducer, or replacing the entire flow monitor and that for both Thomas Hill units, the two 
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largest changes in reported gross heat rate all coincided with work on CEMS equipment or the 

flow monitor.

Commenters stated that Antelope Valley Unit 2 fires northern lignite, features a dry FGD process 

with a fabric filter, and uses combustion controls to limit NOx emissions. Commenters stated 

that the data in Figure 5 depict the timeline for gross heat rate and defines actions taken by the 

owner that could affect heat rate or to calibrate or repair CEMS equipment while Figure 6 

compares the gross heat rate as measured by annual fuel consumption to that determined by 

CEMS data. 

Commenters stated that the Figure 5 timeline reports the dates of boiler and air heater cleaning, 

and changes to the CEMS equipment or stack gas flow probes. Commenters described that for 

units fired by lignite, cleaning the boiler and air heater to remove deposits will increase surface 

area for heat absorption, and improve gas flow through the air heater and that both actions should 

improve boiler thermal efficiency and thus lower gross heat rate. Commenters stated that boiler 

and air heater cleaning were conducted in 2002, 2005, 2008, and 2011.

Commenters stated that for two of boiler and air heater cases (2002, 2005) gross heat rate 

decreases in the subsequent year, and for another two (2008, 2011) gross heat rate increases. 

Commenters stated that considering fuel-derived gross heat rate in Figure 6, in two cases (2002 

and 2008) fuel-derived heat rate decreased in the year subsequent to cleaning, while for two 

other cases (2005 and 2011) fuel-derived heat rate was either unchanged or increased. 

Commenters stated that Figure 5 also reports the CEMS equipment underwent several significant 

changes and that these are (a) the test method for flow RATA was changed from the analog 

method to an auto probe (2007), (b) the gas analyzers for SO2, NOx, and CO2 were replaced 

with new equipment (2009), and (c) the gas flow analyzer was replaced (2010). Commenters 

stated that notably, Figure 6 reports gross heat rate derived from fuel consumption is almost 10% 

lower than CEMS-derived heat rate, for the period from 2002 through 2006. Commenters stated 

that eventually gross heat rate increases so that by 2012 the fuel-derived values exceed those 

determined by CEMS. 

Commenters stated that Seminole Electric Units 1 and 2 exhibit highly variable CEMS-derived 

gross heat rate data with time. Commenters focused on the timeline for Unit 2, for which the 

gross heat rate timeline is shown in Figure 7. Commenters stated that both Seminole units 

generate approximately 715 MW (gross basis), with Units 1 and 2 initiating commercial service 

in 1984 and 1985, respectively. Commenters stated that these units fire eastern bituminous coal 

with opposed, wall-fired boilers and that environmental controls feature a cold-side ESP and a 

wet limestone FGD. Commenters stated that in 2007 SCR NOx control was retrofit to both units 

(Figure 7 depicts the timeline for gross heat rate and defines actions taken by the owner that 

could affect heat rate or to calibrate or repair CEMS equipment). Commenters stated that Figure 

7 shows a significant decrease in reported gross heat rate following actions in 2002. Commenters 

stated that Seminole staff discovered anomalies in the gas flow measurement and immediately 

implemented improvements and that the most significant actions were (a) use a new method to 

calibrate the flow instrument, and (b) minimizing sample gas in-leakage. Commenters stated that 

the change in reported heat rate is completely attributed to these actions and that additional steps 

to recalibrate the stack gas flow monitor were implemented in 2003 and identified by the Owner 

as another key source of gross heat rate variation. Commenters stated that Seminole implemented 
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several actions to lower heat rate - in 2006 low NOx burners were retrofit, and at the same time 

measurement of airflow in the ductwork was improved to better control excess air and increase 

boiler thermal efficiency. Commenters stated that in 2009 SCR was retrofit, and 

contemporaneously actions taken to limit leakage of gas into air across the air heater, increasing 

boiler thermal efficiency. Commenters stated that each of these actions will lower plant heat rate, 

but by a magnitude much less than the improvement suggested by the CEMS data, notably, the 

low-pressure (LP) section of the steam turbine in 2010 was upgraded. Commenters stated that 

Seminole estimates this action lowered heat rate by about 2%, as opposed to the 4% change 

reported by the CEMS. Commenters referred to Figure 8 which compares the gross heat rate for 

Seminole Unit 2 as derived from EPA CEMS data to the net heat rate determined by annual fuel 

consumption (the latter by the Owner). Commenters stated that Figure 8 shows net heat rate, in 

marked contrast to CEMS-derived gross values, is relatively constant over the 11-year period. 

Commenters summarized that most reported changes in gross heat rate for Seminole Unit 2 are 

due to changes or recalibrations to the CEMS-derived data from which gross heat rate is based 

and that gross heat rate based on fuel consumption is relatively consistent over the 11-year 

period. Commenters stated that Seminole implemented several heat rate improving actions, the 

most significant being overhaul of the LP turbine, the latter calculated to lower heat rate by 

approximately 2%. Commenters stated the change in gross heat rate using CAMS data is either 

over-reported or not recognized.

Commenters stated that the CEMS-derived heat rate for Holcomb Unit 1 is presented in Figure 9 

Commenters stated that Holcomb Unit 1 is a 384 MW unit, employs a tangentially configured 

boiler that fires Powder River Basin coal, and is equipped with a dry FGD and fabric filter to 

control SO2 and particulate matter. Commenters stated that Figure 9 shows that gross heat rate 

decreases consistently each year starting in 2001 through 2005, coincident with an increase in 

capacity factor of the unit and that a total reduction of 6% is realized over this period. 

Commenters stated that from 2006 and through 2007 the gross heat rate increases about 3% -

during a time when the steam turbine was upgraded and boiler surfaces reconfigured (2006), 

which should lower heat rate. Commenters stated that the CEMS analyzers were replaced in 

2007 and that changes in reported gross heat rate subsequent to this period are small and erratic. 

Commenters further stated that Figure 9 also depicts the range of net heat rate recorded by the 

owner over the 11-year period and that the net heat rate is observed to remain within a relatively 

narrow range - from approximately 10,300 Btu/kWh to 10,500 Btu/kWh. Commenters stated that 

these net heat rate data - as determined by the owner based on annual performance tests and net 

generation delivered - are relatively consistent and do not reflect the trend in gross heat rate 

depicted in Figure 9.

Commenters summarized that Holcomb Unit 1 CEMS-derived gross heat rate decreases in the 

first 4 years without apparent reason, and increases in the subsequent 3 years when a steam 

turbine upgrade and boiler refurbishment should lower heat rate and that net heat rate as 

determined by the owner is relatively constant, and within 3% over the 11 year period.

Commenters stated that - in summary - significant variability is noted in CEMS-derived reported 

gross heat rate and that for many units a reported decrease in gross heat rate of 3% or more, 

using CEMS-derived data, either follows or precedes increases of similar values. Commenters 

stated that it is possible operating factors such as load and the ambient temperature at which the 
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unit rejects heat into the environment affect heat rate and are responsible for some of the 

apparent variability. Commenters stated that all four owners of seven units report most if not all 

changes in gross heat rate were due either exclusively or almost exclusively to unrelated normal 

or routine variability in CEMS heat input measurements and that the most frequently cited source 

of variation is the routine recalibration of the stack flow monitor. Commenters stated that several 

owners also reported significant changes as a result of using more accurate manual test methods 

when performing that recalibration. Commenters stated that two owners of two units report that 

upgrading the steam turbine, with the gross heat rate not recognizing the improvement for one 

(Sunflower) but recognizing the heat rate reduction for the other (Seminole Unit 2). Commenters 

stated that the importance of abandoning gross heat rate and using net heat rate as the key metric 

is demonstrated by the experience of three units that directly compared gross heat rate and owner 

supplied net heat rate. Commenters stated that in all three cases the owner-supplied net heat rate 

showed relatively little change over the 11-year period, in contrast to the significant year-to-year 

variations in CEMS derived gross heat rate. Commenters stated that the takeaway from this 

experience is that CEMS-derived gross heat rate data are an inadequate basis from which to 

judge modest changes in heat rate. Commenters stated that year-to-year changes can be highly 

variable and that numerous observations suggest the role of stack gas flow monitor calibration 

induces most of these apparent heat rate changes - major reported reductions in gross heat rate 

are coincident with routine annual recalibration or a change in test methods used for calibration. 

Commenters stated that these observations support the conclusion that CEMS-derived heat rate 

data are significantly influenced by factors unrelated to actual changes in heat rate and that he 

most reliable way to gauge the payoff of heat rate improving investments is through thermal 

performance monitoring.

Commenters stated that EPA identified 16 EGUs and says, the 16 units have demonstrated a 3-8 

% HRI. Commenters stated that EPA further believes that it has identified two EGUs where 

equipment upgrades have resulted in 2-3% HRI, and EPA, although unable to confirm other unit 

HRI attributed to equipment upgrades, nonetheless believes that equipment upgrades were the 

result of HRI in "some" of the other observed unit HRIs.

Commenters stated that EPA apparently never contacted the owners of these units to determine 

what actual factors were responsible for the apparent heat rate reductions, and its failure to do so, 

especially in a study including only 16 units, is arbitrary and irrational. Commenters stated that if 

EPA had followed a rational analytic process, it would have contacted the unit owners/operators 

and requested information and data verification. Commenters stated that especially in view of 

EPA's assessment, cited earlier, that significant HRI has been associated with changes in data 

reporting, prudent evaluation would dictate that EPA take a close look at data associated with the 

sixteen units. Commenters pointed to a table which summarizes the causes of the HRI for the 

sixteen units as determined by industry consultant Ed Cichanowicz in a study conducted for 

UARG, and stated that Cichanowicz made actual contact with the owners of the sixteen units. 

Commenters stated that based on detailed discussions with ten of the twelve unit owners, the 

reported heat rate improvements resulted almost exclusively from changes in continuous 

emission monitoring system ("CEMS") reporting methodology or stack flow monitor calibration 

rather than from purposeful efforts to improve unit efficiency. Commenters stated that EPA's 

reported heat rate improvements in the Sixteen Unit Study do not reflect actual changes in unit 

efficiency or reductions in unit CO2 emission rates and that the owners of ten units report that all 

changes are due either exclusively or almost exclusively to changes in CEMS reporting 
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procedures, most frequently including changes to the method of calibrating the stack gas velocity 

probe. Commenters stated that some units did report significant initial heat rate improvements 

from equipment upgrades, such as upgrading the steam 85 turbine, but these improvements were 

more than offset by increases in net heat rate due to the retrofit of environmental controls. 

Commenters concluded that therefore EPA has presented no valid documentation regarding the 

Sixteen Unit Study on which it can rationally justify any of the proposed options for HRI across 

the coal-fired EGU fleet.

Commenters stated that EPA has also derived incorrect conclusions from the continuous 

emission monitoring system ("CEMS") data to support its Block 1 target. Commenters stated the 

CEMS data is limited in its usefulness in determining whether heat rates did or did not improve; 

for instance annualized CEMS data does not adjust for startups, shutdowns, degradations in heat 

rates following projects, cycling of coal plants to follow load or renewables, or other factors, but 

most glaringly, the CEMS data expresses heat rate in gross terms rather than net terms, meaning 

that CEMS data ignores increases in "house power" needed to run environmental controls. 

Commenters stated that partially due to this use of gross CEMS data, EPA incorrectly concludes 

that the heat rate of their A.S. King Plant in Minnesota has improved (A.S. King was one of 

sixteen coal EGUs that EPA cited as evidence of significant year-to-year efficiency 

improvements). Commenters stated that while they did undertake a number of heat rate 

improvements at A.S. King during a plant rehabilitation project from 2004-2007, they also added 

a number of power consuming environmental controls such as a scrubber, SCR, and a baghouse. 

Commenters stated that net-basis testing shows that A.S. King's heat rate was 4.7% worse, not 

better, due to these changes to the plan, and put simply, A.S. King is now a far cleaner plant, but 

its heat rate is slightly worse. Commenters stated that in setting the Block 1 target, EPA should 

properly account for true net-basis heat rates, and should also factor in the widespread adoption 

of environmental controls taking place nationwide.

Commenters stated that even the 16 specific EGUs upon which EPA relies as evidence of the 

feasibility of a six percent heat rate improvement x did not actually attain six percent heat rate 

improvements. Commenters stated that Utility Air Regulatory Group ("UARG") contacted all of 

these units to determine how they obtained their heat rate improvements and that UARG 

discovered that most of the reported reductions in gross heat rate were due to unrelated normal 

variations in CEMS - based heat input values, not the result of proactive steps to reduce heat rate. 

Commenters stated that owners of 10 units reported that all large gross heat rate reductions 

observed over the 11-year period were due to unrelated variability in the CEMS-based 

measurements. Commenters stated that for example, EPA relied on apparent heat rate reductions 

at Wisconsin Public Service's Weston Unit 3 of eight percent in 2007, ten percent in 2008, and 

four percent in 2009, but that essentially all of these heat rate reductions were due to routine 

recalibration of the stack flow monitors and in fact, a change in the stack flow monitor 

calibration method during a 2006 outage was responsible for a flow reduction of more than 10 

percent and the associated reported heat rate reduction. Commenters stated that Wisconsin Public 

Service also believes that recalibrating the flow monitors in 2008 contributed to the 10 percent 

decrease in gross heat rate - to less than 9,000 Btu/kWh - below the design target. Commenters 

stated that in light of the illusory heat rate improvements at the plants on which EPA relied, it is 

unreasonable for EPA to conclude that a six percent heat rate improvement is achievable.
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Commenters stated that the EPA identified from the national generating inventory 16 units the 

Agency claims demonstrate the feasibility of achieving gross heat rate reductions of at least 3%, 

on a year-on-year basis, as determined over an 11-year period and that one of the 16 generating 

units the EPA relied upon for its analysis is their Gibson Station Unit 1 in Owensboro, Indiana. 

Commenters stated that the apparent reduction in the heat rate of this unit was influenced by a 

number of factors that have nothing to do with an actual reduction in the unit's heat rate and 

therefore the gross heat rate history of this unit does not support the EPA's conclusion that 

targeted heat rate reductions of up to 6 percent are feasible.

Commenters stated that the EPA erred in its reliance on the Gibson Unit 1 data because the 

CEMs data for this unit are not independently representative of the analysis the EPA conducted. 

Commenters stated that first, prior to the spring of 2007, the Gibson Unit 1 flue gas exited a 

single common stack that was shared with Gibson Unit 2 and per the CEM protocols of Part 75, 

heat input measurements from the single common stack were allocated to the individual units on 

a pro-rata basis using gross unit load. Commenters stated that as a result, the CEM data do not 

independently represent the performance of Gibson Unit 1. Commenters stated that in the Fall of 

2007, Gibson Unit 1 was retrofitted with a new wet flue gas desulfurization system ("FGD"), 

including a new stack and a completely new CEM system and because of these changes, the 

CEM data before and after this event are not comparable as the EPA protocol allows up to a 

7.5% Relative Accuracy Test Audit limit for the flow monitor, and 0.7% for the CO2 monitor 

(the measurements from the flow monitor and the CO2 monitor are used in the CEM heat input 

calculation). Commenters stated that therefore, changes in the Gibson Unit 1 heat rate based on 

the CEM data cannot be differentiated between the change in the CEM itself and any actual gross 

heat rate improvement and that this is only further emphasized by the fact that the improvement 

being sought is within the established measurement accuracy of the instruments, and should 

therefore be completely discounted. Commenters stated that lastly, when the selective catalytic 

reduction ("SCR") (2005) and flue gas desulfurization ("FGD") (2007) were added to Gibson

Unit 1, the auxiliary power consumption for the unit increased, also increasing the net heat rate, 

even while the gross heat rate remained constant. Commenters stated since the EPA's analysis is 

only (and inappropriately) relying on gross generation and heat input data, it does not capture the 

change in the true total net heat rate, which is the basis for compliance with the Clean Power 

Plan.

Commenters stated that EPA's analysis of heat rate improvement relies on CEMS data for hourly 

heat input data. GHG Abatement Measures TSD at Section 2.5.1. Commenters stated that this 

data cannot be used for accurate analysis of heat rate trends due to the EPA-recognized 

measurement error of flue gas flow. Commenters stated that EGU heat input is calculated using 

flue gas CO2 concentration and flue gas flow. Id. at Section 2.5.1 n. 3. Commenters stated that 

EPA's allowable relative accuracy for flue gas flow is plus or minus 10% at any given load point. 

40 C.F.R. Section 75.20. Commenters stated that because flue gas flow is directly proportional to 

heat rate, reported heat rates relied upon by EPA's analysis can be plus or minus 10% of the true 

value. Commenters stated that given this potential plus or minus 10% variation, it is questionable 

whether the data cited by EPA demonstrates any industry or individual unit trends over time 

from heat rate improvement projects with heat rate impacts that are within this plus or minus 

10% variation band. 
211

Commenters stated that even more troubling than EPA's assumptions regarding achievable 

improvements in net heat rate at coal-fired EGUs constructed in or before the 1980's, such as 

those at CGS, is the fact that EPA made the same assumptions for state-of-the-art coal-fired 

EGUs, such as the SRP-owned Unit 4 at SGS. Commenters stated that SGS Unit 4 commenced 

operation in 2009 and, based on the Part 75 monitoring data that was the basis for EPA's analysis 

of heat rate variability, has a gross heat rate of approximately 8,800 Btu/kWh. Commenters 

stated that this is approximately 10% less than the average for EPA's "study population," 

reflecting the fact that the initial design of this and other state-of-the-art units already includes 

the technological upgrades upon which EPA based its assumptions regarding achievable 

improvements in net heat rate at coal-fired EGUs. Commenters stated that although EPA makes 

clear that the 2009 S&L study is the sole basis for its assumption regarding the achievability of 

heat rate improvements through equipment upgrades, EPA also summarily discusses other 

sources of purportedly pertinent data that it considered such as a subset of the "study population" 

of 884 EGUs. Commenters cited GHG Abatement Measures, at 2-32 through 2-33 Commenters 

stated that the inferences drawn by EPA based on apparent year-to-year improvements in gross 

heat rate shown by the "study population" data set are not appropriate. Commenters stated that a 

fatal flaw in EPA's logic with respect to this data set is that fluctuations in reported heat input 

rate are more likely the result of measurement error or factors other than actual improvements in 

EGU efficiency. Commenters stated that here, having admitted that it had no basis for presuming 

that the observed fluctuation in gross heat rate at 14 of the 16 referenced EGUs was attributable 

to an equipment upgrade, EPA did not even attempt to determine whether the purported 

improvements in heat rate were sustained. 

Commenters stated that with regards to the 884 unit database, EPA acknowledges that 

monitoring approaches improved during the 11 year period that the data were recorded (2002-

2012), so observed HRI values could reflect better measurement, rather than better operation, 

and differences in the methodology and manner in which measurements were conducted and 

reported over the period (many of which were initiated by EPA) produced variability in heat rate. 

Commenters stated that for example, in 2008 EPA changed the F-factor requirement for the 

CEMS reporting, and this factor is used in converting the measured air pollutant concentrations 

in flue gases to a basis consistent with regulations, such as pounds per unit of heat input or tons 

per hour. Commenters stated that changing the F factor did not change the actual gas 

concentrations, but changed the "converted" values reported by electric utilities and used by EPA 

to determine heat rate and as a result, a change in heat rate could have been perceived where no 

actual change occurred. Commenters stated that on units firing sub-bituminous fuel, this change 

in measurement and reporting methodology would be interpreted as a 2 percent change in heat 

rate, although there would be no real change in heat rate. Commenters stated that one of their

member utilities confirmed that the F-factor change was incorporated in that company's reported 

data, beginning in April 2008, and likely affected reported heat rates.

Commenters stated that CEMS Flow monitor changes/upgrades (e.g., multiple transponders on 

retrofitted units), temperature measurement changed, pressure measurement changed and 

switching between redundant monitors could cause a 3 percent change in flow. Commenters 

stated that EPA's QA/QC steps and overall processes for reporting data have evolved over the 

years. Commenters stated that data from 2009 forward is likely to be the most homogeneous 

because of more widespread use of Emissions Collection and Monitoring Plan System (ECMPS) 

by reporting sources. Commenters stated that allowable Relative Accuracy Test Audit (RATA) 
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flow instrument recalibration is typically less than +/-7.5 percent, but can be +/-10 percent or 

more. Commenters stated that this will factor into the variability in heat rate measurements. 

Commenters stated that CEMS measurement inaccuracies, coupled with unsupported 

assumptions regarding opportunities for actual efficiency improvement, undermine EPA's 

predictions regarding what reasonably can be achieved by Building Block 1. 

Commenters stated that EPA's explanation for how it arrived at this fleet-wide number is 

contrived and not based on any actual demonstrated heat rate improvements across the fleet of 

U.S. EGUs. Commenters stated that EPA provides detailed statistical analysis of heat rate 

variability observations and links this variability to heat rate improvement potential. Commenters 

stated that however, these mathematical contortions fail to provide adequate demonstration that 

any specific actions attributable to "best practices" were the cause of any heat rate improvements. 

Commenters stated that EPA concedes that its "Heat Rate Assessment" showed that "two-thirds 

of the large decreases in heat rate can be associated with changes in reporting method 

implemented to provide more accurate heat input data." Commenters stated that obviously, a 

change in reporting does nothing to actually improve heat rate or decrease CO2 emissions. 

Commenters stated that a recent evaluation was completed of the methodology EPA used to 

justify setting a 6% emissions rate reduction target for heat rate improvements at coal-fired 

electric generation units. Commenters stated that recent assessment found EPA had computed 

heat rates from 16 coal units' using heat input data reported to EPA under the Acid Rain Program 

and data from continuous emissions monitoring systems (CEMS) at each plant. Commenters 

stated that based on their statistical analysis EPA claimed these 16 units demonstrated a year-onyear heat rate improvement of between 3 and 8% and that these types of improvements could be 

assumed to be achievable at all coal-fired power plants.

Commenters stated that the evaluation of EPA's methodology included contacting -and receiving 

technical responses from -10 of the 12 owners addressing 14 of the 16 units. Commenters stated 

that the key finding of the recent critique was that EPA's reported reductions were due to 

unrelated normal variations in CEMS-based heat input values, and not the result of proactive 

steps to reduce heat rate. Commenters stated that this analysis therefore disproves the 

assumptions EPA used to establish the 6% heat rate improvement for purposes of calculating 

North Dakota's "goal.

Commenters stated that they are very concerned with the EPA's assumption that a 4% HRI that 

can be achieved through adoption of heat rate variability best practices, with no proof that it is 

possible.

Commenters stated that EPA used the CEMS megawatt production, this being used to calculate a 

heat rate for the unit on an hourly basis however this input to the CEMS may not be a routinely 

calibrated device. Commenters stated that they have two megawatt measured loops one is for 

"billing" (routinely calibrated) and the "other" is used for various internal displays and the 

CEMS megawatt input was taken from "other", however "Other" is not calibrated as routinely as 

the "billing" megawatt measurement and they have seen annual differences of as high as 17,000 

MwHr/year. Commenters stated that the CEMS heat input is a calculated value, based on various 

inputs each having a variance in accuracy. Commenters compared their annual heat input date 
213

from EIA (based on actual coal measurements) and the EPA CEMS data and the percent 

difference between the two for the same time periods on an annual basis is between +5.6% to -

1.6%. Commenters stated that if the annual data from the EPA, CEMs data, varies by as much as 

5.6%, how much does the hourly CEMS data vary from actual? Commenters stated that they do 

not believe the hourly variation is a reliable measurement to use as a guide for best practices. 

Commenters stated that the EPA has performed computer analysis to show that a larger than 4% 

variation in heat rate occurs but has not provided any specific best practices to show it is a 

possible to improve the heat rate on an hour to hour basis. Commenters stated that the EPA 

should not rely on hourly CEMS data to imply possible heat rate improvement best practices 

without verifying the best practice. Commenters stated the 4% improvement based on fictitious 

best practices is an overreach by EPA and should be removed from the rule. 

Commenters stated that EPA's sampling of 16 EGUs for significant year-to-year improvements 

in heat rate is not accurate. Commenters stated that at p. 2-32 of its GHG Abatement Measures 

TSD, EPA says it analyzed 16 EGUs as examples of what significant HRI could be achieved and 

one plant evaluated was NPPD's Sheldon Station Unit 1. Commenters stated that a study 

undertaken for the Utility Air Regulatory Group ("UARG analysis") finds fault with EPA's 

conclusion that the 16 EGUs demonstrate the feasibility of EPA's heat rate improvement targets 

(See Exhibit F in A2 file for details). Commenters stated that Cichanowicz & Hein, Critique of 

EPA's Use of Reference Units to Select Heat Rate Reduction Targets prepared for the Utility Air 

Regulatory Group at 24 (October 13, 2014). Commenters stated that UARG contacted and 

received technical responses from 10 of the 12 owners addressing 14 of the 16 units. UARG 

analysis at 1. Commenters stated that they responded to a request for information from UARG 

and provided a basis for the information contained in the UARG analysis concerning Sheldon 

Station Unit 1.

Commenters stated that they conducted a study concerning alleged heat rate improvements at 

Unit 1 of Sheldon Station (See Exhibit G in A2 file for details) Commenters stated that using a 

timeline of CEMS-derived annual average gross heat rate for Sheldon Unit 1 shows a sharp drop 

in heat rate in 2006 (UARG analysis at 14). Commenters stated that this heat rate drop did not 

result from employment of best practices or equipment upgrades, but from a shift in how data 

were measured, as their study shows.

Commenters stated that the conclusions from this review indicate that the noted change in heat 

rate at Sheldon Station Unit 1, specifically the change in average annual heat rate between 2005 

and 2006, is not real, predominantly due to reduced error in the measured CEMS flow which 

results in greater accuracy in heat input and ultimately calculated heat rate. Commenters stated 

that review of actual station performance and accounting data shows a gradually increasing but 

predominantly steady heat rate throughout the time period in question. Commenters stated that 

the assertion by the EPA, that the reported heat rate improvement can be attributed to equipment 

upgrades, is false. 

Commenters stated that with regard to EPA's study of 16 plants that appear to have demonstrated 

significant efficiency improvements are possible in the past, they understand that many of the 

efficiency improvements EPA identified were actually attributable to changes in monitoring and 

reporting methodology, not actual efficiency improvements achieved through operating practices 

or equipment replacements. Commenters stated that this result is consistent with their own 
214

experience with different monitoring methodologies. Commenters stated that in the past, San 

Juan has used three different EPA methods to establish the "K factor" needed to calibrate the 

flow monitors that measure heat rate, which is then used to calculate CO2 emission rates. 

Commenters stated that when the facility switched from Method 2 to Method 2f (which is known 

to more accurately measure stack flow), the heat rates and CO2 emission rates of the San Juan 

units appeared to decrease by 12 to 15 percent, even though no other changes were made to the 

unit, and thus actual efficiency levels presumably remained relatively constant. Commenters 

stated that later, when San Juan switched again from Method 2f to Method 2g (due to saturated 

stack conditions), the heat rates and CO2 emission rates of the units appeared to increase by 2 to 

3 percent, again without any change in equipment or operations that would explain the change in

monitored efficiency levels. 

Commenters stated that this experience illustrates how the choice of monitoring methodology 

can have a far greater impact on reported heat rates and CO2 emission rates than the activities 

and projects EPA recommends as a possible means of achieving the expected efficiency 

improvements. Commenters stated that EPA fails to address these monitoring issues in its 

analysis of the 16 units that it cites as support for the conclusion that a six percent improvement 

is achievable, thus drawing that conclusion into question. 

Commenters stated that EPA must re-evaluate the methodology used to determine the target heat 

rate improvement (HRI) of 6%, specifically the proposed method of using historic heat rate data 

computed from continuous emissions monitoring systems (CEMS). Commenters stated that EPA 

should use site-specific data to determine a particular unit's ability to further improve heat rate, 

including recognition of efficiency improvements already undertaken and the loss of efficiency 

gains from implementation of other environmental upgrades, rather than assumptions based on 

an analysis of heat rates calculated using stack flow data from CEMS. 

Commenters stated that the Association of Mechanical Engineers has specific Performance Test 

Codes (PTC) for steam turbine-generators which include test procedures that result in the highest 

level of accuracy consistent with the best engineering knowledge and practice in the steam 

turbine industry. Commenters stated that a performance test conducted in accordance with the 

appropriate ASME PTC is the most accurate method of determining turbine-generator 

performance. Initial thermal acceptance tests can be performed using PTC - 6 "Steam Turbines" 

while periodic tests can be performed using PTC - 6S "Simplified Procedures for Routine Tests 

of Steam Turbines." PTC - 6 requires the use of calibrated instrumentation and controlled 

measurement procedures and PTC -6S aids in developing procedures to monitor performance. 

Commenters stated that the Utility Air Regulatory Group (UARG) concluded in their report 

entitled "CRITIQUE OF EPA's USE OF REFERENCE UNITS TO SELECT HEAT RATE 

REDUCTION TARGETS" prepared by J. Edward Cichanowicz and Michael C. Hein: 

"The takeaway from this experience is that CEMS-derived gross heat rate data are an inadequate 

basis from which to judge modest changes in heat rate. As noted, year-to-year changes can be 

highly variable. The numerous observations regarding the role of stack gas flow monitor 

calibration in what might appear to be heat rate changes - where major reductions in gross heat 

rate are reported co-incident with routine annual recalibration or a change in test methods used 

for calibration - support the conclusion that CEMS-derived heat rate data are significantly 

influenced by factors unrelated to actual changes in heat rate. The most reliable way to gauge the 

payoff of heat rate improving investments is through thermal performance monitoring." 
215

Commenters concurred with UARG in that using CEMS-derived heat rate data is not an 

appropriate method to use to determine a fleet wide HRI average. Commenters stated that each 

coal-fired power plant is unique and each plant should be analyzed on a case-by-case basis to 

identify the measures that have already been implemented and realistic heat rate improvement 

goals. 

Commenters stated that the Utility Air Regulatory Group (UARG) recently issued a report 

evaluating the methodology EPA used to justify setting a six percent emissions rate reduction 

target for heat rate improvements at coal-fired electric generation units. Commenters stated that 

UARG found EPA had computed heat rates from 16 coal units using heat input data reported to 

EPA under the Acid Rain Program and data from continuous emissions monitoring systems 

("CEMS") at each plant. Commenters stated that based on its statistical analysis, EPA claimed 

these 16 units demonstrated a year-on-year heat rate improvement of between three and eight 

percent and that these types of improvements could be assumed to be achievable at all coal-fired 

power plants.

Commenters stated that UARG's critique and evaluation of EPA's methodology included 

contacting - and receiving technical responses from - ten of the twelve owners addressing 14 of 

the 16 units. Commenters stated that the key finding of its critique was that EPA's reported 

reductions were due to unrelated normal variations in CEMS - based heat input values, and not 

the result of proactive steps to reduce heat rate. Commenters stated that the UARG analysis 

undermines the assumptions EPA used to establish the six percent heat rate improvement for 

purposes of calculating each state's goal. 

Commenters stated that EPA assumes that coal-fired power plants can reduce their emissions by 

6% by implementing heat rate improvements. Commenters stated that the Agency does not base 

this assumption on an actual analysis of each state's plant conditions, instead, it simply used 

national reporting Continuous Emissions Monitoring ("CEMS") data as a springboard for bold 

assertions that the relied-upon data does not support.

Commenters stated that in Building Block #1-Coal Plant Efficiency Improvements-the EPA 

proposes a 6% reduction target for heat rate and CO2 emissions. Commenters stated that the 

notion of improving the efficiency of coal-fired plants that will be asked to operate at reduced 

output flies in the face of the engineering and physics associated with the conversion of fuel to 

electricity. Commenters stated that in addition it has also been found to be based upon erroneous 

and unreliable data. Commenters stated that in its October 13, 2014 comments, the Utility Air 

Regulatory Group ("UARG") concluded that based upon its extensive and well-documented 

investigation, that "most reported reductions in gross heat rate are due to unrelated normal 

variations in CEMS-based heat input values, and not the result of proactive steps to reduce heat 

rate. Commenters stated that the year-to-year reported gross heat rate is highly variable and 

characterized by large changes; the annual reductions usually coincide with changes in the stack 

gas flow monitor calibration, installation of new CEMS, or retrofit of an FGD process. 

Commenters stated that in addition, the EPA completely ignores the one example in the Sargent 

& Lundy report referenced in its technical support documents that shows the amount of heat rate 

improvement gained at a single plant. Commenters stated that in section 8.2 of the report, the 

only case study dealing with heat rate reductions at a large coal-fired unit (the type that would be 

expected to remain in service after smaller units are retired to avoid uneconomical investments 
216

for MATS compliance), Table 8-2 shows a heat rate reduction of only 124 Btu/kWh (-1.2%) 

resulting from an investment of $1.65 million. Commenters stated that it is therefore 

unreasonable to conclude that heat rate improvements over this amount could have been 

economically achieved on this or any similar unit.

Commenters stated that in conclusion, the plant efficiency savings are significantly overestimated and the efficiency at the plants cannot be increased to the levels proposed by EPA, 

particularly when reduced output is expected, as well as additional parasitic power requirements 

(mostly increased fan loading) commensurate with MATS compliance. 

Commenters stated that as part of its analysis to develop the 6% Building Block 1 heat rate 

reduction target, U.S. EPA relies on Continuous Emission Monitor (CEM) heat input and gross 

generation data from multiple specific generating units to determine what it believes are 

examples of significant step change improvements in gross heat rate. Commenters stated that one 

of the generating units relied upon is Gibson Station Unit 1 in Gibson County Indiana, owned 

and operated by Duke Energy. Commenters stated that U.S. EPA has erred in its reliance on the 

Gibson Unit 1 data because the CEM data for this unit is not independently representative for the 

analysis being conducted. Commenters stated that prior to the spring of 2007, the Gibson Unit 1 

flue gas exited a single common stack in combination with Gibson Unit 2. Commenters stated 

that per the CEM protocols of Part 75, heat input measurements from the single common stack 

were allocated to the individual units on a pro-rata basis using gross unit load and as a result, this 

CEM data does not independently represent the performance of Gibson Unit 1. Commenters 

stated that additionally, in the fall of 2007, Gibson Unit 1 was retrofitted with a new wet flue gas 

desulfurization system (FGD), including a new stack and completely new CEM system and it is 

inappropriate to compare CEM data before and after this event as the U.S. EPA protocol allows 

up to a 7.5% Relative Accuracy Test Audit limit for the flow monitor, and 0.7% limit for the 

CO2 monitor (the measurements from the flow monitor and the CO2 monitor are used in the 

CEM heat input calculation). Commenters stated that therefore, any changes in heat rate cannot 

be differentiated between the change in the CEM itself and any actual gross heat rate 

improvement, if any. Commenters stated that this is only further emphasized by the fact that the 

improvement being sought is within the established measurement accuracy of the instruments, 

and should therefore be completely discounted anyway. Commenters stated that lastly, when the 

selective catalytic reduction (SCR) (in 2005) and FGD (in 2007) were added, the auxiliary power 

consumption for the unit increased, also increasing the net heat rate, even while the gross heat 

rate remained constant. Commenters stated that since U.S. EPA's analysis is only relying on 

gross generation and heat input data, it does not capture the change in the true total net heat rate 

for which compliance with the Clean Power Plan is required. Commenters stated that the Gibson 

facility is one of the largest coal-fired EGUs in the United States and critical to the establishment 

of BSER. Commenters stated that Indiana strongly encourages U.S. EPA to revisit the methods 

used to establish BSER for Building Block 1 as this may not be the only instance where such an 

important technical oversight was made.

Commenters stated that the EPA, in a Technical Support Document related to 111d regulation 

for which their review indicated a year-to-year Heat Rate Improvement (HRI) in the range of 3-

8% and for which they believe the improvements can be attributed to an equipment upgrades. 

Commenters stated that this data analysis was used in part to support EPA recommendation that 

HRI's of 4 -12% are achievable throughout the industry. Commenters stated that upon further 
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review it was determined that NPPD's Sheldon Station Unit 1 was one of those 16 EGU's. 

Commenters stated that the report documents their review of EPA's information and analysis and 

the findings detailed in the report identify a number of issues which call into question the 

appropriateness of the use of CEMs reported data for the purpose of identifying actual HRI. 

Commenters stated that to review and provide comment on EPA's findings, they reviewed 

CEMS reported data and duplicated the process of calculating monthly and annual average gross 

heat rates to determine legitimacy of EPA's assertion of a single year-to-year heat rate 

improvement of 3-8%. Commenters stated that review of CEMs data confirmed that the data 

used and heat rate calculations were correct given the source of the data and additionally the 

calculated heat rates using this data does indicate a single year-to-year heat rate improvement of 

3-8%. (~10% improvement 2005 to 2006)

Commenters stated that actual unit performance data including gross heat rate as reported to 

NERC for General Data Availability System (GADS) reporting requirements for the same 11-

year time period were reviewed and that review of the actual GADS reported heat rate 

information contradicts the CEMS based heat rate calculations and in fact indicates a gradually 

increasing but predominantly steady heat rate throughout the time period. Commenters provided 

a chart that displays the average annual heat rate for Sheldon Station Unit 1 during the time 

period noted for both CEMS-based heat rate calculation and GADS-reported heat rate values.

Commenters stated that using the data in this Annual Heat Rate chart, commenters presented 

another chart that shows calculated percentage change in year-to-year heat rates for both CEMS 

and GADS based data. Commenters stated that as can be seen in in this chart, the year to year 

change in heat rate from 2005 to 2006 based on CEMS reported data shows a reduction 

(improvement) in heat rate of approximately 10%. Commenters stated that however actual heat 

rate as shown by the GADS reported data shows a slight increase (deterioration) in heat rate. 

Commenters stated that after identifying the discrepancy between CEMS-based and GADSbased heat rate values, further review was completed to fully understand the bases for the two 

calculations and try to identify the likely sources of error. 

Commenters stated that the following section describes the specific findings related to each of 

the step changes in the CEMS calculated flow and related heat rate as noted previously during 

the 2005 - 2008 time frame. 

1. Consistent increase in monthly heat rate from May to September 2005 followed by a 

large decrease in October, 2005: Commenters stated that the increase during the summer 

of 2005 is due to gradual degradation in performance due to record capacity factors and 

consistent high load operation for the entire summer, thus a vast majority of hours were 

operated in the high load range which had the greatest flow error percentage. 

Commenters stated that the decrease in heat rate in October corresponds to the fall 

maintenance outage but no significant equipment upgrades or replacements were made 

during this outage and thus any improvement was related to routine BMP completed 

during the outage. Commenters stated that following the October outage capacity factors 

were much lower and thus more time was spent operating in the mid load range where 

flow measurement accuracy was better.
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2. Step change decrease in heat rate in August 2006: Commenters stated that on June 5, 

2006 a RATA flow test was completed and Commenters chose to begin using 3 separate 

K-Factors for the three required load ranges. Commenters stated that subsequently in 

August, 2006 during their routine annual RATA testing, the K-Factors for the three load 

ranges were adjusted down as allowed and this resulted in an approximated 8% decrease 

in measured stack flow.

3. One-month step increase in heat rate January, 2007: Commenters stated that this is 

believed to be related to higher than average capacity factor for the month of January 

2007. 

4. Step increase in July 2007: Commenters stated that RATA flow test conducted in June 

2007 resulted in K-Factor adjustment which lead to increase in stack flow of 

approximately 8% over the entire load range.

5. Consistent decrease in heat rate from December, 2007 to April, 2008 followed by 

consistent increase through December 2008: Commenters stated that flow RATA in 

February, 2008 resulted in approximate 8% decrease in stack flow over the load range. In 

April, 2008 they adjusted the F-Factor from 1800 for bituminous coal to 1840 for 

subbituminous coal which results in approximate 2% decrease in calculated heat input. 

Finally in August, 2006 RATA flow test resulted in adjusting K-Factor which lead to 

approximate 6% decrease in stack flow.

Commenters stated that the conclusions from this review indicate that the noted change in heat 

rate at Sheldon Station Unit 1, specifically the change in average annual heat rate between 2005 

and 2006, is not real and that it is predominantly due to reduced error in the measured CEMS 

flow which results in greater accuracy in heat input and ultimately calculated heat rate. 

Commenters stated that review of actual station performance and accounting data shows a 

gradually increasing but predominantly steady heat rate throughout the time period in question 

and the assertion by the EPA that the reported heat rate improvement can be attributed to 

equipment upgrades is false. 

Commenters stated that finally, EPA's analysis of hourly heat rate data assumes that facility 

reporting of power generation and fuel consumption is perfectly uniform and entirely accurate. 

Commenters stated that in reality, significant variation exists among measurement and reporting 

procedures used by facilities. Commenters stated that in particular, EPA itself acknowledged in 

its TSO that over one-third of EGUs studied reported heat rate data that showed year-to-year 

variability of over 8.5%, and that most of this variability was due to changes in reporting 

methods over its period of analysis, especially when cross-comparing between Methods 2, 2F, 

2G, 2H and CTM-041. Commenters stated that others have found that the data reported exhibit a 

high degree of noise that suggests a significant degree of error which has not been adequately 

taken into account by EPA. Commenters stated that without properly adjusting for this potential 

error, EPA overstates the degree of heat rate improvements that can be obtained from operating 

and maintenance practices. 

Commenters stated that EPA also identified 16 EGUs from the study population to determine 

EGU year-to-year HRI. Commenters stated that EPA's interpretation of HRI data from these 
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units, where equipment upgrades resulted in 2-3% HRI, further demonstrates its faulty approach 

and interpretation of the data. Commenters stated that EPA never contacted the owners of the 

units identified to determine what factors were responsible for the apparent heat rate reductions. 

Commenters stated that while EPA attributed the HRI to equipment upgrades, preliminary 

discussion with the owners of these units reported that HRI were not the result of purposeful 

efforts to improve unit efficiency but were instead almost exclusively from changes in 

continuous emission monitoring system ("CEMS") reporting methodology. Commenters stated 

that therefore, it is clear that the reported HRI in this study did not reflect actual changes in unit 

efficiency or reductions in unit CO2 emission rates. Commenters stated that this is yet another 

example of EPA's unfounded determination that 4% HRI is achievable across the board for all 

coal-fired EGUs from best practices. 

Commenters stated that in EPA's GHG Abatement Measures Technical Support Document, EPA 

points to large heat rate improvements via equipment upgrades that could be replicated on other 

EGUs. Commenters also stated that however, in many of the cases where EPA believed an 

efficiency improvement occurred, the reality is the perceived efficiency improvement was 

actually just the result of a change in continuous emission monitoring system reporting 

methodology and not the result of an equipment or operational change to lower heat rate. 

Commenters stated that the actual heat rates did not improve and that rather, a more accurate 

assessment of air flow through the stack caused the units to report an apparent improved heat 

rate.

Commenters stated that in its October 16, 2014 comments, UARG identified problems with 

using gross heat rate data provided by RPS-2's continuous emission monitoring systems (CEMS) 

and attributed most of the heat rate variance to CEMS calibration, not to any action taken by 

Cleco (the unit's operator) to achieve heat rate improvements. Commenters stated that their 

company, which owns 50% of RPS-2, confirms the information provided by Cleco (the unit's 

operator) and assembled by UARG, which questions both the validity of the data and of EPA' s 

interpretation of said data. Commenters stated that in summary, it is inappropriate to use CEMSbased gross heat rate data from any generating unit to determine the ability of generating units to 

achieve heat rate improvements, and it is especially inappropriate to make that determination 

based upon data retrieved from RPS-2, a unit projected for retirement partially due to perceived 

continued cost of compliance with other EPA regulations. 

Commenters stated that one such factor is the inherent heat input measurement error from 

continuous emission monitoring system (CEMS). Commenters stated that under the EPA's 

methodology, the heat input is a derived value from measurements of flue gas flow rate, oxygen 

content and moisture content. Commenters stated that each of those measurements will add error 

to the true heat input value. Commenters stated that for example, the flow monitor used at Unit 3 

is Teledyne Ultraflow 150. Commenters stated that the instrument will potentially contribute a 5 

percent measurement error. 

Commenters stated that EPA has proposed to entirely abandon its traditional reliance on 

reference method testing. Commenters stated that while they support continuous emission 

monitoring systems ("CEMS"), the commenters note that the level of heat rate improvement (six 

to ten percent) assumed under Block 1 is not significantly larger than the calibration 

requirements for the continuous monitors. Commenters stated that in addition, EPA's different 
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data sets contain unexplained and, at times, technically incredible emission data reported by 

utilities. Commenters stated that by way of example, the operators of Killen Station Unit Two

reported a gross CO2 emission rate of less than 1,500 lbs CO2/MWh for over a year in 2005-

2006 (Figure 10: titled, “Killen Station Unit Two Average Daily Emission Rate”), an emission 

rate that is neither technically possible for that type of facility nor sensible in light of the unit's 

performance in proximate years. 

Commenters stated that in the past, EPA has permitted sources to rely on fuel sampling rather 

than CEMS data for compliance purposes. Commenters stated that EPA should reject this option. 

Commenters stated that first, fuel sampling is well known to be less accurate that CEMS data 

and will not serve as an adequate substitute. Commenters stated that second, under state 

programs adopted pursuant to the Clean Power Plan, emission data will be used to establish and 

enforce programs with a significant environmental impact and will form the basis of tradable 

emission credits. Commenters stated that these data and the credits on which they are based will 

be far more valuable in the future than they are today. Commenters stated that for this reason, 

EPA should work with states and sources in the coming years to clean up the existing data sets 

and tighten the technical installation requirements for CO2 CEMS to ensure that accurate and 

unbiased data are produced. 

Commenters stated that the understanding is that in the early years of the Acid Rain program, 

industry satisfied a substantial portion of its compliance obligation simply by "recalibrating" the 

existing monitoring equipment. Commenters stated that EPA should adopt measures to ensure 

that the HRI anticipated under Building Block 1 are real and not illusory. Commenters stated that 

this would include (1) reference method or other upgraded testing either as a relative accuracy 

test audit ("RATA") requirement or as a standalone test requirement; (2) identification of the 

specific measures undertaken to achieve and maintain the claimed heat rate improvement; and 

(3) correlation of the recalibrated result with the required improvement.

Commenters stated that EPA has proposed that sources should be able to choose from among 

several potentially available reference methods, but has solicited comment on whether EPA 

should require operators to use the reference method that provides the most accurate results for 

the specific source. Commenters stated that the difference in cost between the available reference 

methods is quite small in the overall scheme and they are aware of no possible reason why EPA 

should permit a source to use any method that is less accurate than the published methods. 

Commenters stated that indeed, EPA should contemplate extending sampling times and volumes 

to improve accuracy over current Reference Method 2 variants.

Commenters stated that EPA should use fuel consumption data from the CAMD database to 

calculate real gross and net heat rates for individual EGUs. 

Commenters stated that changes in an EGU's flue gas handling system (i.e., duct work, fans, or 

stack) can significantly affect flow measurements, such as that stacks or ducts with certain 

physical characteristics can cause the flue gas to swirl (i.e., have non-axial components) rather 

than traveling straight up the stack. Commenters stated that some EPA reference methods 

(including the original Method 2) do not distinguish between straight and non-axial flow. 

Commenters further stated that stack volumetric flow also is affected by friction along the walls 

of the stack or duct that causes flow to decrease (i.e., velocity decay) near the stack wall and that 
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therefore reference method velocity measurements are taken at the centroid of several equal area 

segments within the cross-section of the stack. Commenters stated that EPA's velocity reference 

method assumes the flow determined at the measurement point is equal across the entire width of 

the equal area segment and asserts that this assumption is not correct for the measurement 

segment that is adjacent to the stack wall, because the stack gas velocity actually decays to zero 

at the wall. Commenters stated that therefore the EPA reference method procedure for measuring 

volumetric flow yields results that are naturally biased high and that the amount of bias can vary 

based on the stack liner material (e.g., masonry causes more friction than steel) and the shape of 

the stack flue or duct (e.g., rectangular, square, or circular). Commenters further stated that 

because of these effects, any change in the flue gas handling system that could create or reduce 

swirling flow (e.g., the reworking of ducts, addition of straightening veins, or removal of a unit 

from a common stack) or that changes the shape or liner of a duct or stack can have a significant 

effect on flow measurements, and, although such changes are not made frequently, they often are 

made in concert with addition of new pollution controls. Commenters stated that EPA in 1999 

promulgated new flow methods that are capable of correcting for non-axial flow and wall effects 

and that a change in the flow method used to conduct the RATA can result for some EGUs (i.e., 

those with non-axial flow or significant wall effects) in a significant change in heat input, but 

that similar changes however can occur without a change in flow method if the flue gas handling 

system itself is changed. 

Commenters stated that the statistical analysis focused on identifying EGUs with significant 

changes in year-to-year heat rate and of the original study population, roughly one third of the 

units (355 EGUs) showed a single year-to-year change in heat rate of greater than 8.5%. 

Commenters stated that using statistical processes, EPA filtered this data set to eliminate EGUs 

where the heat rate variance could be attributed to a change in capacity factor (an increasing 

capacity factor will reduce the associated heat rate), a change in year-to-year ambient 

temperature, a change in reporting methodology, or other factors. 

Comment 16: Comments asserting that it is not feasible or practical to use any single year as a 

baseline

Response 16: See section V.C of the final rule preamble of the CPP and chapter 2 of the GHG 

Mitigation Measures TSD supporting the final CPP for EPA’s response to this comment. In 

addition to what is stated in those documents, use of 2012 data accords with the data used to 

calculate state goals.

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

Commenters stated that the use of any single year as a baseline for heat rate is not feasible or 

practical considering the vast array of variables that can impact heat rate on any given unit at any 

given time. Commenters stated that if the baseline year happened to be a particularly unique year 

for an individual unit, any heat rate improvement based upon that particular base year will not be 

meaningful. Commenters presented a graph that shows one particular unit's average gross annual 

heat rate from 1999-2013. Commenters pointed out that operation in 2012 happened to be 

anomalous for this particular unit, as equipment outages and maintenance issues kept the unit out 
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of service much of the year, resulting in significantly lower than normal capacity factors and 

output factors. Commenters further points out that in 2013, the unit returned to more typical 

operations having incorporated no significant heat rate improvements, but that, from 2012 data, it 

appears that the unit's heat rate improved on the order of 27%. Commenters stated that this is but 

one example demonstrating the flaw in selecting a single baseline year. Commenters stated that it 

also demonstrates why it is impractical to design, implement, and enforce heat rate limitations. 

Commenters stated that in fact, a review of recent air permits for fossil fuel-fired electric 

generating units nationwide revealed not a single example of a heat rate limit.

Commenters stated that a cursory review of heat rate values in EPA's 2012 power plant database 

reveals some highly improbable results, such as very small units with heat rates below the 

theoretically plausible range and moreover, the wide variability in a unit's heat rate and the 

operational impacts that can occur on any unit in any given year, call into question the ability to 

select ANY one year as a representative baseline year for the entire fleet. Commenters stated that 

one of their member utilities operated one of their units in 2012 very infrequently (just over 

1,300 operating hours), resulting in an unusually low capacity factor and an unusually high gross 

unit heat rate (approximately 11,760 BTU/kWh). Commenters stated that in 2013, the average 

annual gross unit heat rate for that unit was 8,490 BTU/kWh - an improvement of 27 percent 

over 2012 which was not the result of any HRI projects or "best practice" employment. 

Commenters stated that this is but one example of why selecting a single and arbitrary baseline 

year is problematic. 

Comment 17: Comments that unit specific upgrades made prior to the 2012 baseline should 

count towards the target, making an additional 6% HRI difficult or impossible to achieve

Response 17: For the EPA’s response to these comments, see section V.C of the final rule 

preamble of the CPP and Chapter 2 of the GHG Mitigation Measures TSD supporting the final 

CPP. For example, as discussed in those documents, the EPA’s assessment of potential heat rate 

improvement accounts for HRI measures initiated before or during the study period and 

sustained through 2012. Additionally, because building block 1 is calculated on an average basis, 

if an affected EGU cannot meet its particular emission standard because it has below-average 

potential to reduce emissions with heat rate improvements, then in instances where the EGU’s 

state plan allows emissions trading, the EGU can acquire credits or allowances from affected 

EGUs that have above-average potential.

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

Commenters referred to unrealistic assumptions underlying Block 1 heat rate improvements and 

emission goals. Commenters stated that they implemented a number of pre-2012 heat rate 

improvement projects (collectively the High Pressure, Intermediate Pressure and Low Pressure 

Turbine Steam Path Modernization Projects). Commenters stated that these projects reduced the 

net heat rate on Rawhide Unit 101 by 4.9% between 2005 and 2012 at a cost of $16.55 million. 

Commenters stated that these recent heat rate improvements were in addition to improvements 

undertaken over the period 1985 to 2004, which reduced the heat rate by approximately 2.5%. 

Commenters stated that in total over the life of the Rawhide plant, the net heat rate has improved 
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7.6% - from 10,692 Btu/kW-hr in 1985 to 9,884 in 2012. Commenters stated that similar heat 

rate improvements have been made to Craig Units 1 and 2, and it is believed that most of 

Colorado's other EGUs have also completed heat rate improvement projects. Commenters stated 

they were an aggressive early adopter of efficiency improvements. Commenters stated that an 

additional 6% improvement from the 2012 baseline is not technically possible with existing 

technology. Commenters stated that in effect, their company and Colorado are being penalized 

for their proactive adoption of efficiency improvements. Commenters stated that the baseline 

should either be established at 2005 or the EPA should adopt a crediting mechanism that will 

selectively adjust the 2012 baseline to recognize prior actions. 

Commenters stated that HRI projects affect a limited number of large coal-fired units that have, 

in some cases, already undertaken equipment upgrades and operational improvements. EPA 

recognizes in its GHG Abatement Measures Technical Support Document (TSD) (page 2-4) that 

higher cost HRI projects are more effective and economically feasible for larger coal-fired units 

due to economies of scale. Commenters stated that Georgia has only 10 coal-fired units greater 

than 500 MW not slated for retirement that would be ideal for the "equipment upgrades" defined 

on page 34859 (Section VI.C.1.a.) of the proposal; however some have already completed higher 

cost upgrades. Commenters stated that the 10 large coal-fired units are located at Georgia Power 

Company's Plant Bowen (4 units), Plant Scherer (4 units), and Plant Wansley (2 units). 

Commenters stated that the high-cost equipment upgrades including steam turbine overhauls, 

took place at Bowen Unit 1, Scherer Unit 1 and Scherer Unit 4 as recently as 2010. Commenters 

stated that according to EPA's GHG Abatement Measures TSD (TSD page 2-12, Table 2-2) 

steam turbine overhauls achieve the highest reported efficiency increases, yet Georgia will not be 

able to count recent turbine overhauls towards its state goal because the projects took place 

before 2012. Commenters stated they believe that HRI investments of this magnitude at the two 

largest plants in the state (Plant Bowen and Plant Scherer) will not reoccur in the near future. 

Commenters also pointed out that as stated in the 2009 Sargent & Lundy study (page 3-2) used 

by EPA to set the HRI goal, similar turbine retrofits at smaller coal-fired units are cost 

prohibitive and thus unlikely. 

Commenters stated that in relying upon analysis more than six years old when developing the 

proposed rule, EPA ignored that the baseline 2012 emissions data already reflected HRI projects 

finished after the S&L and NETL studies were completed. Commenters stated that per the 

NEEDS database as referenced by EPA, there was approximately 314 GW of coal-fired 

generating capacity operating in 2012 and of the 314 GW of coal-fired capacity, approximately 

207 GW were operating in competitive wholesale energy markets as of 2014, representing 

approximately 65 percent of the coal fleet. Commenters stated that due to the nature of the 

competitive wholesale energy market (i.e. plants that are more efficient are dispatched more than 

units that are less efficient), many of the coal-fired power plants very likely would have 

implemented already many of the HRIs to improve the plants' economic position in the market. 

Commenters stated that the remaining 107 GW of capacity operating in other market structures, 

including traditional cost of service areas, also have every incentive, and in some cases are 

required, to operate and maintain units as efficiently as possible and doing so reduces fuel costs 

and reduces overall costs to customers. Commenters stated that as such, many units in these 

areas have also already undertaken HRI projects; and stated that for example, Southern Company 

has an aggressive program to maintain heat rates as low as possible. Commenters stated that as 

part of this program, Southern Company implements best practices and efficiency projects across 
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its coal fleet to minimize heat rate including many that EPA has focused on, including condenser 

cleanings, installation of digital control systems, and like-kind replacements of degraded 

equipment. Commenters stated that thus, these types of maintenance programs, coupled with 

annual goals of trying to improve heat rate from year to year, to ensure that projects that are 

economic and feasible have been performed already and requiring additional improvements on 

top of such efforts is impractical, if not infeasible, and would penalize utilities for longstanding 

best practice programs already in place.

Commenters stated the proposed rule punishes utilities that have taken early action to improve 

heat rates. Commenters stated where heat improvement measures have been taken, such as at 

their A.S. King station, and for a new unit such as their Comanche Unit 3 which came online in 

2010, significant additional improvements may not be possible. Commenters stated credit for 

those improvements is swept away by the 2012 base year, and Block 1 applies a potentially 

unrealistic burden to newer plants and plants where improvements have been made.

Commenters stated that owners and operators of many EGUs have already made heat rate 

improvements prior to the 2012 baseline year that EPA used in establishing the targets in its 

proposed rule; and because of these pre-2012 heat rate improvements, the proposed 6 percent 

level is not feasible. Commenters recommended using a site-specific analysis to determine the 

level of heat rate improvement for each facility and stated that this approach is consistent with 

the proposed rule for "Carbon Pollution Standards for Modified and Reconstructed Stationary 

Sources: Electric Utility Generating Units" (79 FR 34960; June 18, 2014).

Commenters stated that in satisfying the emissions reduction goal that EPA develops, states 

should be allowed to take into account the measurable and verifiable CO2 emissions reductions 

that already have occurred in the electricity generating sector ("inside-the-fence line") and 

among industrial consumers ("outside-the-fence line") since 2005. Commenters stated that 

electrical utilities and industrial consumers should be given credit for past actions taken to 

achieve these reductions, as many coal-fired units upgraded in previous years and engineering 

steps to further improve EE and meet EPA's proposed EE goals are cost prohibitive. Commenters 

stated that in estimating the proposed emission standard that can be hypothetically achieved by 

the State of Indiana, EPA assumed that all coal-fired power plants in Indiana can gain a 6% 

reduction in CO2 emissions by implementing heat rate improvements (Building Block #1) at 

existing utilities sometime after 2015, but many of Indiana's coal-fired units, including their

Warrick power plant, have already implemented available heat rate improvements, and no other 

cost-effective options remain for installation after 2015. Commenters stated that for example, 

Warrick, whose generation output supports production at their Warrick Smelter, Rolling and 

Finishing operations, installed more efficient turbine generators when SO2 scrubbers were 

installed in the early 2000's, and any remaining equipment options or modifications for 

improving energy efficiency are cost prohibitive. 

Commenters stated that in establishing the final GHG standard for the State of Indiana, EPA 

needs to identify which existing utilities (individual units) in the State no longer have costeffective options available to achieve the hypothetical 6% from Building Block #1 and increase 

the Indiana CO2 standard accordingly and that this correction also should be applied to the 

proposed CO2 standards for other States where heat rate improvements have already been 

implemented on the existing utility boilers. 
225

Commenters stated that first and foremost, the plants in which they have an ownership interest 

have already undertaken many, if not all, of the efficiency improvement projects identified by the 

EPA and the Sargent & Lundy study cited in the Proposed Rule, and moreover, the Sargent & 

Lundy study was published in 2009, several years before the 2012 baseline that the EPA 

proposes to use for setting state goals. Commenters stated that therefore, many of the 

improvements in that study are already likely to have been implemented by 2012, leaving little 

opportunity for additional improvement and as with other large coal-fired EGUs around the 

country, their plants are also already employing operational best practices to maximize net 

generating efficiency. Commenters stated that therefore, it is likely not possible for these plants 

to achieve even greater improvements to their heat rates and EPA should recognize that some 

states and individual plants may have already implemented the heat rate improvements identified 

for this Building Block, and reduce these states' emissions reduction targets accordingly.

Commenters noted that reductions may not be achievable due to EPA's basis of determination for 

heat rate improvements being 2012. Commenters stated that since those calculations were made, 

many plants have had to add environmental control equipment or other processes to deal with 

compliance for a host of regulations currently in effect and known to be in development 

including the Clean Air Visibility Rule (requiring compliance with Best Available Retrofit 

Technology), the Clean Air Interstate Rule/Cross State Air Pollution Rule, Mercury and Air 

Toxics Rule, Clean Water Act 316B, Effluent Limitation Guidelines, and further NAAQS 

reductions. Commenters stated that each of these compliance efforts will impact heat rate at the 

potential of 1 - 4% negative impact on heat rate. Commenters stated that therefore, to meet the 

EPA objective of heat rate improvements, some EGUs may need to find 7 - 10% improvement in 

heat rate- a virtual impossibility and certainly not contemplated by EPA. 

Commenters stated that Missouri's investor-owned electric utilities (IOUs) and the Association 

of Missouri Electric Cooperatives, Inc. (AMEC) indicate the 6 percent power plant efficiency as 

reflected in Building Block 1 is not achievable. Commenters stated that IOUs and AMEC have 

already implemented efficiency improvements and for instance, Ameren Missouri (Ameren) 

indicates that since 1998 it has upgraded at least one of the steam turbines on 9 of the 12 units in 

its fleet and the entire turbine train has been replaced on all eight of its largest units. Commenters 

stated that however, projects completed prior to 2012 will not be counted toward the 6 percent 

heat rate reduction. Commenters stated that Ameren estimates that an additional 1-1.5 percent 

heat rate improvement could be achieved. Commenters stated that the Empire District Electric 

Company (Empire) recently completed efficiency projects for a total heat rate improvement of 

4.45 percent; and that Empire estimates it can achieve another 1.73 percent heat rate reduction.

Commenters stated that Kansas City Power & Light Company and KCP&L Greater Missouri 

Operations Company (collectively, KCP&L) identified 35 projects that would decrease the heat 

rate at its coal-fired generating units, for a total heat rate reduction of 1.6 percent.

Commenters stated that almost all projects improving operating efficiency have already been 

completed because the power industry has an incentive to operate its units at peak efficiency, so 

analyses must be undertaken to determine if there are remaining opportunities for heat rate 

improvement projects. Commenters stated that even though many facilities have applied basic 

efficiency improvements without being obligated to do so by the CPP, the EGUs do not get 

credit for the improvements made prior to 2012 and would still need to meet the six percent heat 

rate improvements to comply with the BSER for Building Block 1. Commenters stated that 
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EPA's refusal to consider past projects is unreasonable and unjustified and the proposed CPP 

punishes EGUs like them that have been proactive and worked diligently to ensure that their

units operate efficiently. 

Comments addressing improvement projects, programs and initiatives (units not specified) prior 

to the 2012 baseline, therefore do not count towards target and making an additional 6% HRI 

difficult or impossible to achieve

Commenters stated that because of the 2012 baseline year Georgia will not be able to count large 

equipment upgrades and operational improvements that took place before 2012 towards meeting 

its state goal. Commenters stated that many large investments in operational improvements and 

equipment upgrades took place in Georgia from 2008 through 2012 to comply with GA Rule 

391-3-1-.02(2)(sss) - Multipollutant Control for Electric Utility Steam Generating Units. 

Commenters stated that by using 2012 as the base year, EPA gives no credit to Texas for having 

already achieved a significant amount of EPA's Block 1 goals. Commenters cited NERC stating 

in its November 2014 reliability assessment of Rule 111(d): NERC is concerned that the 

assumed improvements may not be realized across the entire generation fleet since many plant 

efficiencies have already been realized and economic heat rate improvements have been 

achieved. Commenters stated that multiple incentives are in place to operate units at peak 

efficiency, and periodic turbine overhauls are already a best practice.

Commenters further cited EPRI: [Heat rate improvements] may also not be achievable or 

justifiable at every coal-fired plant. In many cases, staff at many well-performing plants have 

been proactive and already implemented some of the possible improvements (e.g., steam turbine 

upgrades, remote monitoring centers, etc.), thus reducing the potential for further maximum heatrate improvement.

Commenters concluded that the use of an arbitrary average 6% heat rate improvement factor in 

setting Texas's emissions rate is flawed because it fails to reflect that most generators in Texas 

have already made many of the improvements cited as rationale for that standard and fails to 

credit Texas for the improvement already made through use of the 2012 base year. Commenters 

stated that EPA must remedy this flaw through one of two options: First, rather than use an 

arbitrary 6% heat rate improvement requirement on all units, EPA should have instead performed 

an analysis as to which plants have not already implemented the improvements identified in the 

technical support documents and only required those power plants to implement those costeffective and technically feasible practices. Commenters stated that alternatively, EPA should 

use an earlier date of 2002 for purposes of measuring the base from which the heat rate 

improvement would be calculated. Commenters stated that finally, EPA should account for the 

impacts of increased renewable energy generation on power grids; namely the degradation of 

heat rates as coal plants are ramped up and down to accommodate the intermittency of wind and 

solar power.

Commenters stated that many units have already undertaken equipment upgrades and as such, 

the potential for additional improvement is marginal. Commenters stated that steam turbine 

upgrades represent the most significant heat rate improvement option available to the industry 

and to date, 86% of their coal-fired generating capacity that will still be in service in 2020 and 

beyond undertook steam turbine upgrades prior to 2012. Commenters concluded that these units 
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would receive no credit for these upgrades, and have limited options for additional heat rate 

improvements since turbine upgrades are generally the most effective heat rate improvement 

option available to reduce emissions.

Commenters stated that EPA seems to assume that all coal-fired EGUs across the country 

operate in a persistently degraded and inefficient state. Commenters stated that while coal-fired 

EGUs experience natural degradation in heat rate over time, they actively seek to recover lost 

heat rate consistent with providing cost-effective and reliable electric power service, and that for 

decades, their business practice has been to work to maintain and reduce heat rates over the life 

of the operating units. Commenters stated that, to minimize heat rate degradation, their system, 

which includes each operating company, has an aggressive heat rate monitoring and 

improvement program that has existed for over 40 years aimed at keeping heat rates as low as 

possible. Commenters stated that, as part of this program, they strategically and economically 

implement best practices and efficiency projects across their coal fleet to minimize heat rate such 

as condenser cleanings, installation of digital control systems, and like-kind replacements of 

degraded equipment. Commenters stated that, as an example, since 2005, Mississippi Power 

Company and Gulf Power Company have expended over $85 and $100 million respectively on 

projects that have helped maintain net heat rates at their coal-fired EGUs.

Commenters stated that, in addition, they set yearly heat rate recovery goals across the coal-fired 

fleet based on the best attainable heat rate from the previous year, which typically results in 30 to 

50 Btu/kWh (< 0.5 percent) of recovered heat rate. Commenters stated that EPA's projected heat 

rate "improvements" do not properly take into account the industry-wide processes already in 

place, in effect requiring entities like them to reduce heat rates by an additional six percent above 

and beyond the results already achieved. Commenters stated that to expect them to reduce heat 

rates by an additional six percent is not feasible given their longstanding implementation of best 

practices and equipment upgrades.

Commenters believed that EPA's analytical assumptions for heat rate improvement projects are 

not practicable and in some cases technically infeasible because efficiency improvements may 

already be completed or in place at existing coal-fueled units which are expected to continue 

operating after 2020, because new emissions control equipment installed for compliance with 

other environmental programs will require additional station power use and reduce plant 

efficiency from the level used as a baseline in EPA's goal-setting calculation, and because 

implementation of Building Blocks 2 and 3 may offset emissions reductions achieved by 

Building Block 1.

Commenters stated that they have reviewed their EGUs in light of EPA's analytical heat rate 

assumptions. Commenters stated that minimizing heat rate (maximizing unit efficiency) is a key 

operating objective for their coal-fueled generating units. Commenters stated that their company, 

like many utilities, have an economic incentive to improve operating efficiencies and therefore 

already exercise best operating practices and implement capital projects to improve heat rate 

where economically justified. Commenters stated that a number of the equipment upgrades or 

changes suggested in the S&L report were implemented by their company on generating units 

during or before 2012, including turbine section replacements, which provide the most 

significant opportunity to improve heat rate at a coal-fueled facility. Commenters stated that 

other efficiency improvement projects, such as cooling system heat loss recovery, flue gas heat 
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recovery, low-rank coal drying, expanded use of energy efficiency equipment and combined heat 

and power operations, have been deemed to be technically infeasible for their units. Commenters 

stated that some of their units were the first coal-fueled units in the country to specifically 

undertake greenhouse gas best achievable control technology ("BACT") reviews subsequent to 

the issuance of the GHG BACT requirements; these BACT reviews affirmed that these measures 

were not feasible.

Commenters stated that the benefits from the pre-2012 heat rate improvement actions cannot be 

repeated in the coming years and are reflected in the 2012 CO2 emissions baseline. 

Commenters stated that in its analysis of equipment upgrades EPA states, "EPA expects that a 

significant fraction of the coal fleet has already applied some or many of the available HRI 

methods". Commenters stated that there is no mechanism for units already meeting BSER for 

HRI in 2012 to be excluded from the BSER requirement or for a state to take credit for it in its 

plan. Commenters recommended the proposed rule be altered significantly to allow the topperforming units to be excluded or given credit for previous efficiency upgrades. 

Commenters believed that the establishment of a 2% or 4% heat rate improvement requirement 

for the state is arbitrary, inconsistent with the CAA, and based on inadequate analysis. 

Commenters stated that Building block 1 assumes that the average heat rate of affected fossil 

units decreases 6%, however, EPA's basis for concluding that a 6% efficiency improvement for 

all affected units is possible, much less reasonably achievable, is not supported by the facts. 

Commenters stated that application of building block 1 would not account for efficiency gains 

made before 2012, and in effect would further disadvantage units that have already made 

efficiency improvements before this time. Commenters stated that in the application of the 

building block approach under the proposed rule, Arizona would have to retire or otherwise 

eliminate all coal by 2020 to meet interim goals (pursuant to building block 2), which would 

essentially eliminate this building block as a compliance option for Arizona. 

Commenters stated that a unit by unit analysis must be undertaken to determine if there are 

remaining opportunities for heat rate improvement projects. Commenters stated that though 

many facilities have applied basic efficiency improvements without being obligated to do so by 

the CPP, EGUs do not get credit for improvements made prior to 2012 and would still need to 

meet the 6% heat rate improvements to comply with BSER for Building Block 1. Commenters 

stated that EPA's refusal to consider past projects is unreasonable, arbitrary and unjustified and 

the proposed CPP punishes EGUs that have been proactive and worked diligently to ensure their 

units operate efficiently. 

Commenters stated that given the lack of heat rate improvement projects available, EPRI 

estimates that there may be opportunities to achieve heat rate improvements in the range of 0.5 to 

5%; however, the highest estimate would not rise to the 6% average heat rate improvement 

required by EPA in Building Block 1. Commenters stated that the Indiana Utilities Regulatory 

Commission states that facilities in Indiana can only obtain heat rate improvements of 1 to 3%, 

far short of the 6% proposed by EPA. Commenters stated that EPA's Building Block 1 proposal 

is further confused by the agency's proposal to use gross heat rate data when measuring heat rate 

improvement. Commenters stated that this calculation method is inconsistent with the net 
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emission accounting method used in computing state goals. Commenters stated that inconsistent 

calculations cause confusion and inaccuracies. 

Commenters stated that the EPA has estimated that a six percent reduction in the CO2 emission 

rate of the coal-fired EGUs in a state, on average, is a reasonable estimate of the amount of HRI 

that can be implemented at a reasonable cost through a combination of best practices and 

equipment upgrades. Commenters stated that however, the various efficiency projects that have 

either been considered or have recently been implemented at their facilities cannot achieve the 

proposed six percent HRI goal; especially given the fact that efficiency improvements prior to 

2012 do not count toward the six percent HRI. 

Commenters stated that as the proposed language of the rule indicates, projects that have been 

completed prior to 2012 will not be counted toward the six percent HRI goal and will make it 

extremely difficult, if not impossible, to achieve an additional six percent improvement. 

Commenters stated that they have implemented efficiency projects at various facilities recently 

and prior to 2012. Commenters stated that projects such as steam turbine retrofits (which can 

provide some of the best single heat rate efficiency gains) completed prior to 2012 will not be 

counted and instead are included in the baseline numbers of 2012. Commenters stated that plant 

energy efficiency projects completed prior to 2012 should be given consideration in establishing 

state HRI targets as well. Commenters stated that the model should use data from the years 

around 2005 to better account for early emissions reductions that were achieved prior to 2012. 

Commenters stated that while they agree that many efficiency improvement measures have the 

potential to pay for themselves over time, this is not universally the case. Commenters stated that 

they are now in a position in which they have made all of the sensible improvements (none of 

which increased emissions of any pollutant) to their workhorse steam units and have no more left 

to exploit. Commenters stated that as a result, they would be penalized for these improvements, 

as would any other plants that proactively moved to improve efficiency prior to 2012. 

Commenters stated that their analysis reveals that, while not linear, coal-fired heat rates have 

decreased approximately 21 BTU/kW-h per year since 1997 and continue to drop. Commenters 

believed that much of this improvement is the result of increasing deregulation and competition 

in Ohio's power market, which provides strong profit motives to utilities to operate as efficiently 

as possible. Commenters stated that in 2013, Ohio coal-fired utilities had an average heat rate of 

9,464 BTU/kW-h. Commenters stated that this heat rate demonstrates clearly that Ohio's fleet is 

highly efficient, largely due to effects of deregulation, which began in 2001 and are continuing to 

expand. Commenters stated that furthermore, they estimate that after the retirement of 

approximately 30 coal-fired units in the state by 2016 due to the MATS, the average heat rate 

(gross) of Ohio's fleet will be approximately 9,287 BTU/kW-h. Commenters stated that Ohio's 

coal-fired fleet will represent a fleet of highly controlled and efficient units. Commenters stated 

that it is concerning that the proposed rule will not enable states to take credit for significant 

HRIs due to the shutdown of older, less efficient units. Commenters stated that for Ohio, this 

would represent a HRI of approximately 5.4%, based on 17 years of heat rate data. Commenters 

stated that these shutdowns also represent substantial reductions in CO2 emissions.

Commenters stated that a review of pertinent data for Units 1 and 2 at SRP's Coronado 

Generating Station illustrates the type of information that EPA would have collected if it had 
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undertaken the data-gathering that is crucial for reasoned decision-making. Commenters stated 

that first, EPA would have seen that SRP already performed several of the equipment upgrades 

identified in the 2009 Sargent & Lundy study for these units before 2012, eliminating 

opportunities for heat improvements relative to a 2012 baseline. Commenters stated that as 

detailed in a recent study performed by Sargent & Lundy, rather than an opportunity for an 

aggregate heat rate improvement of four percent as suggested by EPA, the achievable 

improvement in net heat rate through equipment upgrades at each of the two coal-fired EGU's at 

their Coronado Generating Station is at most one percent. Unit Heat Rate Improvement Study at 

Coronado Generating Station (SL-012487), November 13, 2014. Sargent & Lundy. 

Commenters stated that it is standard practice in the utility industry to utilize preventative 

maintenance and routine cleaning practices that promote and sustain efficient operations and that 

they, along with other utilities, the Electric Power Research Institute (EPRI), and power plant 

system original equipment manufacturers (OEMs) have for years participated in industry 

workshops, users group meetings and other forums to share best operating and maintenance 

practices to improve overall plant performance. Commenters stated that many of these targeted 

efforts have specifically focused on improving heat rate, i.e. reducing the amount of fuel 

consumed to generate electricity, thus lowering operating costs, but yet, the CPP offers no credit 

for proactive efforts like these, and the amount of heat rate improvement contemplated by EPA is 

very aggressive and overly ambitious for units that have historically been well maintained and 

operated. Commenters stated that for recently constructed coal units that were built with more 

advanced and more efficient technologies, many of the potential heat rate improvement 

opportunities have already been incorporated into their base designs. Commenters concluded 

that any potential improvement opportunity will be minimal and certainly far from the 6% level 

that EPA has considered in the proposed rule. 

Commenters stated that many units have already undertaken equipment upgrades and as such, 

the potential for additional improvement is marginal. Commenters stated that steam turbine 

upgrades represent the most significant heat rate improvement option available to the industry 

and to date, 86% of their coal-fired generating capacity that will still be in service in 2020 and 

beyond undertook steam turbine upgrades prior to 2012. Commenters concluded that these units 

would receive no credit for these upgrades, and have limited options for additional heat rate 

improvements since turbine upgrades are generally the most effective heat rate improvement 

option available to reduce emissions.

Commenters stated that approaches are flawed, resulting in overly optimistic projections for 

fleet-wide HRI that may result in state emission rate targets that are unachievable. Commenters 

stated that EPA also overestimated the value of fuel costs savings to an affected EGU. 

Commenters stated that EPA should revise the analyses used to determine the potential fleetwide HRI that could result from both O&M "best practices" and equipment upgrades. 

Commenters also stated that EPA made no effort to establish whether the identified "best 

practices" already have been deployed on any unit included in its analysis. Commenters stated 

that as EPA notes, there is an apparent trend of improving (decreasing) heat rates over time. See 

Abatement Measures TSD at 2-18. Commenters stated that one cause of such a decrease could be 

implementation of the very "best practices" measures that EPA recommends to improve heat 

rates. Commenters stated that in other words, it is plausible that EPA is correct that a four 

percent improvement in historic heat rates was possible, and in fact already has been achieved or 
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largely achieved. Commenters stated that EPA notes that the fleet heat rate in 2008 was three 

percent less (improved) than in 2002. See Id. at 2-29. Commenters stated this improvement may 

be related to improved O&M and other efforts to decrease heat rates. Commenters stated that 

moreover, electric utilities have strong financial incentives to deploy measures that improve heat 

rate because of fuel savings. Commenters stated that these measures often provide greater 

reliability and fuel supply certainty as well, thus providing additional economic incentives. 

Commenters stated that these factors argue that the improvements sought by EPA and suggested 

by the S&L report may already be "baked into" the existing fleet and cannot be "counted twice." 

Commenters stated that EPA has made no effort to determine if these measures have already 

been implemented and to adjust the analysis accordingly. 

Commenters stated that the Building Block 1 presumption that an average 6% heat rate 

improvement (HRI) for coal-fired EGUs is attainable in South Dakota is not supported by the 

record. Commenters stated that Big Stone Plant has a proud history of "best operating practices" 

and efficiency upgrades, and it should not now be penalized for early, proactive measures to 

reduce emissions prior to EPA's announcement of the Clean Power Plan. Commenters stated that 

furthermore, Big Stone Plant is already planning to complete the remaining large efficiency 

improvement projects identified by the Sargent & Lundy report during a scheduled 2015 outage 

and although these projects alone will improve overall net plant heat rate (on the order of 1%), 

EPA overlooks the fact that Big Stone Plant will also be installing a state-of-the-art AQCS 

during the same outage, which will essentially eclipse these HRIs due to the energy-intensive 

nature of the system. Commenters stated that EPA should allow South Dakota to take credit for 

improvements already made at Big Stone Plant and also allow an offset for the substantial new 

station service requirements of the AQCS required by EPA's Regional Haze and MATS rules. 

Commenters stated that EPA's unrealistic 6% heat rate improvement sought under Building 

Block 1 is based on an incomplete analysis. Commenters stated that almost all projects 

improving operating efficiency have already been completed because the power industry has a 

strong incentive to operate their units at peak efficiency, so analyses must be undertaken to 

determine if there are remaining opportunities for heat rate improvement projects. Commenters 

stated that EPA's analysis of past heat rate improvements at existing EGUs does not demonstrate 

that future heat rate improvements can be performed to reduce CO2 emissions, rather, past heat 

rate improvement projects illustrate that the utility industry has a strong incentive to maximize 

operating efficiency and has already undertaken heat rate improvements. Commenters stated that 

such improvements are unit-specific, and are either not feasible, already in place, or not 

economic and therefore, if such projects existed, EGU owners would have completed them 

already. Commenters stated that there simply are not additional efficiency projects that EGUs 

can perform to achieve a 6% improvement in heat rate. 

Commenters stated that EPA has not taken into account that those not-for-profit utilities 

operating generation resources on a cost basis have already implemented best practices to 

increase the operational efficiency of power plants and as a result additional efficiencies are not 

attainable at most EGUs. Commenters stated that the proposed six percent heat rate 

improvement for coal generation is unrealistic and unfortunately, as drafted, the Proposal do not 

take into account past best practices and creates a scenario where additional plant efficiencies 

cannot be gained and will result in the forced closure of beneficial and efficient resources.
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Commenters stated that EPA's blanket assumption that all coal-fired steam EGUs can attain an 

average of 6% heat rate improvement fails to account for the fact that their utility and other 

South Carolina utilities have been making significant efforts to reduce CO2 through efficiency 

improvements even before the Proposed Rule. Commenters stated that rather than rewarding 

them and other utilities for making these improvements, the Proposed Rule would penalize them

for being proactive in reducing emissions through heat rate improvements.

Commenters stated that EPA's methodology for existing coal-fired EGUs HRI is punitive to 

states that have been forward-thinking with respect to pollution reduction, such as North 

Carolina in that Building Block 1 unfairly penalizes EGUs that have already undertaken HRI and 

achieved heat rate improvements below the national average. Commenters stated that the 

methodology penalizes the ratepayers that have borne the costs of early retirements, natural gas 

conversions and emissions controls. 

Commenters stated that every unit is different and that some companies have made more heat 

rate improvements on EGUs than others. Commenters stated that EPA's assumption in setting the 

6 percent requirement appears, at best, to be for units that have not made any significant heat rate 

improvements and this simply is not true as an average across the fleet and could result in 

punishment for those who made early improvements. 

Commenters stated that heat rate improvements of 6 percent under Building Block 1 are 

significant and unlikely to be achieved at plants that have already made efficiency improvements 

prior to the 2012 reference year. Commenters provided the following information as evidence 

that a heat rate improvement of 6 percent is not technically or economically achievable in New 

Hampshire.

Commenters stated that in 2008, they did undertake an important energy efficiency project at its 

Merrimack Station. Commenters stated that a high pressure/intermediate pressure (HP/IP) 

turbine energy efficiency project was completed at Merrimack Unit 2, their largest coal unit and 

this energy efficiency project was undertaken to increase the output of the unit utilizing the same 

amount of fuel burn, resulting in less emissions for the same energy output and an approximate 5 

percent heat rate improvement. Commenters stated that this very successful effort confirms there 

are unique but limited opportunities for this type of heat rate improvement projects; and smaller 

units would have little to no similar cost effective opportunities. Commenters stated that it must 

be noted that the ability to make similar efficiency gains at other of their units is not likely. 

Commenters stated that Original Equipment Manufacturers (OEMS) and after-market equipment 

suppliers must have made large investments in retrofit design, development, and manufacturing 

of more efficient, upgraded equipment and these opportunities are not common. 

Commenters stated that EPA's assumptions are unrealistic and unachievable for most, if not all, 

fossil-fueled EGUs. Commenters stated that most electric utilities-including their members-have 

already implemented most of the best practices and equipment upgrades identified by EPA. 

Commenters stated that furthermore, to the extent that some equipment upgrades may be 

available, the costs of implementing these upgrades at affected units would generally be 

prohibitive. Commenters stated that EPA's approach fails to consider the impact of subsequent 

building blocks on the emission rate reductions that could be achievable at coal-fired steam 

EGUs.
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Commenters stated that as a rural electric generation and transmission cooperative, they are

constantly investigating, evaluating, and implementing efficiencies at all facilities, as well as 

updating all processes and practices in order to provide the most reliable and economical energy 

to their Member Systems. Commenters stated that at Plant Morrow, their coal fired generating 

facility, they have invested over $10.5 Million over the last several years on numerous efficiency 

improvement projects achieving a conservatively estimated 3% efficiency improvement. 

Commenters stated that EPA does not consider these past improvements when adjusting the 

state's CO2 emission rate nor considers whether an additional 6% on top of the previous 

achievements is even possible. 

Commenters stated that the 6% heat rate improvement anticipated in this Building Block is not 

realistic and EPA's analysis of past heat rate improvements at existing EGUs does not 

demonstrate that future heat rate improvements can be performed to reduce CO2 emissions. 

Commenters stated that rather, past heat rate improvement projects illustrate that the utility 

industry has a strong incentive to maximize operating efficiency and has already undertaken heat 

rate improvements. Commenters stated that as explained by IHS Energy," such improvements 

are unit-specific, and are either not feasible, already in place, or uneconomic," and therefore, if 

such projects existed, EGU owners would have completed them already. Commenters stated that 

there simply are not additional efficiency projects that EGUs can perform to achieve a 6% 

improvement in heat rate. 

Commenters stated that electric cooperative owners and operators strive to maintain generation 

that is both reliable and affordable and that because cost savings are passed directly to members, 

cooperatives work constantly to ensure that their generating assets are well maintained and 

operated in a way that maximizes electric output for any given quantity of fuel input. 

Commenters stated that as a consequence, many of the heat-rate improvement projects that EPA 

assumes that units will be able to undertake to comply with Building Block 1 of the Proposed 

Rule have already been undertaken, thus making impossible for those units to obtain anything 

close to the 6% improvement in emission rates that EPA proposes. 

Commenters stated that EPA's proposed rule arbitrarily assumes that substantial thermal 

efficiencies can still be obtained from coal plants in Texas. Commenters stated that within the 

ERCOT interconnection that comprises most of Texas there is little room for heat rate 

improvement because the ERCOT market has already forced coal-fired generators to adopt state 

of the art technologies available to improve thermal efficiencies in order to compete effectively. 

Commenters stated that in addition to the specific concerns individual members may submit on 

the technical basis for the six percent heat rate improvement, they are also concerned about the 

equal application of the heat rate improvement factor to all states without recognition of 

investments firms may have recently made to improve the heat rate of existing coal-fired fleets. 

Commenters stated that in a number of states where member companies operate, investments 

have been made to improve the heat rate of some units. Commenters stated that EPA could 

provide a mechanism to recognize recent investments that have resulted in improved power plant 

efficiency. Commenters stated that to that end, they would support a standardized process for 

states to demonstrate that owners or operators of specific, in-state units have made recent 

investments that resulted in clear efficiency improvements within a timeframe defined by EPA. 
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Commenters stated that if states were to make such a public demonstration, EPA would adjust 

the assumed availability of heat rate improvements in that state. 

Commenters stated that Block 1 allows existing plants to improve their efficiency by 

implementing new measures. Commenters stated that the problem arises when most plants, such 

as the plants in North Dakota, have already done all of the things EPA thinks can be done. 

Commenters stated that in some cases, recent investments already have been made to improve 

the heat rates of existing coal-fired units - for example, many large coal-fired units have already 

had turbine overhauls, the projects with the largest potential heat rate improvement in the S&L 

study. Commenters stated that additional efficiency gains of the magnitude proposed in the rule 

would be unfeasible both physically and economically. 

Commenters stated that the proposed six percent efficiency improvement does not recognize the 

incentives companies have already and continually have made to improve efficiency and reduce 

fuel costs and that electric utilities have strong financial incentives to deploy measures that 

improve efficiency because of fuel savings. Commenters stated that EPA made no effort to 

determine if these measures have already been implemented and to adjust the analysis 

accordingly and that EPA's approach does not recognize recent investments companies have 

made to improve the heat rate of existing coal-fired EGUs; for example, turbine overhauls, 

economizer replacement, APR seal and basket replacement, fan VFDs, condenser cleaning, etc. 

Commenters stated that the FGD modifications do not apply to the type of FGDs they have and 

only two out of their nine surviving coal units have cooling towers that could be repacked and 

that the condition of those units does not warrant replacement at this time.

Commenters stated that HRI projects would have significant impact on the older, less efficient 

units. Commenters stated that in their system, most of these units are either being retired or have 

been converted to natural gas and the remaining units in the system (total of about 250 MW) will 

have a very small impact on Virginia's state emission rate when compared to the much larger 

coal units. Commenters stated that at a minimum, if a state can demonstrate that HRI projects 

already have been implemented at in-state affected coal-fired units, they request that EPA 

recalculate state emission rate goals accordingly.

Commenters referred to the Belews Creek station in North Carolina, the second most efficient 

coal plant operating in the US last year according to Electric Power & Light. Commenters stated 

that Belews Creek plant design is based on the most efficient design at the time of its 

construction and uses best operating practices resulting in high operating efficiency and that due 

to these factors it will have difficulty improving its heat rate. Commenters believed that it will 

have difficulty in achieving the stated 6% goal even if it is averaged into the North Carolina grid 

due to its size (approximately 2,300 MW) and high capacity (80%) factor. 

Commenters stated that many fossil units have already performed part, if not all, of their 

theoretically possible upgrades or improvements prior to the effective date of the rule, thus 

rendering most units' ability to achieve either target extremely difficult if not impossible.

Commenters stated that many fossil units have already performed the proposed improvement 

options, making it impossible to achieve further improvements.
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Commenters stated that many coal plants have already made investments in many of the heat rate 

improvements EPA relies on as incrementally available, which means they are no longer 

available as broadly as EPA assumes 

Commenters stated that Illinois requests USEPA reassess the viability of achieving the 6% heat 

rate improvement rate. Commenters stated that nearly all Illinois affected sources have indicated 

that if a 6% fuel savings was possible in the manner USEPA suggests, any such modifications to 

plant equipment and operation would have already been made as an economic priority. 

Commenters stated that sources have expressed to the Illinois EPA that several variables impact 

heat rate over a given time period, including varied operating capacity, changes in fuel type, 

burner modifications, installation of new control equipment, and other equipment changes. 

Commenters urged that these factors be considered in USEPA's analysis of achievable heat rates. 

Commenters stated that cost effective early deployment of turbine generator efficiency 

improvements on Minnesota coal units have already been implemented, delivering the 

greenhouse gas emission reductions from Minnesota coal generating units under early action that 

EPA is now proposing for the CPP. Commenters stated that these improvements were made after 

determinations by Minnesota regulators that the projects were cost effective, as part of utilities' 

resource planning or rate recovery proceedings. Commenters further stated that the Minnesota 

Public Utilities Commission (MPUC) has required Minnesota utilities to adopt heat rate 

improvement projects and maintenance practices that optimize the balance between preserving 

unit operating efficiency and dispatch capability and that these measures help preserve the 

dispatch capability of an electric generating unit. Commenters stated that preservation of 

dispatch capability helps assure that the value of generation resources is retained over time, as 

utility, customer and energy market needs continue to evolve. Commenters stated that integrated 

resource planning, regulated by the MPUC, is part of what guides the process for deployment of 

new resources and dispatch capability of existing generation resources. 

Commenters further stated that it is notable that the report prepared by Sargent and Lundy (S&L 

Coal-Fired Power Plant Heat Rate Reductions, Final Report SL-009597, Project 12301-001, 

January 22, 2009, the "Sargent and Lundy Report") from which EPA identified potential Block 1 

generating unit efficiency options, referenced in EPA's CPP Block 1 Technical Support 

Documentation, pre-dates deployment of the turbine upgrades that improved heat rate 

performance of Minnesota Power units. Commenters stated that the S&L analysis cites some of 

the very measures deployed by MP among those it suggests for efficiency improvements, just as 

the report also recognized that variances between units preclude the deployment of all measures 

identified by S&L on all electric generating units. 

Commenters stated that U.S. EPA made no attempt to identify and correct for in its statistical 

analysis those HRI measures that have already been implemented or installed. Commenters 

stated that although stated in the GHG Abatement Measures TSD that U.S. EPA recognizes that 

some of these measures have already taken place, the statistical analysis performed ignores this. 

Commenters stated they believe that this is a major oversight, and that to understand what is 

possible beyond HRIs already made at the existing coal-fired fleet U.S. EPA must conduct a 

thorough engineering study of the coal-fired fleet and rely on measured HRI data.
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Commenters stated that despite having been proactive in reducing CO2 emissions from the 

State's electric generating fleet, the electric cooperatives and other electricity providers in South 

Carolina are disproportionally impacted by the proposed EPA rule. Commenters stated that 

South Carolinians will have to bear the burden of making the largest carbon intensity reduction 

in the nation, and stated that EPA says they must drop from 1,587 lbs/MWH to 772 lbs/MWh by 

2030. Commenters stated that EPA assigned one state which has a similar CO2 emission rate of 

1,552 lbs/MWh a target reduction of just 16 percent. Commenters stated that assignments for 

other states are similarly inconsistent. Commenters stated that EPA should be consistent in its 

rules so that it doesn't penalize states that have been early investors in carbon-free technology 

and those who have limited access to additional natural gas resources. Commenters stated that 

EPA's proposal should not place additional burdens on particular states as to other generation 

options due to inconsistent results when applying EPA's model. 

Commenters stated that EPA's assumption fails to consider the efforts companies have already 

undertaken to improve heat rate 

Commenters stated that EPA erroneously assumes that all coal-fired units can implement 

efficiency projects that will yield a six percent improvement in the unit's heat rate and as an 

initial matter, EPA fails to consider the substantial efforts that companies have undertaken to 

maximize heat rate; the most cost-effective projects have long-since been accomplished because 

every marginal improvement in the heat rate lowers the fuel costs, which lowers the rates. 

Commenters stated that Otter Tail Power Company operates in jointly-owned Big Stone Plant, 

the one coal-fired power plant in South Dakota and that Building Block 1 is technically 

unfeasible because the Big Stone Plant already has performed the available significant heat-rate 

improvement projects.

Commenters stated that the 6 percent heat rate improvement is unachievable and in order to 

produce electricity as efficiently, reliably, and cost-effectively as possible, utilities have already 

undertaken measures to optimize the efficiency.

Commenters stated that EPA presumes that plan operators do not already run and maintain their 

facilities by best practices to minimize the unit costs, and if they're already doing so it certainly 

cancels projected heat rate improvement. 

Commenters stated that many of the projects the EPA cites in the rule have already been done or 

are being done on a routine basis at existing power plants. Commenters stated that EPA 

acknowledges that some of these projects have already occurred, but doesn't factor those 

reductions into the emissions targets and credit should be given for having already completed 

these projects and not hold states and utilities to more stringent, unachievable emission rate 

target that does not represent the best system of emission reduction.

Commenters stated that the rule begins its data baseline in the year 2012 which tends to ignore 

actions prior to that date and further, the target-setting process embeds mechanisms, some of 

which may have been unintentional that further ignore early action. Commenters stated that 

Block one ignores any heat rate improvements already done at coal units.
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Commenters referred to EPA's HRIs. Commenters presented a table stating that Big Stone Plant 

has already implemented, or plans to implement within the next year, all of the applicable HRI 

measures identified in the TSD 

Commenters stated that although they did not doubt that EPA's heat rate data demonstrates that 

certain EGUs have improved their efficiency through best practices and equipment upgrades in 

the past, they cannot see how this data demonstrates that the current fleet will be capable of such 

significant improvements in the future. Commenters stated that there is a limited universe of 

practices and equipment upgrades that existing EGUs can implement to improve their heat rates. 

Commenters stated that because they have strong incentives to operate at high efficiencies, most 

EGU owners and operators have likely implemented most, if not all of the "low-hanging fruit," 

leaving little room for additional improvement. Commenters stated that EPA has not adequately 

considered the possibility that past improvements in the efficiency of the EGU fleet have made 

future improvements more difficult, if not wholly unachievable.

Commenters stated that EPA's assumption that existing sources can increase their efficiency by 

six percent on average is not supported by the evidence and is unreasonable. Commenters stated 

that companies are in the business of operating as efficiently as possible and most have already 

have taken all of the steps necessary to operate as efficiently as possible. Commenters stated that 

most of the measures EPA relies on to support its assumed efficiency gains have either been 

adopted by their facility or would not meaningfully reduce heat rates at their EGUs.

Commenters stated that EPA initially assumes that the heat rate improvements that may be 

achievable at a hypothetical EGU at which those improvements have not already been made are 

informative as to the achievable improvements in heat rate for the fleet of twelve coal-fired 

EGUs in Arizona. Commenters stated that EPA recognizes and acknowledges that this 

assumption has no basis "because the EPA expects that a significant fraction of the coal fleet has 

already applied some or many of the available [heat rate improvement] methods."

Commenters stated that EGU operators have a financial incentive to improve heat rate at their 

facilities. Commenters stated that considering that the entire fleet of coal-burning EGU's was 

evaluated over an extended period of time, there were likely dozens, if not hundreds, of 

individual equipment upgrades and improvement programs undertaken at EGUs that resulted in 

real heat rate improvements prior to issuance of the Proposed Rule. Commenters stated that 

because the statistical analysis focused largely on year-to-year changes to capacity factor and not 

on other relevant factors, many improvements to heat rate were essentially unrecognized and the 

underlying conclusion was that heat rate improvement measures were not being undertaken and 

represented a significant opportunity for lowering greenhouse gas emission rates across the coalburning EGU fleet. 

Commenters stated that the efficiency improvement for existing coal-fueled power plants should 

be reduced from 6% to 1%. Commenters stated that their utility and other utilities already utilize 

"best practices" and cannot achieve the improvement envisioned in the rule. Commenters stated 

that the most efficiency improvement that could be achieved at Spruce 1 is less than 1% and that 

would require significant investment. Commenters stated that lowering the efficiency 

improvement standard for existing plants proposed in Building Block 1 will reflect realistic and 
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achievable efficiency gains based on the operational limitations of existing coal-fueled power 

plants and take into account the efficiency improvements already implemented.

Commenters stated that as shown in the Heat Rate TSD, many of the projects identified in the 

S&L and NETL studies do not provide opportunities for heat rate improvements at their units 

because they has already implemented these projects in order to maintain a highly efficient unit, 

and they cannot be duplicated. Commenters stated that these projects were accomplished because 

they operate in a competitive market and thus implement heat rate improvement projects when 

those improvements can be implemented economically and as such, many of the heat rate 

improvements that EPA assumes are available to coal-fueled EGUs are no longer available to 

their facility and likely not to other units operating in other competitive and potentially regulated 

markets.

Commenters stated that using a national average heat rate improvement penalizes early action by 

not recognizing and taking into account those improvements that have already been made at 

individual facilities. Commenters stated that for example, the operators of the San Juan 

Generating Station have already made improvements to their generators, resulting in an 

approximately 3% heat rate improvement. Commenters stated that the retrofits included 

replacement of pulverizer classifiers, boiler tube sections, burners, piping and headers, Venturi 

throats, air heaters and feedwater heater tubes. Commenters stated that new heater seals have 

been installed, as have baghouses to replace the electrostatic precipitators and this facility has 

undergone boiler cleaning and turbine overhaul as well. Commenters stated that these 

improvements were made before 2010 and were not considered when EPA looked at national 

average heat rate improvement opportunities. 

Commenters stated that their supplier has indicated that there is minimal heat rate improvements 

remaining to be made at their two coal-fired generating units as those improvements and 

investments have already been completed prior to the issuance of this proposal. 

Commenters asked how is a target achievable if it is asking units to duplicate reductions that 

have already been achieved.

Commenters stated that in developing Building Block 1, EPA performed statistical analyses on 

2002-2012 data, found statistically significant variability in heat rates across existing coal-fired 

EGUs, and concluded that, on average, gross heat-rate improvements of 4 percent are feasible 

among those EGUs. Commenters stated that EPA then used a 2009 Sargent & Lundy study of 

potential equipment upgrade options and other reports to suggest that additional improvements of 

2 percent are possible. Commenters stated that by adding the two together, EPA established 

Building Block 1 and its mandate of an annual 6 percent heat-rate improvement.

Commenters stated that in principle, heat-rate improvements are not objectionable and, in fact, 

energy companies routinely strive for them without being told to do so by EPA. Commenters 

stated that heat-rate improvements translate to greater efficiency which translates to lower 

operating costs which translates to lower customer rates, however, there are limits to these 

benefits, some of which come incidental to agency involvement. Commenters stated that for 

example, several types of projects routinely undertaken across the industry to improve heat-rate 

performance have been subject to enforcement actions or threats of enforcement actions by EPA. 
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Commenters stated that these challenges often take years to resolve, achieve mixed results in the 

courts, and leave operators reluctant to attempt projects that could improve heat-rate efficiency. 

Commenters stated that Building Block 1 reflects EPA's lack of understanding of the nature of 

heat-rate improvements. Commenters stated that EPA's theoretical model assumes that heat-rate 

improvements, once made, are always effective and create permanent emission reductions but in 

reality, improvements tend to diminish over time as operations continue and equipment becomes 

fatigued. Commenters stated that additionally, EPA incorrectly assumes that the component and 

maintenance improvements discussed by Sargent & Lundy can be freshly implemented at 

regulated EGUs but at their facility several of these improvements were implemented prior to the 

2012 baseline year and therefore cannot help the company meet their targets. 

Commenters stated that decreases in heat rates translate to decreases in cost of operation and it is 

common practice for owners and operators of coal-fired power plants to analyze and employ 

cost-effective measures to improve efficiency through both capital and O&M projects. 

Commenters stated that many power plants may already be operating at peak efficiency and may 

have already implemented many or all of the equipment upgrades, operations and maintenance 

procedures included in the 2009 Sargent & Lundy report. 

Commenters stated that because their plant was designed from the start to incorporate the most 

efficient available technology, it will be extremely difficult to achieve more than a 2 percent 

improvement in the plant's efficiency, and any additional heat rate improvements would likely be 

cost prohibitive if not technically impossible when considering the need to maintain reliable 

plant operations. Commenters stated that EPA's Building Block 1 provides no credit to their 

plant (or Virginia ratepayers) for their initial determination to build and maintain the plant to 

maximize their operational efficiency. 

Commenters stated that EPA fails to adequately justify or disclose its assumptions for each of the 

four building blocks used to establish BSER and in building block one, EPA makes a blanket 

assumption that all coal-fired EGUs are capable of achieving a six percent heat rate 

improvement. Commenters stated that in doing so, EPA ignores the real-world conditions faced 

by coal-fired EGUs. Commenters stated that most coal-fired units in the U.S. already undergo 

regular maintenance and upgrades to improve efficiency as part of good business practices. 

Commenters stated that improving heat rates makes units more competitive from a cost 

perspective and thus unit owners regularly evaluate and have already implemented opportunities 

to improve efficiency and performance and to assume that all coal units could improve their 

performance by six percent ignores the fact that many units have already completed all 

economically feasible unit upgrades and improvements. 

Commenters stated that they are minority owners in PacifiCorp's Hunter 1 plant and Deseret 

Power's Bonanza Plant. Commenters stated that both plants have implemented state of the art 

environmental controls and meet current EPA standards and these plants have already take steps 

proposed by the EPA to be more efficient. Commenters stated that credit should be given to the 

Utah fleet of coal generation compliant with the intent of Block 1. Commenters suggested that 

EPA should focus on those generating units that are less efficient and apply similar standards for 

environmental controls using and mandating best available operating equipment and technology 

to improve heat rates for all plants. 
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Commenters stated that generally, they support EPA's position to apply heat rate improvements 

at coal-fired steam EGUs only. Commenters stated that however, the six percent heat rate 

improvements for each state may not be achievable because EPA fails to recognize the actions 

many companies have taken through the years to maintain and/or continually improve unit 

efficiency and reduce fuel costs. Commenters stated that as an example, starting in 2008 through 

2010, they spent approximately $1.3 billion to install air pollution control technology on the coal 

EGUs at their Mercer and Hudson Generating Stations to significantly reduce emissions of SO2, 

NOx, particulate matter and mercury. Commenters stated that in addition, numerous projects, 

including refurbishment of the steam generator at Hudson unit 2, were undertaken to minimize 

the heat rate losses due to the increase in parasitic load from operation of the new control 

technologies. Commenters stated that the overall percent increase in net heat rate was 4.1 percent 

and in addition, a high-pressure turbine overhaul was completed on Unit 2 at their Mercer 

Generating Station in 2013. Commenters stated that the project resulted in a heat rate 

improvement ranging from three to five percent, however, these improvements are not taken into 

account in the proposed rule as these units are expected to be able to achieve the full six percent 

heat rate improvement goal. Commenters stated that EPA must allow for adjustments in the heat 

rate improvement component of the state-specific target to a level lower than six percent where 

any unit has completed heat rate improvement projects within five years of the baseline period. 

Commenters stated that based on feedback from the wholesale suppliers that sell electricity to 

Colorado's 22 electric distribution co-ops, EPA's suggestion that power plant heat rates, or 

efficiency, can be increased by 6 percent is unrealistic and cannot be achieved in Colorado. 

Commenters stated that all utilities, including electric co-ops, are motivated to run their plants as 

efficiently as possible, and the Plan does not account for the measures that have already been 

implemented at existing coal plants to improve heat rates and maximize operational efficiency. 

Commenters stated that since the purported benefits of this building block are illusory, the 

overall emission reduction goal should be reevaluated to account for a realistic expectation of 

power plant efficiency for Colorado's coal generation resources.

Commenters stated that EPA's assumptions on heat rate improvement are particularly flawed for 

plants in merchant markets like Pennsylvania's and Montana's. Commenters stated that over the 

past decade or so, they have already implemented all realistically achievable efficiency 

improvements at its coal-fired power plants in these states. Commenters stated that their coal 

fleet in Pennsylvania is substantially more efficient than most others in the industry and with 

those investments already made, very little additional improvement is available. 

Commenters stated that there is nothing in the docket or the proposal that allows the commenters

to conclude that EPA evaluated which, or how many, coal-fired power plants have already 

implemented best practices or have installed the types of equipment upgrades the EPA assumed 

can be installed to achieve a 6% improvement in heat rate. 

Commenters stated that EPA has not taken into account that those not-for-profit utilities 

operating generation resources on a cost basis have already implemented best practices to 

increase the operational efficiency of power plants and as a result additional efficiencies are not 

attainable at most EGUs. Commenters stated that the proposed six percent heat rate improvement 

for coal generation is unrealistic. Commenters stated that unfortunately, as drafted, the Proposal 

does not take into account past best practices and creates a scenario where additional plant 
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efficiencies cannot be gained and will result in the forced closure of beneficial and efficient 

resources. 

Commenters stated that some U.S. utilities, including their plant, have been leaders in taking 

action to reduce greenhouse gas emissions. Commenters stated that these utilities have made 

significant investments in anticipation of forthcoming greenhouse gas regulation and the desire 

to get out in front of the expected costs and impacts of such regulation. Commenters stated that 

thus it is surprising and disappointing that the Proposed Rule does not reflect the forward 

progress that these utilities have made in achieving emission reductions. 

Commenters stated that in addition to installing DryFiningTM at Coal Creek Station, over the 

past decade commenters have made sizable investments to improve plants efficiencies such as 

the installation of new state-of-the-art turbine rotors, variable frequency drives on its large 

motors, and turning vanes in its flue gas ductwork. Commenters stated that post-2012, these 

types of improvements cannot be replicated for additional gains in efficiency. 

Commenters stated that proactive efforts should be recognized by EPA through regulation that 

supports a policy to encourage early voluntary actions. Commenters stated that the Proposed 

Rule would, instead, penalize those utilities who took proactive steps to reduce CO2 emissions. 

Commenters stated that in its Proposed Rule, EPA states that implementation will result in a 30 

percent reduction in CO2 emissions from the power sector by 2030 from a 2005 baseline year. 

Commenters stated that in essence EPA touts reductions starting in 2005 without giving credit to 

those who actually took action and achieved reductions. Commenters stated that by not providing 

credit for early action, the Proposed Rule establishes poor public policy that will have the effect 

of repressing voluntary actions in the future. 

Commenters stated that EPA erroneously assumes that all coal-fired units, including those at 

SGS, can implement efficiency projects that will yield a 6 percent improvement in the unit's heat 

rate. Commenters stated that EPA fails to consider the substantial efforts that Seminole and other 

companies have undertaken to maximize heat rate; the most cost-effective projects have longsince been accomplished because every marginal improvement in the heat rate lowers fuel costs, 

which lowers rates.

Commenters stated that they have implemented more than 20 heat rate improvement activities 

over the last 20 years that have each contributed incremental heat rate improvements. 

Commenters stated that EPA's reliance on the 2009 Sargent & Lundy report for this 6 percent 

reduction in heat rate potential is misguided and inappropriate. Commenters stated that in fact, in 

October 2014, Sargent and Lundy issued a letter indicating that "most of the utilities are 

employing best operational and maintenance practices. Commenters stated that in light of this

observation, it appears that significant further reduction in heat rate, such as that assumed by the

EPA, may not be feasible." Commenters stated that Seminole has already performed the most 

beneficial heat rate improvement projects that the S&L report references, including low pressure 

turbine upgrades, fan improvements, and reducing air heater leakage. Commenters stated that 

given these past improvements, it is not technically feasible for Seminole to improve SGS's heat 

rate anywhere near an additional 6 percent. Commenters stated that NERC has also concluded 

that improving heat rate by 6 percent may not be achievable.
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Commenters stated that nearly all of Iowa's generating units operate within the MISO market and 

their owners have a strong economic incentive to improve their heat rate. Commenters stated that 

some Iowa utilities have already made significant heat rate improvements at many of their 

generating plants, including equipment upgrades that have improved plant efficiency, such as 

turbine upgrades and overhauls, installing more efficient fans, boiler work to improve the overall 

efficiency of plants, control system upgrades, and replacement of other equipment. 

Commenters stated that the EGUs subject to NSR enforcement consent decrees are already 

required to implement certain controls and process improvements that limit heat rate variability. 

The commenters stated that as a result of these and other improvements described by the 

commenters, West Virginia EGUs have the second best 2012 coal-fired CO2 emission rate in the 

country, 2,056 lbs CO2/net electricity MWh. Commenters stated if shutdowns in 2013 and those 

anticipated for 2015 are considered, West Virginia's CO2 emission rate would improve only 

slightly, because those plants did not have a high capacity factor in 2012; however, in 2016, 

West Virginia's remaining EGUs would have the lowest CO2 emission rate in the country, 2,048 

lbs CO2/net electricity MWh. 

Comment 18: Applicable to the supplemental proposal for Tribal and Territorial – Comments

that unit specific upgrades made prior to the 2012 baseline should count towards the target

Response 18: For the EPA’s response to these comments, see section V.C of the final rule 

preamble of the CPP and Chapter 2 of the GHG Mitigation Measures TSD supporting the final 

CPP. For example, as discussed in those documents, the EPA’s assessment of potential heat rate 

improvement accounts for HRI measures initiated before or during the study period and 

sustained through 2012.

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

Commenters stated that many power plants may already be operating at peak efficiency and may 

have already implemented the equipment upgrades and operations and maintenance procedures 

included in the 2009 study by Sargent & Lundy.

Commenters stated that a preliminary review of the management practices and other items on 

which EPA relies in Technical Support Document for its "best practices" and "equipment 

upgrades" demonstrates that these have already been implemented at their facility, either in the

initial design phase or through best practices already implemented at the facility. (Reviewing 

listing in EPA June 2014 TSD). Commenters stated that their facility cannot be expected to 

improve heat rate if the plant has already undertaken the measures EPA asserts would have to be 

implemented to achieve the assumed 6% improvement. Commenters stated that indeed, this 

underscores the gross error by the agency were it to proceed with this Proposal and direct Puerto 

Rico to assume these kinds of improvements can be achieved across the board without first 

considering the specifics at their facility when setting an appropriate goal. Commenters stated 

that moreover, in all events, a number of these are not the type of activities cannot be repeated 

more frequently than current practice. Commenters stated that for example, more frequent 
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turbine overhauls are not practical or economical - or feasible under the PPA, because they 

require a unit to be out of service for an extended period of time.

Commenters stated that EPA's unrealistic 6% heat rate improvement sought under Building 

Block 1 is based on an incomplete analysis. Commenters stated that almost all projects 

improving operating efficiency have already been completed because the power industry has a 

strong incentive to operate its units at peak efficiency, so analyses must be undertaken to 

determine if there are remaining opportunities for heat rate improvement projects. Commenters 

stated that EPA's analysis of past heat rate improvements at existing EGUs does not demonstrate 

that future heat rate improvements can be performed to reduce CO2 emissions. Commenters 

stated that rather, past heat rate improvement projects illustrate that the utility industry has a 

strong incentive to maximize operating efficiency and has already undertaken heat rate 

improvements. Commenters stated that such improvements are unit-specific, and are either not 

feasible, already in place, or not economic. Commenters stated that therefore, if such projects 

existed, EGU owners would have completed them already. Commenters stated that there simply 

are not additional efficiency projects that EGUs can perform to achieve a 6% improvement in 

heat rate. 

Commenters stated that EPA has made no effort to determine if best practice measures have 

already been implemented and to adjust the analysis accordingly. 

Commenters stated that no credit for proactive efforts like these is available under the Proposed 

Rule, and the amount of heat rate improvement contemplated by EPA is overly ambitious for 

units that have historically been well maintained and operated. Commenters stated that for 

recently constructed EGUs that were built with more advanced and more efficient technologies 

(like their Dry Fork Station), many of the potential heat rate improvement opportunities listed 

above have already been incorporated into their designs, and O&M practices were optimized 

accordingly. Commenters stated that any potential improvement opportunity will be minimal and 

certainly far from the level that EPA has considered in the Proposed Rule. 

Commenters stated that EPA's finding of a 2% heat improvement necessarily assumes that no 

coal-fired EGUs have already implemented certain equipment upgrades, but in reality, many 

operators have already taken such steps in the interests of both improving generation efficiency 

and lowering emissions. Commenters stated that for instance, EPA's TSD references several 

examples of plants which have made upgrades to turbines, condensers, and other equipment.

Commenters stated that these examples are just the tip of the iceberg- many energy trade groups 

have long touted the economic benefits of improving heat rate, and newer plants often have 

incorporated at least some of these features into their design. Commenters stated that EPA's 

assumption that no facility has exhausted these upgrades is itself contradictory with its own 

simplistic position on cost-effectiveness: if such upgrades indeed reflect low- or no-net cost 

improvements, virtually every facility would have already implemented them. 

Commenters stated that the proposed rule uses a standard assumption of a 6 percent heat rate 

improvement and applies this assumption to all coal units. Commenters stated that this results in 

more stringent goals for states whose coal units have already undergone heat rate improvement 

projects in comparison to states whose coal units are unimproved. Commenters stated that 

further, many utilities have already implemented ongoing heat rate improvement programs to 
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capture the efficiency gains that EPA is assuming would be possible in the "best practices" 

portion of the Building Block 1 assumption, making a further 4 percent improvement unlikely to 

be achievable. Commenters stated that the ability to achieve a 2 percent improvement through 

equipment upgrades will vary from plant to plant. Commenters stated that new coal units and 

coal units that have already implemented heat rate improvement projects will have more 

difficulty achieving further heat rate reductions than older units that have not previously 

undertaken these projects or programs. Commenters proposed that instead of assuming acrossthe-board heat rate improvements for all coal units, EPA should allow states to evaluate the 

potential for, and cost effectiveness of, heat rate improvement projects at individual EGUs on a 

case-by-case basis. Commenters stated that this would allow states with units where such 

projects have already been undertaken to not be penalized for the proactive investment in 

emissions-reducing technology. Commenters stated that at a minimum, EPA should exclude 

from the goal-setting calculation heat rate improvements at new units as well as at units that have 

previously undertaken significant heat rate improvement projects. 

Comment 19: Comments regarding relatively newer EGUs not being able to achieve any 

appreciable heat rate improvement

Response 19: See section V.C of the final rule preamble of the CPP and Chapter 2 of the GHG 

Mitigation Measures TSD supporting the final CPP for EPA’s response to this comment. The 

EGUs we analyzed are representative of the fleet as a whole.

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

Commenters stated that the maximum improvement to heat rate would be realized at 70 -100% 

of the rated capacity of the plant while operating at high capacity factors, i.e. base load 

conditions. Commenters stated that coal plants that presently operate under base load conditions 

are most likely to be the newest plants with the lowest heat rates and that they are also most 

likely to be the best maintained units. Commenters stated that these plants will likely have little 

opportunity for meaningful mechanical or operational improvements that could lower heat rate 

and that these are also the plants that are the biggest contributors to total CO2 emissions. 

Commenters stated that plants that typically operate at less than 75% of rated capacity and/or are 

cycled on a regular basis will have little chance to show any meaningful improvement in heat 

rate and given the uncontrolled variables that can impact heat rate such as ambient temperatures, 

humidity, rainfall and snowfall, condenser cooling water temperatures, fuel variability, cycling, 

and annual capacity factor, it will be difficult to monitor and measure improvements to plant heat 

rate on a consistent basis.

Commenters stated that the State of Arizona cannot meet EPA's improvement ranges because it 

has a relatively young coal-fired EGU fleet and has already implemented many heat rate 

improvement practices and equipment upgrades and the young nature of the fleet and all of the 

improvements that have already been made leave Arizona's utilities with little room for further

HRI. Commenters stated that Arizona's coal fleet is the sixth youngest in the nation, which 

diminishes the ability to achieve further heat rate improvements. Commenters cited ADEQ, State 

of Arizona Energy System: Examining the Current State of Arizona's Energy Mix in the Context 
245

of the Clean Power Plan, at 15, Arizona's average coal unit has a rated capacity of about 330 

MW, about ten (10%) percent less under actual operating conditions. Commenters stated that 

Arizona's coal fleet has a rated capacity of about 3,900 MW for all units combined under normal 

operating conditions. Id. Commenters stated that in the last few decades, Arizona's ratepayers 

have made a significant investment into building Arizona's coal fleet and making it one of the 

more efficient coal fleets in the country. Commenters stated that Arizona's younger fleet 

incorporates heat rate technologies and best practices not available to some older facilities; 

therefore, Arizona's atypically young coal fleet performs as well as, or better, than older units of 

comparable size and utilization in other states. Commenters stated that because of efficient 

performance of the young coal fleet, it is infeasible for Arizona utilities to improve coal unit heat 

rates of 6% under BB1. Commenters stated that due to the improvements that Arizona coal-fired 

units have already made, 1% improvements, at most, are realistic. 

Commenters stated that the Turk plant is the only ultra-supercritical coal-fired EGU and is the 

most fuel-efficient coal-fired EGU in the U.S and that Plum Point began commercial operations 

in the latter part of 2010. Commenters stated that based upon information provided by 

Southwestern Electric Power Company and Plum Point, these newer EGUs will not be able to 

achieve any appreciable HRI and given the lack of opportunity for HRI at those two facilities, 

the remaining five Arkansas coal-fired EGUs would need to implement HRI exceeding 8% in 

order to meet the 6% HRI goal. Commenters stated that information provided by Entergy to the 

Agencies indicates that if all of the items identified by Sargent and Lundy's report that could be 

implemented at the Independence and White Bluff facilities were fully implemented, the average 

HRI would be 2% to 4% and thus, Arkansas's newer plants will likely not see any significant 

improvements or only trivial improvements in heat rate, and their older plants probably cannot 

achieve greater improvement beyond the design heat rate.

Commenters stated that the coal fleet in Arizona is a relatively young fleet on average compared 

to other states having an average age of 31 years. Commenters stated that in addition, many of 

the EGUs have already made upgrades to improve efficiency and as a result, even if Arizona 

used Building Block 1 in its compliance plan, the Arizona coal fleet could not on average 

achieve a 6 percent efficiency improvement. This Building Block as currently structured is 

unusable for Arizona. 

Commenters stated that Arkansas has two coal plants that are less than three years old and one in 

the middle of costly upgrades and improvements to meet the EPA Mercury and Air Toxics 

Standards ("MATS") rule. Commenters stated that the new plants in particular are unlikely to be 

able to achieve a 6% heat rate improvement because those units are already operating at a low 

heat rate, and also, operating the coal-fired plants at a lower generation capacity will increase the 

average heat rate of the plants. Commenters stated that between 2012 and 2020, at least one of 

Arkansas's coal plants will be retrofitted for MATS compliance and doing so will increase the 

heat rate, making the 6% reduction even more unreasonable and unachievable.

Commenters stated that Wygen Three in Wyoming which came on line in 2010, is a newer 

power plant. Commenters stated that even though that plant was only in operation for two years 

as of 2012, which is the baseline EPA uses for emissions reductions, the EPA still assumes that 

Wygen Three will achieve a 6 percent emission reduction from its 2012 emission rate that just 
246

doesn't make sense to us. Commenters stated that EPA should exclude newer plants from block 

one productions.

Commenters stated that new plants that have just been built that have been built to state-of-theart standards can't get 6 percent overnight. 

Commenters stated that for instance, in Louisiana, Cleco recently noted in formal comments 

before the Commission that its Madison 3 unit is a "new generation sub-critical circulating 

fluidized bed boiler with state-of-the-art technologies to achieve low heat rate and low emissions 

that has very limited opportunities ("marginal opportunities") for any thermal efficiency gains."

Commenters stated that Cleco also noted that an additional 6 percent thermal efficiency 

improvement at its other 2 coal generation facilities would also be equally unlikely since the 

utility (and its partners) have already installed HRI measures at these plants.

Commenters stated that by requiring across-the-board, rather than individualized, heat rate 

improvements, the proposed rule disfavors modern units of more efficient design that have less 

room for efficiency improvements. Commenters stated that to avoid penalizing units that are 

already more efficient, EPA should evaluate heat rate improvement capability at individual coalfired units.

Commenters stated that the subject EGU in the S&L study is a 250 MW pulverized coal plant 

built and commissioned in the 1970s - and not a recently-constructed, state-of-the-art unit like 

the TS Power Plant. Commenters stated that EPA does not distinguish between the age of the 

facilities discussed in the S&L Report, or the potential that numerous of these measures are not 

feasible at new facilities or already may be installed, and simply tabulated the low and high 

range for all the heat rate improvement measures described in the S&L report to conclude that 

"implementation of all the identified best practices and equipment upgrades at a facility could 

provide total heat rate improvements in a range of approximately 4 to 12 percent..." [79 Fed. 

Reg. at 34,359 (emphasis added)]. 

Commenters stated that Arizona's coal-fired EGU fleet is the sixth youngest in the nation and as 

discussed in their individual members' comments, given the relatively young age of Arizona's 

coal-fired EGU fleet, the efficiency improvements that have already been achieved, and another 

of other considerations, it is infeasible for Arizona utilities to improve coal unit heat rates by 6% 

under BB1. Commenters stated that prematurely retiring these coal-fired EGUs by forcing 

ceased operation, before they are able reach their remaining useful life, will result in stranded 

investment costs that will be passed directly to Arizona electric customers. 

Commenters stated that it receives most of their power from the South Carolina Public Service 

Authority (Santee Cooper) under long term contracts dating back to 1950 and forward to at least 

2058. Commenters stated that the members have paid, and are paying, the largest part of the 

construction and operation costs for all of the 5000 MW of generation on the Santee Cooper 

system. Commenters stated that Santee Cooper owns some of the newest coal plants in the 

United States, with the average age of its coal fleet being 17.5 years and as a consequence of the 

newer construction, and the substantial investment in the older units to meet compliance with 

other emissions standards, Santee Cooper's facilities are employing the most efficient operational 

techniques at this time including turbine and boiler feed pump overhauls, regular checks for air 
247

heater seals and ductwork leaks, as well as the use of digital control systems that allow Santee 

Cooper to monitor unit efficiency in real time and analyze data on a daily basis to find and 

correct unit inefficiencies. Commenters stated that as a result, all of Santee Cooper's coal units, 

including those built as long ago as 1971, are operating very near design values. Commenters 

stated that there are some minor efficiency gains which can be adopted in the operation of some 

older units (in the range of one-half to three-fourths of one percent improvement in heat rate, but 

nowhere near the improvements of 6 percent suggested by the proposed regulations). 

Commenters stated that the investment necessary to accomplish even these modest 

improvements would be cost prohibitive. 

Commenters stated that there is nothing from the existing or historic operations at the Guayama 

facility to demonstrate that the suggested improvements could be achieved at their facility. 

Commenters stated that this is a new plant which incorporates the latest technology for heat rate 

improvement. Commenters stated that however, from the start of commercial operations, they

have not achieved the design net heat rate of 9700 Btu/kWh and the plant performance 

acceptance heat rate that was measured when the plant was commissioned in 2002 was 9,881 

Btu/kWh. Commenters stated that as of today, despite best maintenance practices, the net heat 

rate that they have ranged between 10050-10250 Btu/kWh, depending upon the quality of the 

low sulfur coal. Commenters stated that hence, to improve heat rate by 6% - or even 4% - would 

mean sustaining an improved heat rate at a level better than the original design of the CFB 

boilers and that has never been achieved at their facility, despite state of the art equipment, 

scheduled replacements, ongoing maintenance, and a strong financial incentive to do so. 

Commenters stated that in fact, under the PPA, they are incentivized to reduce their heat rate 

because the fuel costs passed through to the Puerto Rico Electric Power Authority are calculated 

based on an assumed heat rate of 9800 Btu/kWh. Commenters stated that every point above the 

PPA heat rate is a financial loss (and every point below that would be an additional financial 

gain), so the company is doing all that can be done to improve it. Commenters stated that there is 

simply no factual basis for assuming that a 4-6% heat rate improvement would occur at their 

facility from the kinds of practices EPA outlines in its analysis.

Commenters stated that EPA's assumption that coal-fired power plants can reduce their 

emissions by 6% from heat rate improvements does not meet the standards because the Agency 

does not base this assumption on an actual analysis of each state's plant conditions; instead, it 

simply used national reporting data as a springboard for assertions that the relied-upon data does 

not support. Commenters stated that specifically, EPA breaks up the justification for its 

assumption into two categories: (1) best practices for operation and maintenance; and (2) 

equipment upgrades. Commenters stated that for the best practices portion of its assumption, 

EPA analyzed the hourly data these plants reported to the EPA from 2002-2012 which included 

hourly heat input and, for most EGUs, hourly gross generation. Commenters stated that after 

analyzing this data, they determined a range of 1.3% to 6.7% potential for improvement in the 

average heat rate of the entire fleet of coal-fired EGUs as a result of best practices. Commenters 

stated that it then arbitrarily determined that a "reasonable" estimate of heat rate improvement is 

4% without justifying why 4% (rather than say 3.8% or 4.2%) is "reasonable." 79 Fed. Reg. at 

34,859. Commenters stated that while this use of statistics may work for averaging over a fleet of 

units, it does not consider a single unit's inability to achieve a 2%, on average, improvement in 

heat rate efficiency nor does it consider whether this is achievable for newly constructed units 

like their plant. Commenters stated that as previously mentioned, the items listed in this proposed 
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rule as "no cost" or "low cost" measures for best operating practices are already in use at their 

plant and the items referenced in the proposal as higher cost heat rate improvement methods are 

not needed at their plant which has already been designed for optimizing heat rates using the 

latest technology and design for the boilers, turbines, condensers, and boiler feed water heaters 

and pumps. Commenters stated that as a newer unit which is not part of a larger fleet of units, 

they cannot improve their heat rate by an additional 2% no matter how desirable that is, nor can 

it seek reductions from a related unit. 

Commenters stated that the proposed ESPS, emissions reduction goals, depend on four building 

blocks that were developed considering national and regional assumptions and costs that may not 

translate to a state or their utilities. Commenters stated that the 6 percent efficiency improvement 

building block is unrealistic since Florida's relatively new coal fired generating fleet already 

employs nearly all of the cost effective heat rate improvements that are available. 

Commenters stated that even if the EPA had calculated an appropriate fleet-wide HRI, such an 

average should not be applied to all states. Commenters stated that Arizona has one of the 

youngest coal-fired fleets in the nation, and the coal-fired plants in Arizona are relatively large, 

base-load units and for these reasons, heat rate improvement levels that may be achievable in 

some states are not achievable in Arizona. 

Commenters stated that notwithstanding the fact that the Proposal calls for the shutdown of all 

affected Arizona coal-fired plants by 2020, they hired S&L to conduct a heat rate improvement 

study at SGS. Commenters stated that SGS is a nominal 1,600 MW coal-fired power plant in 

eastern Arizona comprised of four units. Commenters stated that Units 1 and 2 began 

commercial operation in 1985 and 1990, respectively. Commenters stated that Units 3 and 4 are 

each less than 10 years old, commissioned in 2006 and 2009 respectively. Commenters stated 

that SGS represents 42 percent of Arizona's total coal-fired generation capacity. 

Commenters stated that even more remarkable than EPA's erroneous assumptions regarding 

achievable improvements in net heat rate at coal-fired EGU's constructed in or before the 1970's, 

such as those at their Coronado Generating Station, is the fact that EPA made the same 

assumptions for state-of-the-art coal-fired EGU's such as their Unit 4 at Springerville Generating 

Station. Commenters stated that this unit commenced operation in 2009 and, based on the part 75 

monitoring data which was the basis for EPA's analysis of heat rate variability, has a gross heat 

rate of approximately 8,800 Btu/kWh. Commenters stated that this is approximately 10 percent 

less than the average for EPA's "study population," reflecting the fact that the initial design of 

this and other state-of-the-art units includes the technological upgrades upon which EPA based 

its assumptions regarding achievable improvements in net heat rate at coal-fired EGU's. 

Commenters stated that because the goal computations performed by EPA omit any 

consideration whatsoever of the improvements achievable through equipment upgrades at coalfired EGU's which commenced operation in or after 2009, these units must be excluded from 

coverage under the proposed regulation. 

Commenters stated that EPA has proposed and modeled into its proposal an average six percent 

heat rate improvement for all existing coal plants in Building Block 1. Commenters stated that 

one of their affiliates, Sandy Creek Energy Associates, L.P., has an ownership interest in the 

Sandy Creek Energy Station, a coal-fired EGU in Texas that commenced commercial operation 
249

in 2012. Commenters stated that this facility is the sole coal-fired facility within the commenters'

ownership structure. Commenters stated that as a just-completed, modern coal plant, the Sandy 

Creek Energy Station incorporates all cost-effective heat rate improvement options and pollution 

control measures. Commenters stated that an additional six percent improvement would be 

exceedingly difficult to achieve. 

Commenters stated that prior to 2012, Wisconsin utilities brought online three new, supercritical 

coal-fired EGUs (Elm Road 1 & 2 and Weston 4). Commenters stated that these units have 

implemented all of the HRI measures used by EPA in developing building block 1. Commenters 

stated that in addition, these units have implemented the latest technologies for heat recovery and 

installed steam turbines designed to prevent some of the efficiency degradation that occurs in 

older turbines. Commenters stated that these EGUs also have the most efficient pollution control 

equipment and variable speed fan drives. Commenters stated that as there is no potential for 

further HRI at these EGUs, EPA must exclude these units from building block 1. 

Comment 20: Comments regarding whether EPA's bin analyses are adjusted for the impact of 

SCR and/or FGD installations on heat rate 

Response 20: See Chapter 2 of the GHG Mitigation Measures TSD supporting the final CPP for 

EPA’s response to this comment.

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

Commenters stated that EPA's "Best Practices" analysis used for the 4% heat rate improvement 

calculation is flawed. Commenters stated that several units included in EPA's analysis installed 

SCRs and/or FGDs within the 2002-2012 time period. Commenters stated that in their

experience, installation of these emission controls results in a 3-4% increase (according to 

design) in heat rate that can never be recovered. Commenters stated that replacing a wet FGD 

with a dry FGD can improve heat rate, but this is a unique situation and not an appropriate 

example of a typical heat rate improvement measure. Commenters stated that since EPA's bin 

analyses were not filtered for time (other than from 2002-2012), the lower heat rates, prior to the 

SCR and/or FGD installations, are setting the "best practice" heat rate targets since they would 

be in or near the 10th percentile for these units. Commenters stated that EPA should not include 

in its analysis heat rate data prior to the installation of SCRs or FGDs, or data following 

replacement of a wet FGD with a dry FGD.

Comment 21: Comments regarding the use of gross versus net heat rate

Response 21: For the EPA’s response to these comments, see sections V.C, VI, and VII of the 

final rule preamble of the CPP and Chapter 2 of the GHG Mitigation Measures TSD supporting 

the final CPP.

The following are summaries of the specific public comments under this comment:
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Commenters stated that EPA incorrectly used gross heat rates instead of net heat rates when 

determining heat rate improvement potential. Commenters stated there are many actions that can 

cause gross heat rate to decrease while the net heat rate increases due to increasing station 

service (e.g., replacing steam jet air pumps with vacuum pumps, run pulverizers harder to 

increase the fineness of the coal, turn on an additional circulating water pump to promote better 

heat transfer in the condenser, etc.). Commenters stated the net heat rate accounts for the 

auxiliary power consumption required to operate the machinery in the plant. Commenters stated 

this maintains a holistic view of plant performance and captures the effect of all changes, 

including emissions controls that change auxiliary power consumption. Commenters stated EPA 

should base its heat rate analysis on net heat rate data to ensure that utilities can capture the 

impact of any efficiency improvement that reduces the amount of carbon per net unit of energy 

produced by the generating unit.

Commenters provided a definition of an EGU's heat rate and stated that typical industry practice 

is to report a unit's net heat rate and therefore EPA's use of gross heat rate is contrary to industry 

practice and EPA's own analysis. Commenters stated that most studies examining thermal 

efficiency opportunities (heat rate improvements or "HRI") at power generation facilities utilize 

net heat rate measurements, not gross heat rate, And that in fact, the Sargent & Lundy report 

frequently cited and relied upon by the EPA in developing Building Block 1, defines an EGU's 

heat rate as: ...the amount of fuel energy input needed (Btu, higher heating value basis) to 

produce 1 kWh of net electrical energy output. Commenters stated that it is the metric most often 

used in the electric power generation industry to track and report the performance of thermal 

power plants. 

Commenters stated that moreover, EPA's analysis was inconsistent and while EPA's statistical 

analysis uses gross heat rate as the measure of operating efficiency, its Building Block 1 

recommendations are based upon on a net heat rate. Commenters stated that Lamason: Make 

sure the State Goal Computation folks see this. May want to add cross-reference to applicable 

State Goal Computation stuff. EPA attempts to explain this inconsistency by saying that any HRI 

method that reduces gross heat rate will also reduce net heat rate, and that some HRI methods 

reduce net heat rate without reducing gross heat rate. Commenters stated that similarly, the EPA 

"expect(s) the HRI potential on a net output basis is somewhat greater than on a gross output 

basis, primarily through upgrades that result in reductions in auxiliary loads”. Commenters stated 

that while the assumptions made by the EPA to extrapolate a net heat rate value based on a gross 

heat rate estimate may be valid on average, there is not a relationship between net and gross heat 

rate that is applicable to all types of plants, and thus, these assumptions are likely problematic at 

the state and regional level. Commenters stated that the North American Electric Reliability 

Corporation ("NERC") recently released a review of the "reliability implications and potential 

consequences from the implementation of the proposed CPP and its underlying assumptions." 

Commenters stated that in its review, NERC also highlights the error in EPA's Building Block 1 

methodology: "The EPA calculated unit-specific heat rates using gross generation data ... With 

this approach, the EPA excluded generation-reducing effects from post-combustion 

environmental controls, such as selective catalytic reduction and flue-gas desulfurization 

controls. The EPA then used net generation data, without consideration for these retrofits, for 

coal-fired EGUs when calculating the state CO2 emission rate goals. These retrofits will reduce 

the net output of these units, as well as their associated net heat rate efficiency. Not considering 

these reductions creates an inconsistent approach, especially considering that most coal-fired 
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EGUs will require control retrofits to comply with environmental regulations, such as the 

Mercury Air Toxic Standards (MATS) and Section 316(b) of the Clean Water Act."

Commenters stated that given the lack of heat rate improvement projects available, EPRI 

estimates that there may be opportunities to achieve heat rate improvements in the range of 0.5 to 

5 percent; however this would not rise to the six percent average heat rate improvement sought 

by EPA in Building Block 1. Commenters stated that EPA's Building Block 1 proposal is further 

confused by the agency's proposal to use gross heat rate data when estimating heat rate 

improvement-related CO2 mitigation because this calculation method is inconsistent with the net 

emission accounting method used in computing state goals. Commenters stated that inconsistent 

calculations cause confusion and inaccuracies.

Commenters stated that EPA's Building Block 1 proposal is further confused by the agency's 

proposal to use gross heat rate data when estimating heat rate improvement-related CO2 

mitigation because this calculation method is inconsistent with the net emission accounting 

method used in computing state goals. Commenters stated that inconsistent calculations lead to 

confusion and inaccuracies. 

Commenters stated that EPA's use of gross heat rate data for estimating heat rate improvementrelated carbon dioxide (CO2) mitigation for building block 1 is inconsistent with the use of the 

net emission accounting used in the state goals computation which leads to inconsistencies, 

confusion, and possible overestimation of the heat rate improvement-related mitigation potential. 

Commenters recommended that EPA use a consistent approach for net heat rate estimation and 

accounting through the proposed rule.

Commenters stated that EPA should factor the impact of auxiliary power required to operate air 

emission control systems on net output. Commenters stated that EPA's current assumption 

applies heat rate improvements to the gross output CO2 emissions rate of coal-units, which is an 

incorrect assumption for power plants where controls such as scrubbers have been constructed 

since 2012. Commenters stated that for example, they have or will have installed dry scrubbers 

at the following power plants: Columbia Energy Center, Edgewater Generating Station, 

Ottumwa Generating Station, and Lansing Generating Station.

Commenters stated that EPA's analysis of heat rate improvements only considers potential for 

improving gross heat rates "the HRI potential on a net output basis is somewhat greater than on a 

gross output basis, primarily through upgrades that result in reductions in auxiliary loads." 

Commenters stated that since the state goals are expressed in terms of net output, the calculation 

of heat rate improvements on a gross basis is a further dimension of EPA's analysis that leads to 

a conservative result. Commenters encouraged EPA to look more carefully at opportunities to 

improve the efficiency of auxiliary or parasitic loads, such as pumps, fans, motors, and pollution 

controls, since EPA notes that these loads represent from 4 to 12 percent of gross generation at a 

coal-fired steam EGU, and could present a key untapped opportunity for additional onsite 

improvements.

Commenters stated that the proposed rule should be based on gross generation rather than net 

generation because the EPA requirement to use net generation to demonstrate compliance with 

the state goals only penalizes facilities that have installed pollution control equipment that 
252

increase the facilities onsite parasitic load. Commenters further stated that the use of net 

generation is duplicative with Block 1 for coal-fired EGUs.

Commenters further stated that EPA's justification for the use of net generation states that 

improvements in the efficiency of auxiliary equipment and pollution control equipment represent 

opportunities to reduce carbon intensity at existing EGUs that would not be captured in 

measurements of gross generation, but that, however, the EPA specifically requested comment 

on whether the goals and reporting requirements should be expressed in terms of gross 

generation instead of net generation (79 FR 34894). Commenters further stated that they 

recommend that the rule be based on gross generation but that the use of net generation only 

penalizes companies that have had to install controls for compliance with other regulations, such 

as MATS, that have increased parasitic loads due to installing pollution control equipment. 

Commenters further stated that this requirement is particularly impactful on coal-fired EGUs 

because the EPA has already factored in such assumed efficiency improvements in Block 1 and 

that, effectively, EPA is at least partially applying Block 1 to coal-fired EGUs twice by requiring 

the use of net generation.

Commenters stated that in setting a state's emissions rate reduction target, EPA has proposed 

reducing emissions rates at existing coal-fired units based on a uniform average of 6% HRI that 

is derived from a national study. Commenters stated that EPA, further, inappropriately applied an 

analysis of gross heat rate data to a net heat rate goal and that it is impractical and unreasonable 

for EPA to assign an average HRI to states irrespective of the ability of a particular state's EGUs 

to make that HRI. Commenters stated that the resulting HRI goal may not reasonably apply, 

given the facts on the ground, in Arkansas. 

Commenters stated that EPA's use of gross heat rate data for estimating heat rate improvement 

CO2 reductions for Building Block 1 is inconsistent with the use of the net emission accounting 

used in the state goals computation. Commenters stated that the use of gross heat rate data leads 

to inconsistencies and possible overestimation of the heat rate improvement-related CO2 

reduction potential.

Commenters stated they believe that the results of this statistical analysis of gross heat rate were 

inappropriately applied to derive net heat rate outcomes because it neglects the fact that much of 

the coal-fired fleet, in particular those remaining operational 2016 and beyond, will be well 

controlled and that these controls impose an auxiliary load that degrades the net heat rate of a 

unit.

Commenters stated that, in its statistical analysis, EPA looked at gross heat rate, when what 

matters for the proposed rule is net heat rate. 

Commenters asked why the EPA did not use net output instead of gross output

Commenters stated that in Building Block 1, EPA adjusted the state-level coal rate by reducing 

the "net" heat rate by 6%. Commenters stated that in the preamble and the Technical Support 

Documents, EPA provides no reasonable explanation of how its analysis results on a gross basis 

is transferrable to net generation. Commenters stated that they believe EPA has made an error by 

setting the goal using net generation but based the 6% HRI requirement using gross generation. 
253

Commenters stated that this approach unfairly targets modern plants with multiple air pollution 

devices that consume significant parasitic and auxiliary power at the plant. Commenters stated 

that the EPA study only examined heat rate as a function of gross load, not net electricity 

generation which is a lower number due to parasitic (auxiliary equipment) losses. Commenters 

stated that EPA's heat rate BSER was based on a review of gross heat rate, and did not 

specifically account for variability in auxiliary power usage, especially for EGUs that operate 

control equipment either during ozone season or year round. Commenters stated that during the 

study period, all of North Carolina's coal units operated with controls for NOx, SO2 and PM. 

Commenters stated that EPA utilizes gross heat rate data in its calculation of HRI-related 

improvements. Commenters stated that however, EPA later utilizes net emission accounting in 

the calculation of the state goals computation. Commenters stated that electric industry 

standards, such as those established by EPRI, require HRI data to be reported on a net generation 

basis. Commenters stated that the use of gross heat generation data for determination of HRIrelated CO2 improvements is inconsistent with the use of net generation emission accounting 

used by EPA in its state goals computation. Commenters stated that this "apples and oranges" 

mismatch may lead to overestimation of the emission mitigation potential. Commenters stated 

that they recommend the EPA use a consistent approach for net heat rate estimation and for 

emissions accounting in the final rule. 

Commenters stated that the EPA's use of gross heat rate data to assess HRI potential is 

inconsistent with the use of net heat rate data in its calculation of the state goals.

Commenters requested that EPA restate Building Block 1 heat rate requirement in terms of net 

generation instead of gross generation.

Commenters stated that heat rate effects should be assessed on a net basis - historically, each set 

of emissions control regulations increases auxiliary power consumption by about 1% gross 

generation, translating directly to a decrease in heat rate efficiency. Commenters stated that 

emissions control equipment installations for forthcoming compliance with the MATS rule will 

have a similar detrimental effect on unit heat rates and if this trend continues, unit efficiencies 

will continue to decline. Commenters stated that net heat rate reflects the cost of generating 

electricity including the cost of auxiliary power consumed as part of the process, however, EPA 

has used gross heat rate for determination of heat rate improvement and related CO2 mitigation 

potential in Building Block 1 which may lead to inconsistencies, confusion, and possible 

overestimation of the mitigation potential. 

Commenters stated that the proposed unit of measurement in Building Blocks 1 and 2, pounds of 

carbon dioxide per net megawatt-hours, is of particular concern to commenters and other 

utilities. Commenters stated that by imposing limits based on net megawatt-hours, instead of the 

more traditional gross megawatt-hours, power plants must deduct the power used to run the 

facility (also dubbed parasitic load). Commenters stated that this appears to be the first time 

emissions are being measured as net, instead of gross. Commenters stated that the use of net

megawatt-hours also makes it more difficult for electric utilities to collaborate with their fellow 

state utilities to meet the state goal, which is another wrinkle in this proposal. Commenters stated 

that by using a net measurement, each plant must be able to quantify its parasitic load now, and 

then predict it for the future for compliance purposes, however this is further complicated with 
254

the additional regulations recently finalized or proposed. Commenters stated that for instance, the 

recently finalized 316(b) rule regulates the intake of water for cooling purposes - also affecting 

natural gas plants. Commenters stated that under 316(b), a power plant would need to limit its 

impact on aquatic biota after several years of study and the result could be to add a new cooling 

tower or the like which, in turn, would add more parasitic load and this results in higher carbon 

dioxide emissions from a plant, not because it increased its carbon dioxide emissions output from 

the stack, but because the net megawatt-hour number is smaller on the denominator side of the 

equation. Commenters stated that as more regulations come down the pipeline, it's likely that 

parasitic load will increase to accommodate additional pollution controls. USEPA should 

consider setting this portion of the equation based on gross megawatt-hours instead. 

Commenters stated that in the preamble and TSD- GHG Abatement Measures, EPA asserts that 

existing coal-fired EGUs can achieve a 4-6 percent heat rate improvement. Commenters stated 

that the EPA based its performance target on statistical analysis of its own data of existing coalfired units which examined heat rate as a function of gross load, not net electricity generation 

which is a lower number due to parasitic (auxiliary equipment) losses. Commenters stated that 

significant power can be consumed by pollution control devices at an EGU, and heat rates are 

compromised when greater auxiliary power is needed. Commenters stated that EGUs that 

operate at lower load as a result of these rules would experience a higher level of auxiliary power 

use relative to their generation and for these reasons, it is critical to evaluate heat rate on a net 

basis (as opposed to gross). 

Commenters stated that in Building Block 1, EPA adjusts each state's coal rate by reducing the 

"net" heat rate by 6% and proposes that units demonstrate compliance on a net basis. 

Commenters stated that in the preamble and the TSD, EPA provides no reasonable explanation 

of how its analysis results on a gross basis is transferrable to net generation. Commenters 

believed that EPA has made an error by setting the goal using net generation but based the 6% 

heat rate improvement requirement on gross generation study. Commenters stated that the EPA's 

approach unfairly targets modern plants with multiple air pollution devices that consume 

significant auxiliary power at the plant. Commenters stated that believed that if EPA had 

analyzed heat rate improvements on a net basis, it would not have been able to show a 4-6 

percent heat rate improvement is achievable.

Commenters stated that in 2012, North Carolina had the lowest gross heat rate in the nation, well 

below EPA's national average. Commenters stated that all of North Carolina's largest coal-fired 

EGUs operated with NOx, SO2, and PM controls. Commenters stated that because EPA only 

examined improvements achievable on a gross basis, a 4-6% heat rate improvement on a net 

basis is not believed to be achievable for modern plants. Commenters stated that EPA must 

address this deficiency in the proposal and base its heat rate improvement requirement on sound 

science and real world performance results. 

Commenters stated that assuming that RPS-2 was to remain in service after 2020, its net heat rate 

would reasonably be expected to increase, rather than decrease, both due to the additional 12-14 

MW of auxiliary load added in order to meet Mercury and Air Toxics Standards (MATS) 

compliance requirements (resulting in heat rate increase of ~2.5%) and to the additional auxiliary 

load requirements associated with the installation of flue gas desulfurization and NOx reduction 

system required for anticipated SO2 and ozone NAAQS requirements. Commenters stated that as 
255

noted by UARG, similar compliance measures taken by other generating unit owners that would 

negatively impact heat rate, and thus increase CO2 emissions rates, are not captured in the gross 

heat rate data utilized by the EPA. 

Comment 22: Applicable to the supplemental proposal for Tribal and Territorial – Comments 

regarding the use of gross versus net heat rate

Response 22: See section V.C. of the final rule preamble of the CPP and Chapter 2 of the GHG 

Mitigation Measures TSD supporting the final CPP for EPA’s response to this comment.

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

Commenters stated that in its statistical analysis, EPA looked at gross heat rate as estimated from 

Air Markets Program Data, when what matters for the proposed rule is net heat rate.

Comment 23: Comments regarding subcategorization

Response 23: For the EPA’s response to these comments, see section V.C of the final rule 

preamble of the CPP and Chapter 2 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 EPA did not compare units against one another nor do any sort of subcategorization and that each unit is only compared against itself over that eleven year period, and 

in that respect, sub-categorization is avoided. 

Commenters suggested a subcategory for coal refuse-fired plants:

1. Commenters stated that Pennsylvania has relied on industry to address the water pollution 

caused by legacy coal refuse piles by encouraging industry to remine them - that is, 

process and use the coal refuse as fuel in alternative energy electrical generating plants 

that utilize Circulating Fluidized Bed (CFB) boilers and then reclaim the sites through the 

mining, reclamation and beneficial use of the ash. Commenters stated that everything 

should be done to encourage this practice.

2. Commenters stated that CFB boilers are unique in the fact that their method to control 

acid gases is based on the injection of limestone into the bed of the boiler and that the 

amount of CO2 emitted increases significantly with higher sulfur content coal refuse due 

to the increased limestone usage and the increase in fuel consumption.

3. Commenters stated that the quality (lower heating value and higher sulfur content) of the 

remaining legacy coal refuse piles is diminishing as the higher quality piles have been 

remined and that accordingly, limestone usage to control acid gas emissions has 
256

increased and will continue to increase producing a net increase in the heat input to the 

boiler and a correlating increase of greenhouse gas emissions. Commenters stated that a 

set emission rate for greenhouse gaseous would limit the fuel flexibility needed to 

continue the reclamation of legacy coal refuse piles. 

4. Commenters stated that EPA requirements to lower SO2 emissions in the Cross-State Air 

Pollution Rule (CSAPR/CAIR) or via surrogates as Mercury Air Toxins Rule (MATS) 

will likely increase the use of limestone and coal refuse in these plants consequently 

increasing Green House Gas (GHG) emissions further.

5. Commenters stated that due to technology limitations, coal refuse CFB plants cannot 

economically apply capital intensive carbon sequestration or advanced efficiency (heat 

rate) technologies to reduce the greenhouse gases at the plant sites and be competitive in 

the markets. Commenters stated that coal refuse CFB plants also cannot convert or co-fire 

natural gas as a means to reduce CO2 emissions since such activity is not cost effective 

and would greatly diminish the environmental benefits historically provided by the 

industry.

6. Commenters stated that for the reasons described above, they believe that EPA should 

establish a subcategory for coal refuse-fired power plants under both the new and existing 

source rules and in addition, the coal refuse-fired plants should not be included in the 

BSER program used to calculate the average statewide CO2/MW emission rate, rather, 

existing coal refuse-fired plants should be treated as carbon neutral for the purpose of this 

rule making. Commenters stated that further, the existing coal refuse-fired plants should 

use best work practices for their continued operations. Commenters stated that the work 

practices could be based on an approach that, like the Mercury Air Toxics (MATS) rule, 

focuses on a work practice that provides for a boiler tune-up to maintain efficiency in 

accordance with good engineering practice. Commenters stated that this subcategorization could be incorporated into various states CO2 reduction plans as being 

carbon neutral as they are reclaiming coal refuse piles that have burned, are burning, and 

will burn, and further, the revegetation begins to form a carbon sink. 

Commentersstated that EPA has noted significant gaps in its data and cites "In this analysis, 

units are not categorized by unit specific design characteristics or fuel because: (1) EGU-specific 

detailed design information on all factors that influence heat rate is not available, and (2) certain 

design characteristics are not easily categorized (e.g., EGUs use a large range of steam 

conditions)." TSD, p. 2-19. "The EPA does not have sufficient site specific information to 

accurately estimate what percentage of the fleet has adopted various HRI methods, nor how 

effectively, and is not aware of any other investigator having sufficient information." TSD, p. 2-

36. Commenters stated that EPA should be concerned that a large but incomplete data set can 

and will yield conclusions that are simply wrong and what EPA has done resembles a mass real 

estate appraisal without having a sufficient universe of the supporting data that drive individual 

results, which are the purpose of conducting a mass appraisal. Commenters further stated that no 

assessor would use a mass appraisal approach to derive an average value for all of the real 

property in a city, and tax all of that property as if it were worth that average value and that an 

average does not always achieve a fair or a wise result, and it will not do so if employed as EPA 

proposes. 
257

Commenters stated that as a further evaluation of the potential for heat rate improvements, EPA 

conducted a statistical analysis of heat input and electrical output from 884 coal-fired and 

petroleum coke fired EGUs based on data reported to the EPA's Clean Market Division under the 

Acid Rain Reporting Program (Part 75). [GHG Abatement TSD at 2-15]. Commenters stated that 

hourly data was examined over a ten year period, from 2002 to 2012 and whereas other heat rate 

analyses sub-categorized data based on such factors as fuel types, plant design characteristics, 

plant age and generating capacity, the EPA analysis focused on the impacts of capacity factor 

and ambient temperature on heat rate; in other words, the analysis attempted to hold constant 

these other factors across the population of EGUs evaluated in order to estimate the effects of 

hourly temperature and load variation. [79 Fed. Reg. at 34,860]. 

Commenters stated that EPA's assessment does account for important unit characteristics, such 

as fuel rank, that it concedes are "helpful to understanding the heat rate performance of EGUs." 

Commenters stated that of particular relevance to their units is the effect of coal rank, and EPA's 

analysis confirms that lignite fueled units have demonstrably different heat rate characteristics 

than other coal units - yet EPA concedes that it does not take this into account in building block 

1. Commenters stated that despite the requirement that EPA subcategorize units by fuel type for 

purposes of its 111(d) guidance, it fails to do so. Commenters stated that EPA's building block 1 

analysis is flawed because it failed to consider these unit characteristics in reaching either the 6% 

proposed target or the alternative 4% target. 

Commenters stated that EPA's proposal for existing sources provides no discussion of potential 

subcategories, and in fact, does not even acknowledge EPA's regulatory obligation to determine 

if subcategories are appropriate. Commenters stated that EPA only suggests in its legal 

memorandum that states can subcategorize particular units "on the basis of their costs and other 

considerations." Commenters stated that in regard to the building block 1 analysis, EPA notes in 

one of its TSDs that while "[s]everal other studies do categorize EGUs broadly by capacity, 

thermodynamic cycle, and/or fuel rank," the "range of heat rates for the broad categories . . . 

makes it challenging to develop appropriate categorization." Commenters stated the limited 

discussion in the legal memorandum and TSD related to subcategorization fall short of 

recognizing EPA's duty to subcategorize when appropriate. Commenters stated the EPA cannot 

simply be alleviated from subcategorizing units just because it may be "challenging" to do so. 

Commenters stated that under EPA's procedural regulations for existing sources, EPA has a clear 

obligation to examine and develop subcategories for regulated sources: EPA "will specify 

different emission guidelines or compliance times or both for different sizes, types, and classes 

of designated facilities when costs of control, physical limitations, geographical location, or 

similar factors make subcategorization appropriate." Commenters stated that in promulgating this 

regulation, EPA explained that "while there may be only one standard of performance for new 

sources of designated pollutants, there may be several emission guidelines specified for 

designated facilities based on plant configuration, size, and other factors peculiar to existing 

facilities." Commenters stated that moreover, the "emission guidelines will reflect 

subcategorization within source categories where appropriate . . . . Thus, EPA's emission 

guidelines will in effect be tailored to what is reasonably achievable by particular classes of 

existing sources." Commenters stated that EPA must comply with 40 C.F.R. Para 60.22(b)(5) by 

developing subcategories for coal-fueled EGUs that burn different types of fuel, specifically 

lignite. 
258

Commenters stated that despite EPA's failure to subcategorize here, or even consider it, EPA has, 

in the past, subcategorized sources in the context of various Para 111(d) emission guidelines. 

Commenters stated that in the Final Guidelines document for Kraft Pulp Mills issued in 1979, 

EPA set three standards for different types of recovery furnace systems - "old design" furnaces, 

"new design" furnaces, and cross recovery furnaces. Commenters stated that EPA explained that 

emissions from a cross recovery furnace are not controllable to the same degree as are those from 

straight kraft recovery furnaces. Commenters stated that the reasons for this include higher 

sulfur-to-soda ratios and lower BTU value of the liquor fired." Commenters stated that it is 

readily apparent that EPA is familiar with its duty to subcategorize when appropriate, and it must 

at least examine appropriate subcategories for its proposed standards here. 

Commenters stated that all available data and experience indicate that subcategories for coalfueled EGUs are appropriate for the existing source CO2 standards. Commenters stated that 

EPA's own past rulemakings in other contexts demonstrate that subcategories for coal-fueled 

EGUs are appropriate. Commenters stated that for example, EPA's utilization of a subcategory 

for lignite in the Mercury and Air Toxics Standards ("MATS") rule supports the development of 

a lignite subcategory for the CO2 emission guidelines. Commenters stated that in establishing 

subcategories for its MATS rule, EPA determined that the differing heat content of low-rank 

virgin coal justified a subcategory for mercury emissions, and this determination was upheld by 

the D.C. Circuit. Commenters stated that here, because lignite impacts the emission rate of CO2 

from coal-fueled EGUs, EPA must develop a subcategory for units that burn different types of 

fossil fuel.

Commenters stated that a research paper developed by the American Coalition for Clean Coal 

Electricity provides a discussion of the unique factors associated with various fuel types that 

have an impact on CO2 emissions, thus justifying the development of subcategories. 

Commenters stated that the authors of this paper, J. Edward Cichanowicz and Michael C. Hein, 

analyzed data from a larger data set than was used by EPA and found that coal composition, load 

factors, boiler design, and coal moisture all affect CO2 emissions. Commenters stated that with 

regard to moisture content, Powder River Basin subbituminous fuel may contain 30% moisture 

compared to 6% moisture content for a typical eastern bituminous coal, resulting in a 3-5% 

thermal efficiency penalty due to the amount of fuel that must be combusted to generate a fixed 

amount of steam. Commenters stated that despite this thermal penalty, Cichanowicz and Hein's 

statistical analysis (using EPA's methodology) demonstrates that boiler steam conditions are 

more relevant for creating categories for CO2 emissions than whether the coal is subbituminous 

or bituminous. Commenters stated that on the other hand, lignite coal faces firing and utilization 

challenges that have a bigger effect on CO2 emissions than the boiler steam conditions.

Commenters stated that targeted heat rates are a difficult parameter to control, especially when 

firing an erosive, high ash, low Btu/lb fuel such as lignite.

Commenters stated that consequently, the Cichanowicz and Hein report recommends three 

different emissions standards: (1) supercritical boilers burning subbituminous or bituminous 

coals; (2) subcritical boilers burning subbituminous or bituminous coal; and (3) boilers burning 

lignite. Commenters stated that thus, any final standards for existing sources must provide 

separate standards for coal-fueled utility boilers subcategorized by coal type, and such a standard 

would certainly increase Texas's goal. Commenters stated that EPA must recognize the 

differences in emissions from these three subcategories and adjust the performance standard 
259

accordingly. Commenters stated that as a legal matter, they believe standards for existing coalfueled EGUs must be subcategorized by primary fuel type as provided in the regulations "for 

different sizes, types, and classes of designated facilities when costs of control, physical 

limitations, geographical location, or similar factors make subcategorization appropriate" 

Commenters stated that not to do so would be arbitrary and capricious, contrary to law, and 

inconsistent with EPA's past practices.

Commenters stated that since a number of the larger supercritical plants already have upgrades 

that may limit heat rate improvements to about 1%, other plants may have to achieve upgrades 

greater than 10% which is not practical. Commenters further stated that EPA calls the average 

hourly load (expressed as a percent of maximum load) capacity factor, although industry 

consider capacity factor as averaged over a much longer averaging time than an hour). 

Commenters stated that the degree that heat rate for the unit is consistent or inconsistent over the 

eleven year period for any given temperature and hourly average load is, EPA states, a measure 

of how well or how poorly the facility is being controlled. Commenters stated that EPA argues 

that a well-controlled unit should have very consistent heat rate under a given ambient 

temperature and average hourly load and that to the extent that there is scatter in gross heat rate 

for any given hourly load or temperature condition over this eleven year period, EPA considers 

that a sign that more consistent process control can improve heat rate. 

Comment 24: Applicable to the supplemental proposal for Tribal and Territorial – Comments 

regarding subcategorization

Response 24: See section V.C of the final rule preamble of the CPP and Chapter 2 of the GHG 

Mitigation Measures TSD supporting the final CPP for the EPA’s response to this comment.

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

Commenters stated that EPA did not compare units against one another or do any sort of 

subcategorization. Commenters stated that each unit is only compared against itself over the 

eleven-year period and, in that respect, subcategorization is avoided.

Comment 25: Comments regarding heat rate impacts from startups and shutdowns

Response 25: For the EPA’s response to these comments, see section V.C of the final rule 

preamble of the CPP and Chapter 2 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 EPA's bin analysis only controlled for ambient temperature and hourly 

load but not other factors beyond a unit operator's control that impact a unit's heat rate variability 

- such as a unit's design, fuel type and quality, weather, and operating characteristics (e.g., 

number of startup and shutdown events and low NOx combustion). Commenters stated that 
260

Georgia Power's Plant Hammond Unit 3 serves as an example of the impact startup and 

shutdown events could have on a unit's emission rate referring to three startup events in 2005 

compared to 46 in 2012. Commenters stated that the unit's net and gross CO2 emission rates 

were 17 percent higher in 2012 compared to 2005. Commenters stated that EPA acknowledges

that "EGUs are known to operate at higher heat rates" during periods of startup and shutdown but 

determined these events as having a marginal impact on coal-fired EGUs' efficiency because less 

than four percent of total generation is produced from EGUs with more than 20 annual startups 

and shutdown events. Commenters stated that EPA errs in discounting the number of startups 

and shutdowns from its analysis because historical operations may not be indicative of future 

operations; in particular, after implementation of the Building Blocks 2 and 4, coal-fired EGUs 

most certainly will experience more startup and shutdown events because of reduced usage. 

Commenters stated that EPA's presumption that the variation in efficiency it has identified is 

driven by the need for implementation of best practices is simply unsupported by current utility 

practice, instead, the other factors that impact heat rate more than explain the variations EPA 

identified in its historical analysis. 

Commenters stated that it is important to recognize that requiring EGUs to operate at optimal 

heat rate is in apparent conflict with any measures and requirements that create circumstances 

where coal-fired EGUs are operated at low capacity factors or as non-base load units. 

Commenters stated that more frequent start-ups and variations in load for coal-fired EGUs can 

result in higher heat rates (i.e., lower efficiency) and an undesirable increase in air emissions 

since EGUs are most efficient at higher, consistent loads. Commenters stated that moreover, the 

parasitic load is a higher percent of the net output at lower loads, thereby negatively impacting 

efficiency calculations based on net output.

Commenters recommended work practice standards that are periodically reviewed and 

implemented on a source specific basis. Commenters stated that if EPA does pursue a uniform 

heat rate standard, the agency should exclude emissions released during periods of unit startup 

and shutdown. Commenters stated that in fact, EPA has recognized this type of exclusion for 

other environmental regulations. Commenters stated that this approach would prevent multiple 

environmental regulations from potentially working at odds to one another. Commenters stated 

that given that EPA believes the proposed rule is "consistent with the long-term planning and 

investment processes already used in [the electricity] sector" taking into account other 

environmental regulations seems paramount to promulgating a rule consistent with the aims of 

the CAA.

Commenters stated that based on their concerns, the only possible option is to operate coal 

facilities at the most efficient load for shorter durations. Commenters stated that this results in 

more startups and shutdowns of coal-fired power plants. Commenters stated that coal-fired 

power plants operate even less efficiently during startups and shutdowns, which the EPA itself 

affirmed in the Greenhouse Gas Abatement Measures Technical Support Document. 

Commenters stated that further, more frequent startups and shutdowns could adversely impact 

the existing air quality control systems on coal-fired power plants because those systems were 

designed to be most efficient when a plant operates at higher capacities for longer durations. 

Commenters stated that depending upon on the coal-fired power plant in question; startups could 

result in a shorter useful life for air quality control system components as a result of damage due 
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to more exposure of acid gas condensation. Commenters stated that other operational challenges 

may result for air quality control systems due to more frequent startups and shutdowns. 

Commenters stated that on p. 2-21 of the GHG TSD, the EPA says only 4% of EGUs in the 

study were load following. Commenters questioned why the EPA didn't analyze how this will

change under the application of all BBs collectively. 

Comment 26: Comments regarding future declines in capacity factor due to the other building 

blocks, and demand-side energy efficiency

Response 26: For the EPA’s response to these comments, see section V.C of the final rule 

preamble of the CPP and Chapter 2 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 EPA recognized that coal-fired generation and capacity factors (TSD 

page 2-20) have steadily decreased since 2008, in part due to the recession but also due to more 

natural gas and renewable generation. Commenters stated that EPA states that "16% of the 

change in hourly heat rate is attributable to capacity factor" (TSD page 2-25). Commenters stated 

that capacity factors associated with coal-fired generation are likely to decline even more as the 

Clean Power Plan is implemented as a result of re-dispatching, increasing renewable generation 

or improving demand-side energy efficiency. Commenters stated that therefore achieving higher 

heat rate improvements, or even maintaining current heat rate performance, will prove difficult.

Commenters addressed capacity factor impacts from a variety of contributing operational factors.

Commenters stated that the heat rate or thermal efficiency of generation - particularly when 

measured on a net basis - is compromised at lower capacity factor due to contributing factors 

such as fuel composition, conditions in the boiler, boiler design, steam turbine, and how ancillary 

equipment is operated at part load. Commenters stated that one category of units examined 

exhibited a compromise in heat rate compared to full load by more than 4% to almost 9%, when 

operating at 50% of full load. Commenters stated that operating at reduced capacity factors is 

often out of the control of the unit owner/operator, and could effectively offset the benefit of 

EPA's proposed heat rate and CO2 emissions reduction. 

Comment 27: Applicable to the supplemental proposal for Tribal and Territorial – Comments 

regarding the impacts of capacity factor and ambient temperature

Response 27: For the EPA’s response to these comments, see section V.C of the final rule 

preamble of the CPP and Chapter 2 of the GHG Mitigation Measures TSD supporting the final 

CPP. 

The following are summaries of the specific public comments under this comment:
262

Commenters stated that EPA's conclusion that 4% improvement using "best practices" is possible 

at no or low cost was based upon a statistical analysis of over 800 units using what EPA 

describes as statistical process control methods and for each unit, the gross heat rate in a given 

hour over an eleven-year period was compared against hourly NOAA ambient temperature data 

and hourly average load as a percent of maximum load. Commenters stated that EPA calls the 

average hourly load (expressed as a percent of maximum load) "capacity factor," although most 

industry people consider capacity factor as averaged over a much longer averaging time than an 

hour. Commenters stated that in EPA's approach, the degree to which the heat rate for the unit is 

consistent or inconsistent over the eleven-year period for any given temperature and hourly 

average load is a measure of how well or how poorly the facility is being controlled. 

Commenters stated that a well-controlled unit should, by this reasoning, have a very consistent 

heat rate under a given ambient temperature and average hourly load. Commenters stated that to 

the extent that there is scatter in gross heat rate for any given hourly load or temperature 

condition over this eleven-year period, EPA considers that scatter to be a sign that more 

consistent process control can improve heat rate.

Commenters stated that the statistical approach used by EPA does not consider any technical 

aspects of the facility. 

Commenters stated that EPA used a statistical analysis that presumes that a well-controlled 

facility using "best practices" should have a repeatable heat rate under any given ambient 

temperature or hourly average load condition and EPA assumed that any variability in heat rate 

not explained by temperature or load is an indication that the facility operation is inconsistent 

and therefore can be improved upon through "best practices." Commenters stated that EPA's 

analysis showed that, on average, ambient temperature and load explained only about one fourth 

(26%) of the variation in gross heat rate. Commenters stated that EPA concluded that the nearly 

three quarters of variability not explained by ambient temperature and average hourly load was 

evidence that there is substantial opportunity for improvement and in reaching this conclusion, 

EPA did not consider if there might be other factors beyond the operator's control that would 

explain the variability that was not explained by ambient temperature and average load.

Commenters stated that EPA's failure to consider other factors besides ambient temperature and 

average load that impact heat rate and are beyond the operator's control was, in their opinion, a 

significant oversight. Commenters stated that other important factors that impact heat rate 

include changes to the plants made over the eleven-year period, such as: addition of low-NOx 

burners, addition of SCRs and scrubbers, new soot blower controls, new furnace and burner 

management systems, changes in fuel or fuel characteristics, variability in a particular fuel, and 

extreme weather events, to name a few. Commenters stated that because EPA did not consider 

these and other important factors that have a large effect on heat rate, most of what appears in 

EPA's analysis to be variability that can be better controlled is actually the result of these other 

effects, and therefore EPA mistakes the variability that was not explained by ambient 

temperature and hourly average load as an opportunity to improve heat rate.

Commenters stated that EPA's own analysis demonstrates that for its study population, gross heat 

rate on average dropped steadily about 300 Btu/kWh (nearly 3%) from 2002 through 2008 while 

annual capacity factor remained relatively constant. Commenters stated that this was despite 

installation of advanced pollution control equipment like Flue gas desulfurization ("FGD") and 
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selective catalytic reduction that is known to adversely impact heat rates. From 2009 through 

2012, with lower capacity factors and with FGD installations peaking in 2010, gross heat rate 

started to increase. Commenters stated that by 2012 average heat rate had increased slightly 

(about 100 Btu/kWh or 1%) from 2008 levels but was still well below 2002 levels. Commenters 

stated that this increase in heat rates that peaked in 2012 is widely viewed to be the result of the 

large drop in capacity factor for many coal units due to the unusually low natural gas prices that 

were unique to that year and as this figure demonstrates, much of the "scatter" in heat rates at a 

given capacity factor over the 11-year period that EPA asserts as evidence of room for 

improvement through "best practices" is, in fact, evidence of gross heat rates dropping over the 

period. Commenters stated that therefore, it is unclear how EPA's data supports a further 4% heat 

rate reduction from 2012 levels simply through "best practices" because 2012 gross heat rates 

already benefitted from at least a decade of reductions in gross heat rates at any given capacity 

factor.

Commenters stated that the majority of the coal fleet already has some form of optimization 

software built into its controls and these optimization systems use inputs from hundreds of 

sensors in the plant to develop control algorithms used to operate the plant in a manner that 

optimizes the plant with respect to efficiency, reliability, safety, and environmental compliance. 

Commenters stated that EPA's approach to statistically evaluating the operation of the plants 

against only two variables is unnecessary and too simplistic in light of the fact that many 

facilities already use very sophisticated systems that were tailor-made to optimize that plant's 

operations while monitoring hundreds of sensory inputs.

Comment 28: Comments regarding the EPA’s regression analysis for assessing the impact of 

capacity factor and ambient temperature on heat rate, and factors the EPA should have 

considered in that regression analysis (e.g., fuel composition, boiler design characteristics, partload operations). 

Response 28: For the EPA’s response to these comments, see section V.C of the final rule 

preamble of the CPP and Chapter 2 of the GHG Mitigation Measures TSD supporting the final 

CPP. For example, as explained in those documents, the EPA does not assert that all heat rate 

variability is caused by ambient temperature, capacity factor, and differences in implementation 

of heat rate improvement measures. Additionally, as described in chapter 2 of the GHG 

Mitigation Measures TSD, the economic downturn was not accompanied by a significant fleetwide effect on heat rate.

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

Commenters question if the correlations between heat rate and capacity factor, and heat rate and 

ambient temperature are consistent with basic engineering principles, as it is well known that 

operating at lower ambient temperature and higher capacity factor favorably affects (e.g., 

decreases) heat rate; one index of the validity of the statistical analysis is how much of the 

database population abides by this trend. Commenters stated that this concept is addressed by 

evaluating the regression coefficient for each correlation and whether the values are "positive" or 

negative" and that the occurrence of a few regression coefficients in opposition to the accepted 
264

direction is understandable; Commenters asserted that if a large segment of the population is an 

outlier the basis of the correlations could be flawed. Commenters referred to a table (Table 2 

Regression Coefficients: Negative/Positive Details) showing the variance in positive and 

negative regression coefficients for the multi-variable analysis addressing how capacity factor 

and ambient temperature affect predicted heat rate. Commenters added that, as noted by EPA and 

described in a 2014 UARG report defining factors affecting heat rate, an inverse relationship 

between capacity factor and heat rate (e.g., negative regression coefficient) should be expected 

for most units - higher capacity factor improves (e.g., lowers) heat rate. Commenters further 

mentioned that a direct relationship between ambient temperature and heat rate (e.g., positive 

regression coefficient) should be observed, as lower temperature invariably increases heat 

rejection and lowers heat rate. Commenters noted that Table 2 reports the fraction of the unit 

population that exhibits regression coefficients that are counter to the accepted understanding of 

how capacity factor and ambient temperature affect heat rate. 

Commenters stated that EPA's calculation of its coefficient of determination or the "r-squared" 

value (0.26), which describes the relationship of unit load and ambient temperature, reinforces 

this conclusion, as these variables only account for 26% of the variability in overall heat rate of 

the population. Commenters stated that EPA should have stopped there, since 74% of the 

variability in heat rate is unexplained, but instead, EPA relied upon these two variables as a basis 

to identify available heat rate improvement opportunities. Commenters stated that EPA's failure

to examine other contributing uncontrollable factors leads to a significant overstatement of heat 

rate improvement opportunities.

Commenters stated that UARG's replication of the "r-squared" value using the EPA data, along 

with further analyses of the unit designs and other contributing factors to heat rate significantly 

weaken EPA's assertion that unexplained heat rate variability represents the potential for 

improvement. Commenters stated that not only did EPA's analysis not fully account for the role 

of load and ambient temperature, but also several other variables were ignored - most 

significantly boiler design differences and coal composition. Commenters stated that boiler type 

(e.g. subcritical, supercritical, ultra-supercritical), along with size, age, and ability to respond to 

load changes all will have impact on heat rate. Commenters stated that coal composition can 

affect heat rate through boiler thermal efficiency and slagging impacts, changes in flue gas 

moisture content, and auxiliary power requirements. Commenters stated that if EPA bases its 

final guideline on the existence of heat rate improvement opportunities, then the agency must 

reject the bin analysis and revisit its methodology for determining potential heat rate 

improvements through "best operational practices," and that such a revised analysis must more 

accurately account for unit-specific design differences and be premised on factors that more 

directly affect unit performance and accurately reflect available opportunities for improvement.

Commenters stated that the regression analysis used by EPA to assume a 4 percent heat rate 

improvement lacks sufficient technical data and fails to account for differences in coal rank, 

boiler type and boiler age, all of which have significant effects on heat rate efficiencies. 

Commenters stated that an analysis by Energy Ventures Analysis (EVA) using an algorithm that 

incorporates the factors EPA omits shows no incremental heat rate improvements were possible 

from additional practices. Commenters stated that the 2 percent improvement from capital 

investments rests upon a single 2009 study but however, EPA's reliance upon that study is 

misplaced since the study did not conclude that all coal plants can improve heat rates-let alone by 
265

2 percent from 2008. Commenters stated that at the same time, EPA's MATS rule, issued two 

years ago, requires extensive retrofits of existing plants that will make them less efficient by 

increasing their parasitic load and moreover, the present proposal will force many coal plants to 

run at reduced and sub-optimal levels which in turn will also make them less efficient. 

Commenters stated that EPA's analysis incorrectly assumes that the existence of variation in heat 

rate at individual units mean there is "significant variation in the operation of EGUs" indicating 

that "significant potential for heat rate improvement is available through the application of best 

practices." Id. at 2-30. Commenters stated that in fact, heat rate variability at individual units is 

driven by the design, duty cycle, fuel type, size, cooling conditions, and location of each unit, 

and it cannot be ameliorated by changes in operating practices (Cichanowicz Statistical Critique 

at 5-8). Commenters stated that EPA did not assess differences in variability based on these 

factors or control for these factors in its achievability analysis but that rather, the Agency's 

assessment was based on a simplistic and deeply flawed regression analysis of hourly unit 

capacity factor and ambient temperature on gross heat rate and on the Agency's observations 

regarding "residual" heat rate variation not accounted for by this regression (Id. at 3). 

Commenters stated that the report by UARG's consultants shows that much of the "unexplained" 

heat rate variability that EPA assumed could be reduced by implementing best practices actually 

reflects the impact on heat rate of differences in individual units' age, capacity factor, fuel type, 

boiler design, and cooling conditions, id. at 6-8, and that EPA's regression itself is flawed 

because its results defy known technical relationships between heat rate, operating duty, and 

ambient temperature (id. at 3-6).

Commenters stated that EPA's heat rate assessment analyzed gross data for 884 coal-fired 

electric generating units (EGUs) during a 10-year period. GHG Abatement Measures (EPA June 

2014) (EPA-HQ-OAR-2013-0602) pg. 2-18. Commenters stated that the regression analysis 

examined the effects of the capacity factor and the ambient temperature on the gross heat rate 

efficiencies of coal-fired EGUs. Commenters stated that the EPA's assessment concluded that instate coal units can achieve up to a 4 percent rate of improvement through the use of best 

operational practices. Commenters stated that an additional 2 percent of efficiency improvements 

would be achieved through capital upgrade investments. Commenters further stated that EPA's 

regression analysis does not adjust for the following factors that have profound effects on the 

process efficiency of a coal-fired EGU: (1) subcritical versus supercritical boiler designs; (2) 

fluidized bed combustion, integrated gasification combined-cycle (IGCC), and pulverized coal; 

(3) unit size and age; and (4) coal quality variations in moisture and ash (i.e., every 5 percent 

change in coal moisture results in a 1 percent change in boiler heat rate efficiency). Commenters 

added that lower-capacity factors will cause an increase in heat rates, particularly if the lowercapacity factors are due to the cycling of the coal units. Commenters stated that as a result of 

Building Block 2, coal units will cycle more often; therefore, assumed heat rate improvements 

across the entire coal fleet are unlikely. Commenters stated that while recognizing capacity 

effects in the regression analysis, the EPA did not evaluate the effects of lower-capacity factors 

resulting from the dispatching of natural gas generation before coal generation.

Commenters stated that the EPA performed 3 regression analyses: (1) heat rate onto capacity 

factor; (2) heat rate onto ambient temperature; and (3) heat rate onto capacity factor and ambient 

temperature. Commenters stated that EPA explains that because it is evaluating heat rate under 

normal operating conditions, it eliminated records with hourly heat rate values outside of +/- 2.6 
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standard deviations. Commenters stated that while this may be an acceptable practice for the 

EPA, it is contrary to standard statistical and economic practice for empirical work. Commenters 

stated that as explained in Chambers (1986), if the outliers in question are "elements with values 

that have been correctly recorded and that cannot be assumed...[that] there are no more similar 

outliers in the non-sampled part of the target population," then they should not simply be 

dropped from a regression. Commenters stated that the EPA states that these outliers occur for 

plants utilizing partial operating hours and low load conditions and are not due to incorrect data 

or other problems and that this type of outlier should not be ignored, since it is still representative 

of some portion of the population. Commenters stated that there is simply no statistical rationale 

for the EPA's selective exclusion of this data. Commenters stated that the EPA's regression 

results are expressed as the "R-squared" of the regression, which is one measure of the goodness 

of fit; however, the EPA's model omits a number of important variables, and thus it cannot be 

said with certainty that the R-squared is attributable to capacity factor and ambient temperature 

alone. Commenters stated that when variables are omitted, the estimated coefficients may be 

biased in the amount that they are correlated with the included variables. Commenters stated that 

one example of an omitted variable is one representing the degree to which the unit is loadfollowing. Commenters stated that the EPA recognizes that load-following is vitally important in 

determining heat rate. Commenters stated that if a load-following plant has a large capacity, then 

the estimate for the impact of capacity on heat rate will be higher since it is also capturing the 

impact of load-following on heat rate. Commenters stated that thus, the capacity impact will be 

overestimated and similarly, plants that have many starts, will have higher heat rates since it 

takes more fuel to produce less energy. Commenters stated that however, the EPA's analysis 

removes observations with higher heat rates even if those higher rates were due to higher number 

of starts. 

Commenters stated that the second portion of the EPA statistical analysis, which utilizes a bin 

model to determine the potential improvement from using best practices, groups plants into bins 

based only on temperature and capacity. Commenters stated that this analysis raises similar 

concerns with reliability and comparability as noted earlier in the criticisms of the initial 

regression analysis. Commenters stated that for instance, if plants with similar temperature 

and/or capacity are different in other important yet unconsidered ways, then the EPA's statistical 

bin analysis will not be appropriate. Commenters stated that this is of particular importance since 

the EPA's proposed HRI is based on "comparable" plants within the same bin, which very well 

could be unreliable if plants differ based on unconsidered factors. Commenters stated that EPA 

also cites Fredricks and Todd (2009) as proponents for the widely applicable reduction in heat 

rate in power plants by better data monitoring: statistical process control ("SPC"). Commenters 

stated that Fredricks and Todd discuss the use of what is today more frequently referred to as the 

use of "big data" in improving the identification of problem areas in electricity generation and 

while these methods can be informative in the use of better statistical methods and data 

collection processes, Fredrick and Todd warn that their findings cannot be generally applied, 

which is what EPA appears to be doing in its third methodology. Commenters stated that 

Fredrick and Todd, for instance, only consider the impact of SPC in 2 plants, where the costs and 

improvements found are in no way representative of the population of power plants in operation. 

Commenters stated that the authors stress (much like Sargent and Lundy) the importance of 

plant-by-plant analysis to provide true cost and potential heat rate reduction estimates. 

Commenters stated that the cost estimates provided by the EPA are too general, and contradict 

suggested methodology by existing literature. Commenters stated that the EPA concludes that 
267

the results of its analysis display a wide range of heat rate variability thus indicating the potential 

for heat rate improvement. Commenters stated that the generation-weighted mean RSD for the 

study population is 5.4 percent: a value weighted more heavily for large units, which also likely 

have larger potential improvement on average. Commenters stated that this methodology will 

provide a disproportionate estimate which does not directly correspond for smaller units. 

Commenters stated that similarly, the EPA admits that there has been a large change in quality of 

reporting for a number of plants over the 11 year sample, the implications of which are not fully 

considered in the development of the Building Block 1 recommendations. Commenters stated 

that for example, EPA does not indicate how Table 2-8 (in its GHG Abatement Measures TSD) 

will change if instead of using data from the previous 11 years, only the previous five years' data 

are included, where the data reporting changes have already occurred.

Commenters stated that the reporting methods for heat rate are noisy: the level of accuracy for 

heat rate measurement varies by EGU, which causes statistical noise in any analysis using this 

measure. Commenters stated that statistical noise is a common concern in empirical research, but 

nonetheless needs to be addressed in a straightforward and open manner. Commenters stated that 

the EPA states," approximately two-thirds of the large decreases in heat rate can be associated 

with changes in reporting method implemented to provide more accurate heat input data."

Commenters stated that if the heat rate measures remained noisy throughout the sample period, 

this would just create attenuation bias in any regression estimates for heat rate. Commenters 

stated that however, in this case, the heat rate measures for some EGUs become less noisy over 

time. Commenters stated that this means that if the "noisiness" of a plant's heat rate reporting is 

related to one of the variables in the estimated regressions, the error term will be heterogeneous 

and dependent on time. Commenters stated that heterogeneous errors violate the assumptions of 

OLS regression, but the full extent of the impact cannot be determined without further analysis.

Commenters stated that EPA's regression analysis indicates that approximately "16% of the 

change in hourly heat rate is attributable to capacity factor and 10% to ambient temperature. 

Commenters stated that these results, however, conceal considerable variability. Commenters 

stated that some EGUs, typically load-following, have an 11-year average r-squared capacity 

factor exceeding 50%. Commenters stated that at those EGUs, the capacity factor is a key 

variable influencing changes in heat rate." Commenters stated that the EPA was unsuccessful in 

identifying all the variability in its dataset, and their review of several other studies indicates that 

heat rate performance analysis is very complicated and for this reason, and that they believe a 

6% requirement is unachievable everywhere and overinflates CO2 emission reduction potentials 

under Building Block 1. 

Commenters stated that relying on statistical analysis and examining only 16 EGUs (actually 2 

EGUs) to establish HRI percentages due to best practices for equipment upgrades does not truly 

establish BSER for existing EGUs. Commenters recommended that prior to setting any percent 

improvement in heat rate from best practices or costly equipment upgrades, a more thorough 

analysis of achievable HRI BSER using actual EGUs is performed. Commenters recommended 

establishing a net heat rate threshold which provides a standard of performance for poorer 

performing units to reach without penalizing best performing units. 

Commenters stated that to assess the impact of capacity factor and ambient temperature on heat 

rate, EPA performed regression analyses for “each unit year.” Commenters questioned how the
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EPA selected this methodology. Commenters also questioned why the EPA did not calculate a 

separate regression for each unit, for each year from 2002 to 2012. Commenters also questioned 

why the EPA did not have this statistical analysis peer-reviewed.

Commenters stated that EPA's finding that 26 percent of the variability in heat rate could be 

explained by load factor and temperature is an extremely weak statistical finding and therefore 

has virtually no predictive value. Commenters stated that in practical terms, it means that the vast 

majority of heat rate variability is caused by something unknown to EPA. Commenters stated 

that EPA made no attempt to identify these other causative factors by further regression analysis, 

rather, the Agency made an unsupported conjecture that maintenance and replacement practices 

were significantly responsible for variability in heat rate.

Commenters stated that the use of ambient temperature as a surrogate for climatic effects on heat 

rate is invalid. Commenters stated that cooling water temperature is a significant determinant of 

power plant heat rate, but ambient air temperature is not a reasonable indicator of cooling water 

temperature and water bodies change temperature much more slowly than ambient air, so warm 

early Spring air temperatures are not reflected in nearby water temperatures (with the opposite 

error when air temperatures decrease in early Fall), and large fluctuations in day/night air 

temperatures are not reflected in surface water temperatures.

Commenters stated that the 10th percentile "best" performance level, and the 10 percent-50 

percent reductions in difference, is all arbitrary values that have a significant impact on the 

result. Commenters stated that for example, had EPA decided that the 25th percentile unit was 

more representative of "good maintenance," the agency would have calculated a much lower 

potential HRI for the fleet. 

Commenters stated that most utilities have already implemented ongoing heat rate improvement 

programs to capture the efficiency gains that EPA is assuming in the "best practices" portion of 

its Building Block 1 assumption, making a further 4 percent improvement unlikely. Commenters 

stated that the ability to achieve a 2 percent improvement through equipment upgrades will vary 

from plant to plant and new plants, and particularly supercritical units such as Weston 4, will 

likely not be able to improve their heat rates and in addition, plants that have already 

implemented equipment upgrades will have less opportunity to make further improvements. 

Commenters stated that the 4 percent was derived from a regression analysis using capacity 

factor and ambient temperature and there is no indication the analysis took into account 

parameters such as coal type, boiler type and unit age, all of which affect heat rate. Commenters 

stated that EPA's failure to consider the interaction between building blocks and the impact of 

other EPA rules on heat rate also call into question the validity of the regression analysis.

Commenters stated that the 2 percent was derived from a January 2009 Sargent & Lundy study 

entitled "Coal-Fired Power Plant Heat Rate Reductions," however, nowhere in this report did 

Sargent & Lundy conclude that average plant efficiencies for all coal fired plants could be 

improved by 2 percent from 2008 levels, much less by 2 percent from 2014 levels for an average 

capital upgrade investment of $100/kw, as claimed by EPA. Commenters stated that on the 

contrary, Sargent & Lundy stated on page 1-3 of their report that the costs in their study should 

not be used as a basis for project budgeting or financing purposes. Commenters stated that yet 

this is precisely what EPA has done.
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Commenters stated that the Sargent & Lundy study included only two case studies, both for 

1970's vintage power plants. Commenters stated that two plants are not sufficient to represent the 

nation's current coal fleet and in addition, the EPA regression analysis ignored the fact that 

equipment based heat rate improvements degrade over time between periodic overhauls. 

Commenters stated that Indiana's generation portfolio is predominantly coal-fired; thus the 6% 

heat rate improvement applied by U.S. EPA drives a portion of the carbon emission reductions 

required for the state. Commenters stated that while the data collection efforts of U.S. EPA are

substantial, an important conclusion appears to lack justification. Commenters stated that Page 2-

28 of the Greenhouse Gas (GHG) Abatement Measures Technical Support Document (TSD) 

states that "if an EGU reduces heat rate variability, generally heat rate performance will 

improve." Commenters stated that this conclusion appears to be supported by U.S. EPA's Figure 

2-5 on the page following this statement. Commenters stated that the regression analysis 

exaggerates this correlation because of the inclusion of what is clearly an outlier. Commenters 

stated that removing the outlier from the data set yields a best fit line defined by y = 0.0009x -

3.7804. Commenters stated that the outlier's impact, at a minimum, warrants further investigation 

on the appropriateness of its inclusion. Commenters stated that absent a strong reason for 

inclusion, the outlier should be removed from the data set. Commenters stated that while reduced 

heat rate variability would appear to be an attractive characteristic, the correlation of it to overall 

heat rate improvement is inappropriate.

Commenters stated that EPA miscalculated the data distribution for certain units and certain 

load/temperature bins, resulting in substantial overestimation of the variability in heat input. 

Commenters stated that EPA's analysis, which corrects for ambient temperature and gross load, 

does not correct for a sufficient number of factors to reflect variability that might reasonably 

reflect an opportunity to improve heat rate through improved operating practices.

Commenters stated that EPA claims that 26% of the variability in heat rate over the unit 

population can be explained by changes in load and ambient air temperature, leaving 74% of the 

variability unexplained. Commenters stated that EPA thus concludes the remaining, unexplained 

variability represents potential for heat rate improvement. Commenters stated that the following 

variables have not been fully accounted for: coal composition, boiler design and ambient 

temperature. Commenters stated that the 2014 UARG Heat Rate Report describes how fuel 

composition affects both gross and net heat rate through boiler thermal efficiency, flue gas 

moisture content, and auxiliary power requirements and that the variations in fuel heating value 

and composition will present very different fouling and slagging potential to heat removing 

surfaces that affect boiler performance. Commenters stated that the 2014 UARG Reference Unit 

Assessment cites at least two units that incurred significant changes in coal composition over the 

period of 2002-2012, which based on owners' observations impacted gross heat rate. 

Commenters pointed out that differences in boiler design can account for variability of heat rate, 

particularly when comparing "supercritical" and "subcritical" units where the supercritical 

boilers - featuring so-called "sliding pressure" part-load operation - respond effectively to load 

changes and thus do not exhibit the same relationship between heat rate and load as subcritical 

boilers. Commenters stated further that older boilers that are smaller in generating capacity can 

feature a different arrangement of steam surfaces and that these units may also be equipped with 

less complex environmental controls, relegating them lower in dispatch order and subject to 

frequent cycling. In addition Commenters stated that EPA oversimplified the analysis of ambient 
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temperature, as suggested by the fact that almost 40% of the units studied exhibited an inverse 

relationship between ambient temperature and heat rate. Commenters stated that ambient air 

temperature is important, but this variable alone does not capture the seasonal change in heat 

rejection, rather almost 40% of the generating plants in the database use once-through cooling 

with river or pond water, and for these units the temperature of cooling water is more directly 

linked to the thermal performance. Commenters stated that for cooling towers, humidity is also 

important and is linked to ambient temperature. 

Commenters stated that EPA ignores a number of factors that lead to heat rate variability at 

power plants, stating that variability other than due to capacity factor and ambient temperature 

implies available "best practices" improvements. Commenters stated that EPA also makes overly 

simplistic assumptions concerning the fleet-wide potential to improve efficiency through a series 

of undefined "best practices." Commenters stated that EPA ignored several important factors that 

impact coal-fired power plant heat rate variability in their statistical analysis and when analyzing 

heat rate variability, EPA attributed 26 percent of variability to variations in load and ambient air 

temperature. EPA erroneously assumed the remaining 74 represented the potential to improve 

heat rate. Commenters stated that by only focusing on load and ambient temperature, EPA 

ignored a series of factors that can further explain heat rate variability and which are not 

controllable through "best practices." Commenters stated that for example, the type of coal used 

can significantly impact heat rate through a variety of means, including flue gas moisture content 

and the varying fouling and slagging potential among different coal types. Commenters stated 

that additionally, EPA ignored various boiler design parameters, most importantly whether the 

boiler operates at subcritical or supercritical steam conditions. Commenters stated that some 

supercritical boilers, for example, will be less affected by variations in load and beyond ambient 

air temperature, ambient water temperature, not considered by EPA, plays a significant role in 

the heat rate of coal-fired power plants, especially those using once-through cooling systems.

Commenters stated that EPA also does not fully capture the capacity factor, and the related 

amount of cycling a coal-fired power plant may undergo.

Commenters stated that EPA's bin analysis is flawed and does not demonstrate that most heat 

rate variability is caused by inadequate O&M practices. Commenters stated that EPA conducted 

a regression analysis of 884 generating units and concluded that units with more variable heat 

rates tend to have higher heat rates. See Abatement Measures TSD at 2-26. Commenters stated 

that even assuming this was true, the regression analysis only identified the relationship between 

variability and higher heat rates, it did not identify the cause of the variability and as such, the 

Proposed Rule merely assumes that the cause must be deficient O&M, but there are other factors 

that may cause this variability. Commenters stated that the Proposed Rule is not based on any 

effort to assess whether any other factors-and not O&M practices-caused or contributed to the 

observed variability. 

Commenters summarized EPA's variability analysis. Commenters concluded that EPA's 

assumption ignores numerous causes of heat rate variability that are beyond the ability of coal 

units to control, such as:

• Commenters listed variability in coal quality, such as heat content (Btus) and 

moisture and stated that EPA recognizes, for instance, that coal rank quality can 
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have an impact on heat rate, and that reducing coal moisture through drying can 

improve heat rate (which confirms that high moisture can degrade heat rate.

• Commenters listed variability in pollution control efficiency and electricity 

demand (which can also be affected by variability in coal quality) and stated that 

although EPA recognizes that pollution controls can affect heat rate, it fails to 

recognize the unavoidable variability inherent in the operation of those controls. 

• Commenters listed variability in other ambient and weather conditions that can 

impact heat rate, such as humidity and rainfall (which can affect the temperature 

of the cooling water resource and the moisture of the coal and stated that although 

EPA recognizes that barometric pressure and cooling water temperature affect 

heat rate, it fails to account for anything other than air temperature in its analysis. 

• Commenters listed variability attributable to unavoidable cycles in the 

degradation of components that are designed to wear out over time (e.g., air heater 

baskets, pulverizer rollers, baghouse bags, cooling tower fill, etc.) and stated that 

although EPA recognizes that component replacements can improve heat rate, it 

fails to account for the varying rates of degradation of components over time that 

can affect heat rate variability. 

• Commenters listed variability attributable to changes in heat rate calculation 

method. EPA recognizes that, of the 355 units with large year-to-year changes in 

heat rate, two-thirds of those large changes were attributable to changes in 

reporting method and stated that EPA, however, continues to count the data 

affected by those changes in reporting method in its calculations. 

• Commenters stated that EPA fails to recognize that some plants may have lower 

heat rate variability for other unavoidable reasons, which may skew the data 

based on unit characteristics that cannot be replicated at other facilities. 

Commenters referred to NERC stating, "[t]he EPA's regression analysis does not adjust for the 

following factors that have profound effects on the process efficiency of a coal-fired EGU: (1) 

subcritical versus supercritical boiler designs; (2) fluidized bed combustion, integrated 

gasification combined-cycle (IGCC), and pulverized coal; (3) unit size and age; and (4) coal 

quality variations in moisture and ash (i.e., every 5 percent change in coal moisture results in a 1 

percent change in boiler heat rate efficiency)." 

Commenters stated that EPA's analysis thus fails to account for all the possible source of heat 

rate variability and also fails to address the potential cumulative effect of all of those factors 

together and that EPA has not provided sufficient support for its assumption that the "residual" 

variability in existing coal unit heat rates can be eliminated through the implementation of 

improved O&M practices. 

Commenters stated that to support their conclusion, EPA used a statistical analysis that first 

presumes that a well-controlled facility using "best practices" should have a very repeatable heat 

rate under any given ambient temperature or hourly average load condition. Commenters stated 
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that EPA assumes that any variability in heat rate not explained by temperature or load is 

regarded as an indication that the facility operation is inconsistent and can be improved upon and 

that EPA's analysis showed that, on average, ambient temperature and load only explained about 

one fourth (26%) of the variation in heat rate. Commenters stated that this suggests one of two 

possibilities: 1) that there is a lot of opportunity for improvement to address the nearly three 

quarters of the variation not explained by temperature or load, or; 2) EPA's premise that a wellcontrolled facility using "best practices" should have a very repeatable heat rate under any given 

ambient temperature or hourly average load condition is incorrect. Commenters believed the 

latter explanation for the low explanatory power of temperature and load because other important 

factors that impact heat rate, including changes to the plants over the eleven year period such as 

addition of low NOx burners, addition of SCRs, soot blower controls, furnace and burner 

management systems, etc., were not considered in EPA's analysis. Commenters stated that as a 

result of the exclusion of these and other important factors, what appears in EPA's analysis to be 

variability that can be better controlled is actually the result of these other effects. Commenters 

further stated that the majority of the coal fleet already has some form of optimization software 

built into its controls and that these optimization systems use input from hundreds of sensors in 

the plant to develop control algorithms used to operate the plant in a manner that optimizes the 

plant with respect to efficiency, reliability, safety, and environmental compliance. Commenters 

stated that EPA's approach to statistically evaluating the operation of the plants against only two 

variables is unnecessary and too simplistic in light of the fact that many facilities already use 

very sophisticated systems that were tailor made to optimize that plant's operations while 

monitoring hundreds of sensory inputs.

Commenters stated that EPA associates heat rate variability with potential for heat rate 

improvement, stating "results display a wide range of heat rate variability in the study population 

and thereby indicate potential for heat rate improvement." Commenters stated that the units in 

these four quartiles have very different design characteristics that contribute to the differences in 

heat rate variability and that the EPA incorrectly ignores these design features, and erroneously 

assumes that "best practices" can mitigate this variability and lead to lower heat rate. 

Commenters stated that EPA recognizes the fraction of generation produced by units in the 

quartiles defined by the Residual Standard Deviation of heat rate varies from 33% for the first 

quartile to 16% for the fourth but makes no further inquiry to explore unit differences. 

Commenters reproduced EPA’s results by identifying the units in each quartile, then determining 

for units in each quartile the (a) average generating capacity (MW), (b) average unit age (yrs), (c) 

average capacity factor, (d) fraction of units firing bituminous coal, (e) fraction of units using 

supercritical boilers, and (f) fraction of units employing once-through cooling for heat rejection 

(Figure 1- design and operating features for an average unit in each of the four quartiles, except 

generating capacity, which decreased in a stepwise, linear manner from 433 MW in the first 

quartile to 291 MW in the fourth quartile). Commenters stated that the figure shows - without 

exception - each design or operating trait exhibits a stepwise change from the first through the 

fourth quartile. Commenters then demonstrated that, compared to the first quartile, units in the 

fourth quartile on average are 8 years older and operate at 2/3 of the capacity factor as firstquartile units and that almost 2/3 of units in the fourth quartile fire bituminous coal, compared to 

less than 40% in the first quartile which results in more units in the fourth quartile being subject 

to greater variability in fuel composition and heating value. Commenters continued stating that 

differences in boiler design - supercritical vs. subcritical steam conditions - are notable and could 
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affect variability in steam conditions between the quartiles and that about 3/4 of units in the 

fourth quartile employ once-through cooling, compared to less than half in the first-quartile. 

Commenters stated that therefore fourth-quartile units are subject to a greater degree of 

variability in cooling that was not captured by ambient air temperature, and thus not accounted 

for by EPA. 

Commenters stated that EPA based its analysis on variability in hourly heat input, not on 

variability in hourly gross heat rate. Commenters stated that variability in heat input is not a 

measure of efficiency and EPA erroneously labels any differences in hourly heat input that are 

observed in the data set for a particular EGU and that cannot be explained by differences in 

capacity factor or ambient temperature as "heat rate variability." Commenters stated that EPA 

assumes that this heat rate variability is "attributed to operation and maintenance practices" and 

is indicative of a "potential for heat rate improvement;" in other words, EPA assumed that each 

operating hour for which a particular EGU's heat input is greater than the heat input during other 

operating hours for that EGU with similar ambient temperature and capacity factor, represents an 

opportunity to improve upon the EGU's performance during that hour. Commenters stated that 

this assumption is not valid, as EPA's analysis did not attempt to take measurement error, and the 

potentially significant effects of this error, into account. 

Commenters stated that to examine U.S. EPA's assumptions concerning the influence of ambient 

temperature, load, and operator practices on heat rate, they compiled gross generation, heat input, 

and operating time data for coal-fired units in Ohio, years 1997 to 2013 and from this dataset, 

they selected several "sister" units; that is, units of the same design and capacity with identical 

cooling systems and control measures, operating at the same facility. Commenters stated that via 

outreach to the operators of these units, they have confirmed that these units also burn the same 

fuels and are subject to the same maintenance practices and in selecting "sister" units of this 

nature, and that they believed that the influence of ambient temperature can largely be ignored 

when comparing these units side-by-side. Commenters furthermore stated that understand the 

units selected are maintained using best-practice methodologies, have identical operators, and 

utilize the same fuel Commenters noted that they recognize that ambient temperature and 

capacity factor are significant controlling factors in the heat rate of a coal-fired EGU, and is not 

attempting to present arguments to the contrary but does attest that other variables, including 

those well beyond the control of best-practices and maintenance, have influence, as well. 

Commenters stated that thus, when establishing HRIs as part of BSERs, U.S. EPA should 

consider additional variables beyond those two, and recognize fully that much of the variation in 

heat rate is not under the control of the operator. Commenters stated that based on these results, 

it is clear that if a statistical analysis is to serve as the basis for setting national HRI goals, U.S. 

EPA must consider more than ambient temperature and capacity factor, account for past HRI 

measures, limit heat rate variability within the capacity factor bins, and recognize that some 

variability cannot be attributed to any known variable. Commenters, therefore, believed that a 

statistical analysis is not the appropriate approach to the setting of HRI goals but that instead, 

unit-specific engineering studies of past HRI projects with resultant measured HRIs is the only 

way to determine potentially feasible improvements. Commenters stated that this should be 

informed by what HRI projects have already been completed at each individual unit and the 

status of best-practices at each individual unit. Commenters further stated it is difficult for them

to reconcile that U.S. EPA has proposed HRI goals for a mature coal fleet without considering 
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what projects and best-practice measures have already taken place with the "demonstrated 

technology" aspect of setting BSER.

Commenters stated that U.S. EPA worked with the hourly data (converted to hourly gross heat 

rate) reported by approximately 900 individual coal-fired steam EGUs over the period from 2002 

to 2012 to determine the degree of HRI that can be achieved by best practices. Commenters 

stated that specifically, this data analyzed variability in order to evaluate the consistency with 

which individual EGUs maintained their hourly heat rates over time. Commenters stated that 

U.S. EPA said they expected, and confirmed, that a certain degree of short-term heat rate 

variability was caused by factors beyond operators' control, notably variation in hourly ambient 

temperature and hourly load. Commenters stated that therefore, U.S. EPA attempted to control 

for variation in those factors by grouping the data for each EGU into subsets corresponding to 

ranges of hourly ambient temperatures and hourly load levels. Commenters stated that U.S. EPA 

assumed that between 10% and 50% of the deviation from top decile performance in each subset 

of hourly heat rate observations within defined ranges of temperature and load could be 

eliminated through adoption of best practices, the result is a corresponding estimated range of 

1.3% to 6.7% technical potential for improvement in the average heat rate of the entire fleet of 

coal-fired EGUs. Commenters stated that based on this analysis, U.S. EPA believes "a 

reasonable estimate for purposes of developing state-specific goals is that affected coal-fired 

steam EGUs on average could achieve a four percent improvement in heat rate through adoption 

of best practices to reduce hourly heat rate variability". Commenters stated that this corresponds 

to the elimination, on average across the fleet of affected EGUs, of 30% of the deviation from 

top-decile performance and in addition, U.S. EPA is also considering the use of estimates up to 

6%, reflecting elimination on average of 50% of the deviation from top-decile performance. 

Commenters stated that they acknowledge that U.S. EPA conducted an extensive analysis of heat 

rates across a large majority of the nationwide coal-fired fleet but that however, there is a 

significant disconnect between that study and the proposed nationwide HRI. Commenters stated 

that this is acknowledged by U.S. EPA.

Commenters stated that the proviso is important to this analysis because the EPA expects that a 

significant fraction of the coal fleet has already applied some or many of the available HRI 

methods. Commenters stated that the EPA does not have sufficient site specific information to 

accurately estimate what percentage of the fleet has adopted various HRI methods, nor how 

effectively, and is not aware of any other investigator having sufficient information. Commenters 

stated that HRI potential can therefore not be estimated at this time through analysis of the 

current equipment configurations of the coal steam-EGU fleet. Commenters stated that the EPA 

therefore analyzed 11 years of historical heat rate data and the literature on HRI methods, as 

discussed earlier in this TSD, to estimate that the U.S. coal-steam EGU fleet might reasonably be 

expected to reduce its annual average gross heat rate by about 6%. 

Commenters stated that they understands that the analysis conducted by U.S. EPA was extensive 

and comprehensive, and adequately demonstrated that there is a great deal of variability in heat 

rates across the coal-fired fleet, and indeed at individual units. Commenters stated that this does 

not adequately demonstrate that a 6% HRI is feasible and cost effective at the unit-level, nor that 

the variability not associated with ambient temperature and load is under the control of the 

operator. Commenters stated that indeed, the study assumed that any variability in heat rate not 

associated with load and ambient temperature could be mitigated through capital investments and 
275

best practice operational methods without further justification. Commenters stated that it also 

ignores that variability, or quick sustained jumps, in heat rates can be caused by other factors. 

U.S. EPA "presumption" that the "data apparent" instances where an EGU's heat rate 

experienced a substantial improvement in a short time was due to equipment upgrades is without 

any technical basis and actual knowledge of the cause of those HRIs. Commenters stated that 

they understand that some quick, sustained HRIs could result from improved monitoring 

equipment, optimization of control equipment, enhanced air-flow awareness programs, and a 

variety of other factors not directly attributable to equipment upgrades. 

Commenters stated that even though a coal-fired EGU may supply electricity for base-load 

demand, its heat rate will still vary and certainly not be static over time. Commenters stated that 

this variability is due not only to load or hourly temperature, but also the equipment condition 

and physical design of the EGU's systems and that even well-controlled units that already 

employ best practices of operation and maintenance to improve heat rate demonstrate significant, 

variable fluctuations that cannot be directly correlated to the best practices. Commenters stated 

that, therefore, EPA should not set a specific CO2 emission rate for states because a static limit is 

not a reasonable standard in the case of unavoidably variable CO2 emissions from coal-fired 

EGUs

Commenters asked, with regards to reducing unit heat rate variability through use of "best 

operating practices"

1. Why did the EPA conclude that variability in reported heat rate from units is the result of 

unit operations, and rule out other factors (besides capacity factor and ambient 

temperature)?

2. What expert authorities did the EPA consult with to arrive at such a conclusion?

Comment 29: Applicable to the supplemental proposal for Tribal and Territorial – Comments 

regarding factors affecting heat rate variability and potential heat rate improvement 

Response 29: For the EPA’s response to these comments, see section V.C of the final rule 

preamble of the CPP and Chapter 2 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 EPA's view that a 4% improvement in heat rate is possible through noor low-cost "best practices" was based upon a statistical analysis that overlooked important 

sources of variability in heat rates.

Comment 30: Comments regarding heat rate variability and performance 
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Response 30: See section V.C. of the final rule preamble of the CPP for EPA’s response to this 

comment.

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

Commenters stated that EPA's inferences with respect to a causal relationship between high 

variability in calculated hourly gross heat rate data and poor heat rate performance are without 

foundation. Commenters stated that EPA observes a positive statistical correlation between the 

level of variability in calculated hourly gross heat rate data and annual gross heat rate (i.e., a

negative correlation between variability and efficiency) and from this observation, EPA draws a 

critical inference regarding causal relationship:

"These results indicate that, other factors held equal, if an EGU reduces heat rate variability, 

generally heat rate performance will improve."

Commenters summarized EPA's assumptions and analysis. Commenters stated that EPA's bin 

analysis is flawed and does not demonstrate that most heat rate variability is caused by deficient 

O&M practices. Commenters stated EPA’s assumption that reduced variability in heat rate 

implies an improvement in a unit's heat rates indicates a failure to understand what "variability" 

is and what actually causes it. Commenters stated variability is change relative to an average 

value, not relative to a theoretical optimal value (or top decile).

Commenters stated that the EPA conducted a regression analysis of 884 generating units and 

concluded that units with more variable heat rates tend to have higher heat rates. Commenters 

stated that even if this were true, the regression analysis only identified the relationship between 

variability and heat rates but it did not identify the cause of the variability. Commenters stated 

that the EPA has made the assumption that the cause must be deficient O&M, but that 

assumption is wrong. Commenters stated that there are other factors that cause this variability, 

such as EGUs engaging in flexible operations such as cycling, load following, and extended low 

load periods. Commenters stated that the 2002-2012 data period the EPA analyzed also included 

a severe economic downturn, a drop in natural gas prices which affected dispatch of coal firedEGUs, and changes in continuous emissions monitor ("CEMs") reporting methodology. 

Commenters stated that the EPA has made no effort to determine whether any of these factors 

could have led to the observed variability or change in heat rate trends. Commenters stated that 

the EPA cited nine different categories of factors influencing heat rate and that the EPA's 

analysis attempted to partially account for some of these factors, including load factor and 

ambient temperature. Commenters stated that other factors that affect heat rate include unit size 

and steam conditions and that the EPA's only attempt to recognize and control for the range of 

factors that might affect variability in heat rate was an assumption that 50 percent of the 

variability observed in bin data was caused by deficient O&M practices. Commenters stated that 

in an attempt to be "conservative," the EPA then adjusted that assumption down to 30 percent in 

the estimate of heat rate improvement potential for "best practices." Commenters stated that the 

EPA's arbitrary assumption was not supported by their analysis and did not identify the actual 

cause(s) of the observed variability in heat rates and that if heat rate variability cannot be directly 

attributed to deficient O&M practices, then the EPA has no basis to assert that O&M "best 

practices" will result in a HRI of 4 percent or any percent.
277

Commenters stated that what the EPA's own analysis likely indicates is that load factors, not 

O&M practices, play a significant role in explaining coal-fired EGU heat rate variability. 

Commenters stated that the EPA's bin analysis reduced the effect of load factor change, but each 

bin itself includes a 10% range of load factors. Commenters stated that an International Energy 

Agency ("IEA") report found that a 10% change in load factor can result in a 4 percent change in 

heat rate. Commenters stated that thus, the bin approach reduced, but did not eliminate, the very 

significant impact of variable load factor on heat rate.

Commenters stated that it is well proven that load factor (or capacity factor) has an inverse 

relationship with heat rate for coal-fired EGUs and the higher the load factor, the lower the heat 

rate and, conversely, lower capacity factors (and increased cycling) increase average heat rates 

and also increase heat rate variability. Commenters stated that in the integrated electric grid, 

economic conditions are causing coal-fired EGUs increasingly to be dispatched to respond to 

load rather than running as base load units and therefore unit owners and operators cannot 

control load factor on these EGUs to address concerns about heat rate. Commenters stated that if 

the variation within bins is significantly influenced by load factor, heat rate variability would not 

be able to be addressed by the implementation of O&M "best practices" at all.

Commenters stated that the analysis supporting the Proposed Rule does demonstrate that, even 

after attempts to control for load factor via the bin analysis, load factor is a very important 

determinant of heat rate for units with varying load. See Abatement Measures TSD at 2-25. 

Commenters stated that the bin analysis reduced the effect of variable load factors, but each bin 

itself includes a 10 percent range of load factors. See Abatement Measures TSD at 2-24 to 2-25. 

Commenters stated that an International Energy Agency (IEA) report found that a 10 percent 

change in load factor can result in a four percent change in heat rate and thus, the bin approach 

reduced, but did not eliminate, the very significant impact of variable load factor on heat rate. 

Commenters stated that in the integrated electric system, units are dispatched to respond to load. 

Commenters stated that unit owners and operators, therefore, cannot control load factor to 

address concerns about heat rate. Commenters stated that they cannot, therefore, control the 4% 

heat rate variability within EPA's bins and even if they accepted EPA's premise that best 

practices could improve heat rate by 4%, this within-bin heat rate variability that is not accounted 

for by EPA would effectively cancel out any such alleged potential for improvement.

Comment 31: Comments regarding the impacts of load following on capacity factor variability, 

especially due to the interplay with building blocks 2 and 3

Response 31: For the EPA’s response to these comments, see sections V.A and V.C of the final 

rule preamble of the CPP and Chapter 2 of the GHG Mitigation Measures TSD supporting the 

final CPP. For example, as stated therein, we acknowledge that some heat rate improvement 

measures—like most power plant components—require maintenance in order to sustain their 

efficacy over time. Accordingly, EGU owners and operators will need to diligently apply best 

practices in order to mitigate this degradation, and may need to more frequently replace 

components. Additionally, our heat rate assessment was based on historical data from 884 EGUs, 

and thus reflects instances of increased capacity factor due to the rebound effect.
278

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

Commenters stated that wind power-induced variable load contributed to heat rate variability. 

Commenters stated that starting in 2010, the owner identified the need to "chase wind" as 

prompting highly variable capacity factors - specifically, the standard deviation of the capacity 

factor for Antelope Valley Unit 2 for the years 2010 to 2012 ranged between 13-16, which is 

twice the standard deviation calculated for some of the years from 2003 through 2008. 

Commenters stated that 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 EPA must address the effect of shifting generation from coal-fired EGUs 

to NGCCs and to renewables will have on the heat rates. The commenters also stated that as coal 

fired EGUs are utilized less, heat rates will degrade, negating HRIs and possibly stranding the 

investments made to implement HRIs.

Commenters summarized the EPA's use of the Sixteen Unit study as justification for the 

proposed 6% HRI. Commenters stated that in the case of Antelope Valley Unit 2, high variable 

capacity factors due to the unit's need to follow wind energy resulted in significant heat rate 

variation and that this observation mirrors results in the NRECA S&L study that demonstrate

heat rate inefficiencies are clearly associated with unit cycling. Commenters stated that EPA HRI 

analysis has failed to address the impact of additional wind energy on overall industry fossil fuelfired EGU heat rates, and that in short, NRECA's Nine Unit Heat Rate analysis verifies UARG's 

critique of EPA's Sixteen Unit analysis that EPA has simply misused its own heat rate data in the 

Sixteen Unit Study to wrongly determine individual unit and industry-wide potential for heat rate 

improvements.

Commenters stated that EPA's assessment that plant operational efficiency can be improved by 

4% is also incorrect and in point of fact, coal plant operations are likely to become less efficient 

across the nation. Commenters stated that combination of change in dispatch to base load natural 

gas plants (BB No. 2) over coal plants and the increased penetration of variable renewable 

resources (BB No. 3) will actually decrease plant efficiency. Commenters stated that the majority 

of coal plants that are likely to remain operational in a post-utility Maximum Achievable 

Technology Standard (MATS) [sic] world are plants that are designed to operate at maximum 

efficiency as base load plants. Commenters stated that because EPA has structured a rule that 

largely switches the order of dispatch to base load natural gas plants and to cycle coal plants this 

efficiency is lost. Commenters stated that coal plants will be forced to follow load throughout the 

day, increasingly operate at minimal load levels and cycle off and on more frequently. 

Commenters stated that each of these actions has a significant impact on the operational 

efficiency of the coal plant that will not only eliminate EPA's presumed 4% operational 

efficiency but also more than offset it resulting in higher emissions rates for coal plants that 

continue to operate. 

Commenters stated that coal-fueled resources typically operate at their most efficient operating 

point when operated at or near full load and as coal fueled plants operate at lower loads, their 

efficiency declines. Commenters presented a chart showing how heat rate degrades as an 

example coal unit is operated at less than full load. Commenters stated that this chart illustrates 
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that the heat rate increases by six percent as a result of the plant reducing its output from 89 

percent of full load to 52 percent of full load. Commenters stated that EPA's future resource mix 

and operation, which contemplates such reduced utilization of coal resources, does not take into 

account that any efficiency improvement opportunity associated with coal fueled generation will 

be offset by the reduction in efficiency associated with lower load operation. 

Commenters stated that with the incorporation of other Building Blocks, certain heat rate 

improvements will be lost due to increased cycling and changes in unit dispatch needs.

Commenters stated that the low carbon generation requirements of the rule will decrease the 

efficiency of the fossil plants as they need to be de-rated to accommodate the variability of 

renewable generation. Commenters stated that CPP should take plant cycling and low load

operations into consideration when establishing heat rate and emission rate goals required by the 

rule.

Commenters stated that Building Block 1 is not achievable on a national basis because any gains 

in efficiency implementing Building Block 1 will be significantly impacted by efficiency 

decreases at the same coal-fired EGUs caused by re-dispatch to NGCC in Building Block 2. 

Commenters stated that EPA does not account for the fact that the efficiency of the coal-fired 

units will decrease as their average loads and overall utilization is decreased due to 

implementation of Building Block 2. Commenters stated that NERC also highlights this issue in 

its report: 

As a result of Building Block 2, coal units will cycle more often; therefore, assumed heat rate 

improvements across the entire coal fleet are unlikely. While recognizing capacity effects in the 

regression analysis, the EPA did not evaluate the effects of lower-capacity factors resulting from 

the dispatching of natural gas generation before coal generation.

Commenters stated that EPA did not address the adverse impacts on coal-fired EGU heat rates 

when engaged in the flexible operations (cycling, load following, and extended low load periods) 

that would result from the implementation of EPA's proposed Building Blocks 2, 3, and 4. 

Commenters stated that vast majority of large coal-fired EGUs were originally designed for an 

optimal heat rate when base-loaded using a specific fuel and their efficient operation requires 

maintaining mass and energy balances between hot gases and water/steam flows and among 

different components at all times and across all loads while adapting to changing demand, all 

while firing what is becoming an increasingly variable fuel supply. Commenters stated that 

flexible operation reduces efficiency, increases heat rate variability, and reduces reliability 

through accelerated equipment wear and stress and additionally, an EGU's fixed losses and 

parasitic auxiliary power draws increase as a percentage of load as load decreases. Commenters 

stated that while the EPA acknowledges that coal-fired EGUs have higher heat rates (i.e. are less 

efficient) when operating as load following units and during periods of startup and shutdown, 

there is no indication that this fact was considered by the EPA as part of its Building Block 1 

BSER determination.

Commenters stated that in development of Building Block 1, the EPA has failed to recognize that 

coal-fired EGU heat rates will only degrade rather than improve as load variability increases and 

capacity factors are reduced due to the system interactive effects from the displacement of coalfired generation by dispatch of NGCC units, increased use of renewable power (likely an erratic 
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supply), and growth in end-use energy efficiencies as proposed under the EPA's Building Blocks 

2, 3, and 4. Commenters stated that the planned and forced retirements of the older and smaller 

coal-fired EGUs caused by the economic realities of numerous environmental regulations 

affecting coal-fired EGUs, including the EPA's Proposed Guidelines, will only result in the 

remaining large coal-fired EGUs shouldering an increasing burden of maintaining a variable load 

and these competing demands will eliminate any efficiency gains made through implementing 

HRIs and lead to worsening heat rate trends in general.

Commenters stated that EPA must change its building block 1 methodology to account for the 

negative impact on HRI from building blocks 2 and 3.

Commenters stated that EPA is proposing to increase the dispatch of existing NGCC units 

(building block 2) and require additional renewable energy (building block 3b) to reduce the use 

of coal-fired EGUs, however, reducing the capacity factor of Wisconsin's coal-fired EGUs will 

substantially degrade the fleet heat rate (i.e., decrease its efficiency), thereby offsetting any HRI 

improvement achieved by building block 1.

Commenters stated that to demonstrate this effect for Wisconsin, the potential degradation in 

heat rate was evaluated due to building blocks 2 and 3 by first assessing EGU operation in 2012. 

Commenters stated that for the vintage coal-fired EGUs expected to remain online through 2020, 

their analysis shows the average fleet capacity factor was 57% in 2012, yielding a total 

generation of 25,280 GWh. Commenters stated that individual EGU capacity factors ranged from 

20% to 81%. 

Commenters stated that increasing the NGCC fleet in Wisconsin to 70% capacity factor (done to 

comply with building block 2) results in approximately 7,206 GWh of generation. Commenters 

stated that removing this amount of generation from the coal-fired vintage EGU fleet reduces the 

coal-fired fleet capacity factor from 57% to 41% and in some cases, individual EGUs with 

capacity factors as high as 80% in 2012 fall to below 50%, and in several cases below 40%, due 

to this shift in generation.

Commenters stated that the real impact of building block 2 on EGU heat rates can be seen in 

Figure 1 (Average Heat Rate Trends and Capacity Utilization for Wisconsin Vintage Coal-fired 

EGUs). Commenters stated that this data clearly shows a strong relationship between a lower 

capacity factor and decreased heat rate for Wisconsin coal-fired EGUs. Commenters stated that 

when operating at close to 60% capacity factor, the fleet showed the highest efficiency

(approximately 10,250 btu/kWh). Commenters stated that when the fleet operated at a 43% 

capacity factor, the heat rate was 10,375 btu/kWh. Commenters stated that when the EGUs 

operated at only a 38% capacity factor for two months in 2012, the fleet heat rates were even 

worse (10,502 and 10,804 btu/kWh). Commenters stated that this shows that the 41% capacity 

factor resulting from building block 2 could degrade the fleet heat rate by as much as 5%.

Commenters stated that the 5% fleet-wide degradation more than offsets any efficiency 

improvement reasonably expected to occur under building block 1, therefore, EPA needs to 

adjust its building block 1 methodology to account for full interaction of the building blocks in 

setting BSER, such as allowing a bottom-up approach as previously described, or otherwise 
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ensuring any presumptive HRI percentage is calculated based on the offsetting nature of building 

blocks 2 and 3. 

Commenters stated that EPA's assessment that plant operational efficiency can be improved by 

4% is also incorrect and in point of fact, coal plant operations are likely to become less efficient 

across the nation. Commenters stated that the combination of change in dispatch to base load 

natural gas plants (BB #2) over coal plants and the increased penetration of variable renewable 

resources (BB #3) will actually decrease plant efficiency. Commenters stated that the majority of 

coal plants that are likely to remain operational in a post-utility Maximum Achievable 

Technology Standard (MATS) [sic] world are plants that are designed to operate at maximum 

efficiency as base load plants. Commenters stated that because EPA has structured a rule that 

largely switches the order of dispatch to base load natural gas plants and to cycle coal plants, this 

efficiency is lost. Commenters stated that coal plants will be forced to follow load throughout the 

day, increasingly operate at minimal load levels and cycle off and on more frequently. 

Commenters stated that each of these actions has a significant impact on the operational 

efficiency of the coal plant that will not only eliminate EPA's presumed 4% operational 

efficiency, but also more than offset it resulting in higher emissions rates for coal plants that 

continue to operate. Commenters stated that they also conclude, based on unit-specific plant 

analysis as well as based on an historic understanding of the impacts of plant efficiency at lower 

dispatch rates, that the 6% efficiency improvement is not "technically feasible" and therefore 

cannot be a component of the final Rule.

Commenters stated that increasing efficiency and heat rate improvement at part load is essential 

because a large portion of the coal fleet is now operating a significant amount of time at part 

load, and will likely continue to do so in the future. Commenters stated that coal plants face more 

competition as a result of low gas prices, increased renewable generation, and the anticipated 

impacts of regulation of carbon under Section 111(d) which makes operations in base load more 

infrequent, and increases the amount of cyclic and part load operation. Commenters stated 

that most steam turbine units were designed to be most efficient at or near full load conditions, 

and operations at part load reduce efficiency and increase heat rate and depending on the design 

of the turbine and boiler, and the extent of part load operation, they estimate that this could have 

an adverse impact on plant heat rate in the range of 2%-4%. Commenters stated that hardware, 

operational, and controls changes and retrofits can provide heat rate improvements at less than 

full load; however, the availability of these improvements depends substantially on the unit in 

question and for an example of the impact of part load operation on efficiency. Commenters 

included a chart titled “Performance of a hypothetical 300 MW Coal-Fired Plant with Average 

HR = 9,800”, which shows heat rate vs. megawatts, with a 30% efficiency loss at a minimum 

load compared to full load.

Commenters stated that it is reasonable to conclude that coal plant efficiency will actually 

decrease under the CPP due to EPA's planned changes in dispatch that will result in increased 

cycling of coal units not designed for this mode of operation. Commenters stated EPA's 

assessment that plant operational efficiency can be improved by 4% is also incorrect and in point 

of fact, coal plant operations are likely to become less efficient across the nation. Commenters 

stated the combination of change in dispatch to base load natural gas plants (BB #2) over coal 

plants and the increased penetration of variable renewable resources (BB #3) will actually 

decrease plant efficiency. Commenters stated the majority of coal plants that are likely to remain 
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operational in a post-utility MATS world are plants that are designed to operate at maximum 

efficiency as base load plants, and many of the coal plants have just recently completed or are in 

the process of completing the addition of emissions controls, where the controls will reduce net 

plant efficiency. Commenters stated because EPA has structured a rule that largely switches the 

order of dispatch to base load natural gas plants and to cycle coal plants, this efficiency is 

lost. Commenters stated coal plants will be forced to follow load throughout the day, 

increasingly operate at minimal load levels and cycle off and on more frequently. Commenters 

stated each of these actions has a significant impact on the operational efficiency of the coal 

plant that will not only eliminate EPA's presumed 4% operational efficiency but also more than 

offset it resulting in higher emissions rates for coal plants that continue to operate.

Commenters stated that EPA's building block 1 assumptions do not factor in the impacts that 

changes to dispatch preference and capacity factors will have on plant efficiency. Commenters 

stated that under building block 2, EPA assumes that natural gas combined cycle units will be 

dispatched at a higher priority; however, the proposal does not recognize that this lowered 

dispatch preference has the potential to reduce the efficiency of coal-fired plants, due to 

increased cycling of these units. 

Commenters stated that EPA ignores the effect on heat rate improvements of implementing the 

other Building Blocks, as well as the degradation of heat rate over time. Commenters stated that 

regarding the implementation of Building Blocks 2, 3 and 4, EPA fails to account for the fact 

that these efforts would cause coal-fired units to be retired or operated at lower capacity factors; 

heat rate increases (i.e., gets worse) when a unit operates at a lower capacity.

Commenters stated that EPA ignores the adverse effect on heat rate that implementing the other 

Building Blocks will have.

Commenters stated that cycling frequency as a result of dispatching can have a significant impact 

on plant-level efficiency, which is often dictated by independent system operators/regional 

transmission organizations (ISOs/RTOs) and not under the control of individual electric 

generation units (EGUs). Commenters stated heat rate variability is largely the result of frequent 

dispatch changes that call on EGUs to either increase or decrease their electricity output. 

Commenters stated that the intermittent nature of renewable energy sources such as wind and 

solar impacts the frequency with which EGUs are dispatched and as renewable energy 

generation grows, the cycling frequency of fossil-fired EGUs will likely increase, making it more 

difficult to control heat rate variability through best practices. Commenters stated that when 

establishing the building block 1 target in the final rule, EPA should consider the increase in 

renewable generation called for in the rule and its effect on heat rate variability.

Commenters stated that a detrimental impact to the coal-fired EGUs' heat rate is increased cyclic 

and part-load operation and that many boilers today already operate in a load-following mode for 

at least a portion of their operation. Commenters stated that based on experience with this recent 

phenomenon with their coal-fired fleet, that with an increase of non-dispatchable renewable 

energy connected to the electric grid, coupled with the re-dispatch scenario required under 

building block 2, coal-fired units have been, and will likely continue to be, operated at reduced 

loads. Commenters stated that cyclic and part-load operation of coal-fired plants has a negative 

effect on unit efficiency, resulting in yet another offset to any potential efficiency gains to heat 
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rate improvement projects. Commenters stated that a typical pulverized coal plant will 

experience an increase in net plant heat rate of 6-10 percent when the load is decreased to 50-60 

percent of maximum plant output. Commenters presented a plot, Figure 1 (titled: “Percent Heat 

Rate vs. Percent Load for a generic pulverized coal plant”), showing the typical impact to 

efficiency when boilers are operated at reduced loads.

Commenters stated that EPA also overlooked the negative impact that operating at partial load 

may have on a unit's heat rate. Commenters stated that elsewhere in the rulemaking, EPA 

acknowledges that EGUs have higher heat rates (and thus higher CO2 emission rates) when 

operating as load-following units and during periods of startup and shutdown. Commenters 

stated that likewise, in its proposed NSPS rulemaking for modified and reconstructed EGUs, the 

Agency recognizes that operating at 50 percent load increases the heat rate of subcritical coalfired units by 10 percent. Commenters stated that efficiency decreases even more dramatically at 

lower capacity factors, yet EPA does not account for this factor at all in developing its proposed 

emission guidelines, instead assuming that a unit's heat rate is independent from its utilization. 

Commenters stated that this omission is particularly egregious, given that the remaining portions 

of EPA's proposed BSER are premised on reducing the capacity factor of existing EGUs well 

below their historical levels. Commenters stated that in particular, Building Block 2 reflects redispatch of generation from existing coal-fired EGUs to existing NGCC units, which will result 

in more coal-fired EGUs being dispatched as load-following units with low annual capacity 

factors instead of providing baseload at high capacity factors. Commenters stated that in many 

cases, coal-fired EGUs will be forced to operate at significantly lower capacity factors (if not 

forced to retire altogether), thus, the changes in coal-fired EGU utilization contemplated under 

Building Block 2 will most likely reduce or eliminate any gains in efficiency achieved through 

Building Block 1.

Commenters stated that EPA has overlooked the fact that coal-fired EGUs will be dispatched and 

operated much differently under the Proposed Rule than in the past. Commenters stated that this 

change in dispatch and operation means that the feasibility and benefits of any potential heat rate 

improvement must be evaluated more in context with future operations that may not afford the 

same magnitude of improvement potential.

Commenters stated that as a general matter, potential heat rate improvements are impacted by 

many variables that are both within and beyond the control of EGU owners and operators. 

Commenters stated that an analogy to simplify this point is the decision to replace the air filter in 

your car, which is known to improve fuel efficiency, typically at higher vehicle speeds, however, 

if the highway by which you commute to work is suddenly closed and you are rerouted through 

busy city streets, any fuel efficiency improvement from new air filter might go unseen. 

Commenters stated that similarly, if improvements are made to components or systems within 

the coal-fired power plant, but then the unit is cycled more frequently to balance intermittent 

loads from new wind and solar generation, the heat rate improvements may never be fully 

realized. Commenters stated that in fact, depending upon the situation, the unit's average heat 

rate might actually deteriorate. Commenters stated that it is well established that operating in a 

full-load steady-state condition versus cycling loads up and down, or running at minimum loads 

for which the unit was not optimally designed have a negative impact on heat rate, reducing the 

kilowatt-hours out for every Btu that goes in. Commenters stated that the relationship of unit 
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load to heat rate is shown for a typical unit in a graph of Heat Rate Change (Relative to Full 

Load) vs. Load.

Commenters stated that the EPA's building block 2 assumes that NGCC units can be dispatched 

to a 70% capacity factor. Commenters stated that to "make room" for this additional generation, 

existing coal-fueled EGUs will be dispatched down at a lower annual capacity factor. 

Commenters stated that in the modeling for Michigan, for example, coal-fueled units within the 

State are reduced from 50% to 39% under the Clean Power Plan. Commenters stated that this 

represents a 23% decrease in unit loading. Commenters stated that an estimated impact of this 

generation shift was prepared for DTE's existing units based on the latest PROMOD model of 

unit by unit generation over the next five years. Commenters stated that to simplify the analysis, 

DTE assumed that a unit would operate at its average loading for the entire period, and in the 

change case (representing decreased dispatch if forced lower by increased NGCC generation) it 

would operate at a generating level 23% lower. (Included here is a graph of the Typical Average 

Heat Rate Curve). Commenters stated that in this example, the unit is economically being 

dispatched at a 69% capacity factor and if re-dispatch due to NGCC generation lowers the 

average generation by 23%, the unit will operate at a 53% capacity factor. Commenters stated 

that lowering a unit's average loading will move it to a less efficient operating point on the 

average heat rate curve. Commenters stated that in the example above, this decreased loading 

would result in a 4.5% increase in heat rate; this is typical for the units examined in the modeling 

analysis. Commenters stated that the actual impact would be dependent on actual loading 

patterns and may be slightly less than this, but this analysis points out the fact that the building 

blocks must be evaluated in total, not independently. Commenters stated that if the goal of 

building block 1 is to improve heat rate by 6%, a hurdle imposed by building block 2 increases 

this 6% to somewhere in the neighborhood of 10% or more.

Commenters stated that in the context of the Clean Power Plan, EPA has failed to address the 

interaction of block 1's heat rate improvements with block 2's re-dispatch to natural gas and 

block 3's increased deployment of renewable and nuclear energy. Commenters stated that as 

noted above, the most significant heat rate improvements naturally occur when units are able to 

operate as close as possible to their rated capacity at steady state; however, the implementation 

of blocks 2, 3, and 4 would decrease the average capacity factor of coal-fired steam EGUs, 

forcing them to run at lower levels. Commenters stated that furthermore, the increased use of RE 

will clearly result in the coal-fired generation cycling loads up and down in order to balance 

intermittent loads from new wind and solar generation. Commenters stated that EPA has failed to 

factor in the adverse impacts of these conditions on the heat rates of existing coal-fired units in 

setting proposed efficiency improvements that are realistically achievable by coal-fired EGUs 

under building block 1. 

Commenters stated that building block 2 is based on dispatching existing NGCC's up to a 70 

percent Capacity Factor and to "make room" for this additional generation, existing coal units 

will be dispatched downward. Commenters stated that in EPA's modeling, the capacity factor of 

coal units in Michigan are reduced from 50 percent to 39 percent and this represents a 23 percent 

decrease in unit loading. Commenters stated that to estimate the impact of this downward 

dispatch on their existing units, they looked at their latest PROMOD forecast model of unit by 

unit generation over the next five years. Commenters stated that to simplify the analysis they

assumed that a unit would operate at its average loading for the entire period, and in the change 
285

case (representing decreased dispatch if forced lower by increased NGCC generation) it would 

operate at a generating level 23 percent lower. Commenters provided an example where the unit 

is economically being dispatched at a 69 percent capacity factor and if re-dispatch due to NGCC 

generation lowers the average generation by 23 percent, the unit will operate at a 53 percent 

Capacity Factor. Commenters stated that again, lowering a unit's average loading will move it to 

a less efficient operating point on the average heat rate curve. Commenters stated that in this 

example this decreased loading would result in a 4.5 percent increase in heat rate which is typical 

for the units looked at. Commenters stated that the actual impact would be dependent on actual 

loading patterns and may be slightly less than this, but this analysis points out the fact that the 

building blocks must be evaluated in total, not independently. Commenters stated that if the goal 

of building block 1 is to improve heat rate by 6 percent, the hurdle imposed by building block 2 

increases this 6 percent to somewhere in the neighborhood of 10 to 10.5 percent. 

Commenters stated that technical heat rate improvements will not achieve their intended 

emission reduction effects if the EGUs are operated inefficiently to address grid reliability and 

integration needs. Commenters stated a specific BSER requirement to evaluate and address 

integration and reliability issues without operating EGUs in an inefficient manner is essential to 

capturing the potential emissions benefit of technical heat rate improvements at EGUs.

Commenters stated that the Supplemental Proposal further make any assumption of a flat heat 

rate untenable, specifically, EPA has not considered how the change in how the plant would be 

dispatched would impact any potential heat rate improvements. Commenters stated that their 

plant was meant to operate as base load capacity, and performance at coal-fired power plants is 

optimized when facilities are operated continuously at full capacity to provide baseload power, 

thus, if they were to operate at less than full capacity, as they would be required to do under 

EPA's proposal, they are less efficient and produce more emissions per unit of electricity. 

Commenters stated that reducing operations at their plant and dispatching Puerto Rico's natural 

gas fired combined cycle ("NGCC") units at 70% capacity factor ("CF"), would necessarily 

significantly reduce the CF at their plant. Commenters stated that the reduced output and 

resulting cycling of their facility would be expected to offset if not exceed any theoretical 

improvements in heat rate.

Commenters stated that EPA fails to consider that, as it forces re-dispatch to NGCC and 

renewables through building block 2, it will make these heat rate improvements even more 

unachievable, because operating coal plants at reduced loads will decrease their overall 

efficiency, as shown in Figure 8. Commenters stated that S&L also explains, "[i]n some cases, 

any [heat rate] improvements achieved by undertaking the relevant options described in S&L's 

2009 Report could, in some cases, be negated by [heat rate] losses associated with loadcycling," 

as EPA projects under its proposal. Commenters stated that indeed, EPA's own assessment 

demonstrates this reality. Commenters provided a Figure showing Generic Pulverized Coal Net 

Heat Rate vs. Percent Load. 

Commenters stated that Building Block 1 strives to improve the thermal efficiency of each coalfired power plant by an average of six percent, however, EPA's analysis did not account for 

variations in plant design, the size or age of each plant and fuel variability. Commenters stated 

that coal units are typically designed to run as continuous baseload power generators and as a 

result of the second building block, coal units would run less often but would be forced to 
286

constantly - and inefficiently - cycle up and down to meet demand. Commenters stated that this 

cycling would make EPA's expected heat rate improvements extremely unlikely to achieve and 

furthermore, since many coal units have already been modernized within the last several years in 

order to increase efficiency in compliance with other environmental regulations, the current 

technology and the law of diminishing returns will likely prevent considerable number of these 

units from achieving significantly more efficiency.

Commenters stated that a technical challenge not accounted for under U.S. EPA's approach, yet 

specifically requested for comment, is "the quantitative impacts on the net heat rates of coal-fired 

steam EGUs of operation at loads less than the rated maximum unit loads". Commenters stated 

that they understand that implementation of the proposed rule would likely change the historical 

dispatch of coal-fired units, which have historically been designed to operate most efficiently at 

peak or near peak load conditions. Commenters stated that this raises significant concerns that 

even if a 6% HRI could be achieved, changing dispatch conditions could counteract such 

measures. Commenters stated that when it is considered that Building Block 2 calls for the redispatch of natural gas units to 70% on a very short timetable, considerable changes to the 

historic dispatch patterns of coal would need to occur on a very compressed time table, as well 

and this will certainly impact the heat rates of coal-fired units. Commenters stated that an 

analysis of eGRID and EIA data demonstrate that coal-fired units operate at an average capacity 

of 52%, with many of the larger units operating between 70 and 80%. 

Commenters stated that similarly, EPA's evaluation of heat rate improvements did not take into 

consideration the load profile of coal-fired units. Commenters stated that load profile is an 

important variable, as boilers are designed to achieve their highest efficiency at full load and 

their efficiency decreases with decreasing loads and with frequent load changes. Commenters 

stated that EPA attempted to account for certain factors that affect boiler heat rate in its statistical 

analysis of heat rate data, including ambient temperatures and unit startups and shutdowns; 

however, EPA's heat rate evaluation did not take into consideration load changes or load profile.

Commenters stated that EPA's second, third, and fourth building blocks will likely result in coalfired units cycling more frequently and running more frequently at lower loads and although 

EPA acknowledged that "[o]perating an EGU as a baseload unit is more efficient than operating 

an EGU as a load following unit to respond to fluctuations in customer electricity demand," EPA 

did not account for decreased dispatch or load profile changes in its heat rate improvement 

evaluation or economic analysis.

Commenters stated that the 2009 S&L Report did not analyze the impacts of load cycling on HRI 

method performance, however, if an existing base-load EGU changes to a load-following profile 

in the future, that unit's annual average heat rate will increase, and HRI methods implemented at 

the unit may not off-set heat rate increases due to load-cycling, and in fact, HRI improvements 

could be negated by HRI losses associated with load-cycling.

Commenters stated that EPA has not sufficiently accounted for equipment performance 

evaluated over long periods with increased load cycling, especially given the potential impact of 

building blocks No. 2, No. 3, and No. 4 and by excluding the impacts of shifting load production 

away from coal-fired power, EPA has overestimated the efficiency improvements that can be 

achieved and sustained, and has underestimated the economic impact of potential HRI gains. 
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Commenters stated that Building block #1 incorrectly assumes that upgrade and operational 

improvements are widely available and that implementation of BB 2, 3 & 4 will not lower 

efficiency. Commenters stated that competitive markets such as MISO have already forced coalfired generators such as their plant to adopt state-of-the-art technologies available and enhance 

operations and maintenance to improve thermal efficiencies in order to compete effectively.

Commenters stated that they had an Energy Assessment performed in 2007 to assess how to 

achieve heat rate improvements to Dallman units 31, 32 and 33. Commenters stated that while 

yet another energy assessment of their four (4) Dallman units may identify a fractional 

percentage improvement capability, achieving 6% heat rate improvement is unrealistic, and in 

fact, based on EPA's expectation that coal plants will, by 2020, operate in the dispatch queue 

after CCNG plants, a more rational assessment is that coal plant operational efficiency will 

decrease as plants designed to operate most efficiently at high capacity factors are instead 

relegated to an inefficient role of load following. 

Commenters stated that while the USEPA apparently relied upon a Sargent & Lundy (S&L) 

study in developing the 6% improvement rate, the USEPA's interpretation of the study 

apparently failed to consider the realities of the energy markets, which enable for-profit utilities 

to profit by achieving maximum efficiencies. Commenters stated that testimony of industry 

representatives from NRG Energy and Dynegy, whose fleets represent 76.3% of coal capacity in 

Illinois at the ICC's policy session addressing building blocks #1 (and #2) affirm that 6% heat 

rate improvement is unrealistic and unachievable. Commenters stated that the USEPA's GHG 

Rule therefore fails to recognize how security constrained economic dispatch works in organized 

wholesale markets. Commenters stated that Section 111(d) should not be used by the USEPA to 

disrupt existing wholesale markets that protect the grid and provide energy security to this 

country and while the USEPA's regulatory authority is broad, "it must be exercised with caution 

and is not entitled to boundless discretion." [See, Utility Air Regulatory Group v. EPA, 573 U.S. 

(2014)].

Commenters stated that a coal-fired power plant's heat rate is highly dependent on the load at 

which the power plant is dispatched and as the dispatch level of NGCC units increases under 

Building Block 2, the level at which coal-fired units will be called on to operate will decrease. 

Commenters stated for a typical 600-MW coal-fired plant, decreasing its operating level from 

100 percent to 60 percent would result in its heat rate increasing by 6 percent, essentially 

eliminating any heat rate improvements. 

Commenters stated that EPA also ignores the effect of implementing the other Building Blocks, 

as well as the degradation of heat rate over time. Commenters stated that regarding 

implementation of Building Blocks 2, 3 and 4, EPA fails to account for the fact that these efforts 

would cause coal units such as those at SGS to be operated at lower capacity factors; heat rate 

increases (i.e., gets worse) when a unit operates at a lower capacity. Commenters stated that 

accordingly, this worsening of the heat rate negates any improvements resulting from heat rate 

improvement projects. Commenters stated that moreover, EPA projects that both SGS units will 

be retired as a result of the rule, and thus any heat rate improvement projects are moot. 

Commenters stated that Building block 1 is unachievable because it is antithetical to EPA's 

proposed building blocks 2, 3, and 4. Commenters stated that in building block 2, EPA 

recommends re-dispatching energy production from coal-fired power plants to natural gas 
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combined cycle plants. Commenters stated that EPA's proposed building block 3 increases 

renewable energy but reduces demand from coal-fired power plants. Commenters stated that 

EPA's proposed building block 4 recommends reducing energy production from the power sector 

by reducing the demand side use of energy. Commenters stated that all three building blocks 

require reducing the use of South Dakota's only coal-fired power plant, the Big Stone Plant. 

Commenters stated that the Big Stone Plant was designed to operate at high capacity factors (i.e., 

70 to 90 percent plus). Commenters stated that the lower the load, the less efficiently the unit 

operates and the more air pollutants it will emit. Commenters stated that there is approximately a 

10 percent difference in the Big Stone Plant's heat rate between operating at its designed 

operating capacity versus operating at its minimum operating capacity.

Commenters stated that EPA established the 6 percent potential increase in heat rate efficiency in 

building block 1 based on coal-fired power plants operating at high capacities. Commenters 

stated that the EPA identified in the Greenhouse Gas Abatement Measures Technical Support 

Document that a coal plant operating at reduced capacity would adversely impact the plant's heat 

rate. Commenters stated that given this, if the other building blocks require coal-fired power 

plants to reduce production and decrease operational efficiency by 10 percent or more, the 6 

percent heat rate improvement will not be technically achievable. 

Commenters stated that if EPA believes a coal-fired power plant can operate at full capacity, at 

the most efficient heat rates, for shorter durations in order to meet generation reductions in the 

coal fleet required by the other building blocks, EPA is mistaken. Commenters stated that the 

only feasible scenario for this would be to operate coal-fired power plants to supply electricity 

for intermediate and peaking loads. Commenters stated that natural gas combined cycle plants 

were designed to ramp up quickly and operate for a few hours a day to meet intermediate and 

peaking loads, however, because they have longer startup times, coal-fired power plants do not 

have the ramping capability required to respond to real time changes in wind generation due to 

weather. 

Commenters stated that in general, heat rate improvement opportunities are dependent on the 

original design of the unit; for example, a sub-critical pressure coal fired Rankine cycle plant will 

not be able to achieve the efficiency of a natural gas combined cycle plant because of inherent 

physical design considerations and heat rate and the impact of heat rate improvements will vary 

along the load curve for each generation unit. Commenters stated that production at partial loads 

requires the majority of plant equipment to operate below design, or most efficient levels. 

Commenters stated that improvements that result in reducing heat rate at a high load point may 

result in marginal improvement or higher heat rates at a lower load point, thus, the average heat 

rate improvement will be less than the heat rate reported at the high load point depending on the 

units' capacity factors. 

Commenters stated that EPA's analysis failed to consider unit operational changes that have 

occurred and will occur if the CPP is implemented as proposed. Commenters stated that many 

coal-fired units have gone from being base-loaded to load-following or cycling units, based on 

market/economic conditions or other factors and as such, the heat rate of a unit can change 

significantly, reflecting these operational changes. Commenters stated that a 2011 EPRI 

report outlined the effects of cycling on heat rate and studied a 700 MW coal-fired unit which 

ran base-loaded (usually operated at net loads at or above 650 MW) from January to August of 
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2008, and from August through the end of 2008, the unit was cycled frequently to follow the 

demand for generation. Commenters stated that average net unit heat rate during the months 

when the unit was cycled increased by 2.3%. Commenters stated that the unit continued to cycle 

with generation demand through 2010, and over the operating period from 2008-2010 the plant 

initiated programs to target heat rate improvement. Commenters stated that EPRI performed an 

initial assessment of the plant's "heat rate culture" and found that many of the heat rate best 

practices were already in place at the plant. Commenters stated that on the basis of the EPRI 

assessment, the plant took additional actions which included:

• Formation of heat rate teams to brainstorm heat rate improvement ideas and 

monitor performance;

• Implemented daily, weekly and monthly reporting of key performance indicators;

• Offered refresher training to operators on heat rate awareness;

• Completed routine equipment and site walk-downs targeting equipment and 

component maintenance and cleanliness;

• Improved management of excess air on the unit; and

• Improved coal sampling techniques.

Commenters stated that average net unit heat rates in 2009 and 2010 were only about 1% above 

the average heat rate for when the unit operated as a base-loaded unit. Commenters stated that 

however, this is a good example of how implementation of best-practices and diligent attention 

to improving heat rate could not overcome the 2.3% heat rate increase brought about by 

increased cycling of the unit.

Commenters stated that the operating duty of a generating unit - the amount of time spent at 

various loads over the course of a year - affects thermal efficiency. Commenters stated that the 

reasons are many but most important for gross heat rate is the reduction in steam pressure and 

temperature compared to full-load duty, and the resulting loss in ability to extract energy in the 

turbine. Commenters stated that further, boiler thermal efficiency is typically penalized as the 

airflow is increased (e.g., higher excess air concentration) to maintain optimal conditions at the 

burner. Commenters stated that the penalty to heat rate on a net basis can be even greater. 

Commenters stated that operating at part load requires turning down the operation of pulverizers, 

fans, and boiler feed pumps to match the throughput of the boiler and steam turbine; 

conventional controls typically cannot provide a continuously proportional step-down in 

operation. Commenters stated that there are additional impacts of part load operation. 

Commenters stated these include having to take feedwater heaters out of service, transferring 

"feedpump" turbine steam to higher pressure sources, etc. 

Commenters stated that the mandate to maintain minimum gas flows through equipment for 

safety and operating stability adds a heat rate penalty. Commenters stated that EPA is aware that 

heat rate penalty increases at part load operation. Commenters stated that EPA's TSD addressing 

Reconstructed Steam Generating Units contained a notable reference from an International 
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Energy Agency publication depicting the heat rate penalty due to low load operation. 

Commenters stated that EPA cites this figure and concedes "operating a base load unit is more 

efficient than operating an EGU as a load cycling unit at a lower duty cycle to respond to 

fluctuations in customer electricity demand". Commenters stated that in fact, EPA background 

information acknowledges this trend, noting the number of units operating at the highest "bins" 

of capacity factor has decreased in recent years.

Commenters stated that despite this concession, EPA does not consider this operating 

characteristic in developing its strategy. Commenters stated that the heat rate penalties are not 

theoretical but actual detriments to operation incurred by power plants, particularly those 

equipped with state-of-art environmental controls.

Commenters stated that coal-fired units provide their best heat rates and highest efficiency of 

energy conversion at full load and in an unconstrained economic dispatch, the lowest cost units 

dispatch in order from lowest cost best efficiency to highest cost lowest efficiency of conversion 

of coal fuel to electricity. Commenters stated that having said this, coal-fired units not running at 

full load or less than full load degrade in heat rate based on their unit specific heat rate 

conversion curves and for coal-fired units to achieve their best heat rates, the units must be 

dispatched at full load or near full load into the market. 

Commenters stated that forcing gas-fired units into the bulk power market may push lower cost, 

higher heat rate coal-fired units out of their best efficiency points of operation to make room for 

natural gas-fired units to operate, negating heat rate improvements and operating units at their 

highest megawatt rating is the most efficient point of operation. Commenters stated that forcing 

gas-fired units into the bulk electric market is perverse to economic dispatch and drives up heat 

rates and cost. 

Commenters stated that the highest net benefits of heat rate improvements are achieved near or at 

full load and the aggregate effect of heat rate improvements depends on where the unit operates 

on the energy conversion curve (or heat rate curve). Commenters stated that if the unit operates 

at less than full load, for every megawatt created there is less of an effect of the heat rate 

improvement and utilities investing in heat rate improvement projects need to operate close to 

full load in order to meet the capital investment expectations of improved performance. 

Commenters further stated that in addition to overestimating the amount of plant efficiency 

available, costs notwithstanding, the proposed rule contemplates adding more generation from 

non-coal sources and in order to meet the proposed emission rate targets this new, non-coal, 

generation displaces existing coal fired generation. Commenters stated that displacing existing 

coal generation will reduce overall coal plant capacity factors and diminish heat rate 

improvement effective gains. Commenters stated that coal plants were designed to achieve 

greatest efficiency when producing high output around the clock and the goal of improving plant 

efficiencies but at the same time shifting away from high capacity factors is perverse and 

contradictory.

Commenters further stated trends in heat rate vs. load for these units are examined despite 

concerns for the suitability of the CEMS data from which the heat rate trends are inferred and 

pointed to Table 2-1 (titled: “Increase in Heat Rate at 50% Load (Compared to Full-Load 

Value)” presenting the heat rate penalty due to operating at half load for these units. Commenters 
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stated that the results show the plant heat rate penalty (gross basis) incurred at 50% load is 7% 

for subcritical boilers and 9% for supercritical boilers. Commenters further stated that the results 

in Table 2-1 show for two very different classes of units that any possible gains in heat rate as 

determined for full-load operation are on average more than offset by penalties for low load 

operation. 

Commenters stated that load-related heat rate impacts at TSPP prevent running at optimal 

conditions that would result in a lower heat rate. Commenters stated that TSPP operates under a 

Power Purchase and Sale Agreement with NV Energy, whereby power is sold into the grid and 

purchased back at several Newmont mine sites in northern Nevada and the facility output level is 

determined from NV Energy daily load schedules, which typically require TSPP to reduce 

generation output during the evening hours and operate at higher output levels during the 

daytime. Commenters stated that the daily swings in output levels have a significant impact on 

heat rate, with much higher heat rate experienced at lower output levels, when plant efficiencies 

are greatly diminished. Commenters stated that for example, in 2012, a year with 7,621 operating 

hours at TSPP output levels varied between the lowest sustainable operating levels and the 

highest design output levels, a variation between 80 MW and approximately 220 MW. 

Commenters stated that to evaluate these data, output level for the year has been classified into 

three output bins, representing low, mid and high output levels for the facility and provided a 

table (Table 4) that shows the 2012 Output vs. Heat rate at low, medium and high level. 

Commenters stated that the variation in heat rate between the high and low loads is 1,949 

Btu/KWh, with low load heat rates approximately 20% higher and since the plant output level at 

TSPP is determined by outside parties, TSPP is not able to realize improvement in this output 

level-related component of heat rate. Commenters stated that at TSPP, a significant year-to-year 

variation in heat rate can occur solely as the result of output scheduling.

Commenters stated that EPA's proposal states that displacing existing coal-fired and oil/gas-fired 

steam generation by increasing generation from existing NGCC capacity under Building Block 

Two, see 79 Fed. Reg. at 34,862, would lead to increased cycling of coal-fired EGUs, resulting 

in higher heat rates. 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 load-following and cycling of coal-fired 

EGUs reduces their efficiency, thereby increasing heat rates. Commenters stated that 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 and that at low load points, many plant components operate below their most 

efficient design points. Commenters stated that heat rate decreases (i.e., improves) in a nonlinear fashion as the load increases until it reaches an optimal load point and the heat rate may 

then increase slightly as load approaches the maximum capability of the unit. Commenters stated 

that the heat rate at the lowest load can be 15 percent to 20 percent higher than at the optimum 

load point - for example, the minimum load heat rate for one their member’s unit is 

approximately 10 percent higher than the unit's full load heat rate. Commenters pointed to a table 

that shows a representative curve of heat rate relative to load (Table 1: Heat Rate Penalty at 

Reduced Dispatch for a typical 600-MW Coal-fired Unit). Commenters stated that extra energy 

is required to shift a unit from low to higher loads to overcome inertia in the system and 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; thus, the unit will be less efficient on average. Commenters 
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pointed to a table that shows the average heat rate for varying load scenarios at one of their

member's coal-fired EGU, demonstrating the impact of lower load operations on heat rate (Table 

2: Average Heat Rate at Varying Loads).

Commenters stated that EPA's purely statistical approach is not validated with actual case studies 

of base-load EGUs that already employ such best practices to reduce heat rate variability. 

Commenters stated that without any real-world validation, EPA's statistical approach cannot be 

considered to be "adequately demonstrated." Commenters stated that from 2015 on, all 

remaining coal-fired units in West Virginia will be base-load units, as all load-following units 

will have been retired and that these EGUs minimize heat rate variation due to changes in load, 

because they are designed as base-load units, and therefore are operating at design load with 

peak efficiencies on a nearly constant basis.

Commenters stated that, similarly, EPA's evaluation of heat rate improvements did not take into 

consideration the load profile of coal-fired units. Commenters stated that the load profile is an 

important variable, as boilers are designed to achieve their highest efficiency at full load and 

their efficiency decreases with decreasing loads and with frequent load changes. Commenters 

stated that EPA attempted to account for certain factors that affect boiler heat rate in its statistical 

analysis of heat rate data, including ambient temperatures and unit startups and shutdowns; 

however, EPA's heat rate evaluation did not take into consideration load changes or load profile

Commenters stated that in addition, the redispatching would cause capacity factors for coal-fired 

units to decrease significantly. Commenters stated that decreases in capacity factors cause a 

direct increase in heat rate (i.e. the heat rate gets worse), plants are designed to operate most 

efficiently at full capacity and imposing lower capacity factors due to redispatch makes coal 

plants run less efficiently, which makes achievement of the Building Block #1 targets all the 

more unrealistic. 

Commenters stated that EPA also expressly recognizes its Proposed Rule Building Block 2 -

increased natural gas generation - will displace coal-fueled EGUs: "The electric system's carbon 

intensity can be lowered through re-dispatch among existing EGUs, particularly by shifting 

generation from coal- fired units to natural gas combined cycle (NGCC) units." Commenters 

stated that EPA fails to recognize that shifting generation from coal to gas will reduce coal unit 

capacity factors and therefore increase coal unit heat rates, thereby undermining EPA's stated 

goal of improving coal unit efficiency and in addition, the practical reality is that Building 

Blocks 3 and 4 will also necessarily displace coal- fueled generation, further reducing coal unit 

capacity factors and increasing their heat rates. Commenters stated that since coal-fueled EGUs 

are the most carbon intensive generation, the overwhelming likelihood is that coal-fueled EGUs 

will be displaced and as a result, like Building Block 2, Building Blocks 3 and 4 will reduce coal 

unit capacity factors and increase coal unit heat rates. Commenters stated that the Proposed Rule 

notably fails to take this into account in its Building Block 1 calculations. 

Commenters stated that heat rate improvement assumes a unit operating at capacity to calculate 

the benefits of reduced emissions, however, building block 2 would lower the dispatch of the 

coal units targeted by building block 1. Commenters stated that less dispatch would erode the 

predicted reduction from the improvements. Commenters stated that the 6% estimate is even 

more unrealistic if other building blocks are implemented. Commenters stated that reductions 
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need to be evaluated on a case-by-case basis but, at best, the reductions available in Ohio are in 

the 1 % to 2% range. 

Commenters stated that because the generation and sale of electricity is a cost competitive 

business, most utilities (including their plants) already follow and implement operations and 

maintenance (O&M) "best practices" to achieve peak efficiency for their units. Commenters 

stated that as a result, achieving an incremental 6% HRI on top of that peak efficiency will be 

virtually impossible. (See, e.g., NERC Potential Reliability Impacts of EPA's Proposed Clean 

Power Plan at 8 (Nov.2014) ("NERC comments") ("Overall, improving the existing U.S. coal 

fleet's average heat rate by 6 percent may be difficult to achieve.")). Commenters stated that this 

task will actually become harder if building blocks 2, 3, and 4 are implemented because those 

building blocks force coal-fired EGUs to generate at less than their optimal full load, which 

serves to increase heat rate and reduce unit efficiency. (See NERC comments at 8 "As a result of 

Building Block 2, coal units will cycle more often; therefore, assumed heat rate improvements 

across the entire coal fleet are unlikely."). Commenters estimated that their plants could not 

remotely achieve the 6% HRI targeted by the EPA. Commenters stated that this conclusion rests 

in part on the facts that their EGUs, including Gentleman Station and Sheldon Station, do not 

have flue gas desulfurization ("FGD") or selective catalytic reduction ("SCR") equipment. 

Commenters stated that if they would have to add such equipment, any modest HRI gains 

realized through additional O&M best practices and hardware modifications would be negated 

by the increased parasitic loads presented by such equipment. (See NERC comments at 8 "These 

retrofits [FGD and SCR] will reduce the net output of these units, as well as their associated net 

heat rate efficiency."). Commenters stated that this is a reason to have the proposed guidelines be 

based on gross output, rather than on net energy output. 

Commenters stated that the EPA neither analyzed nor addressed the adverse heat rate impacts 

due to the additional cycling, increased load variability, and reduced load factors that would 

result from the displacement of coal-fired generation from Building Blocks 2, 3, & 4.

Commenters stated that EPA's analysis demonstrates that load factor is a very important 

determinant of heat rate for units with varying load. [See Abatement Measures TSD at 2-25.]

Commenters stated that load factor (capacity factor) has an inverse relationship with heat rate for 

fossil-based EGUs; the higher the load factor, the lower the heat rate. Commenters stated that 

lower capacity factors (CF) or increased cycling increase heat rates and increase heat rate 

variability. Commenters stated that in the integrated electric system, units are dispatched to 

respond to load and unit owners and operators, therefore, cannot control load factor to address 

concerns about heat rate. Commenters stated that in actual plant operation currently and 

increasingly in the future, RE supply needed to meet the calculations of the Proposed Rule will 

decrease the efficiency of the plants as fossil fuel plants will need to accommodate variable RE 

generation with load response. Commenters stated that the EPA should take the impact of 

additional RE and the resultant load swings into consideration when establishing heat rate goals 

as part of the state implementation plans. 

Commenters stated that while their units 31 and 32 may be smaller than the average unit, these 

units have APCs beyond most units their size and larger, for which the citizens of Springfield are 

still paying the debt service for these upgrades. Commenters stated that therefore, while many 

units under 100MW capacity will likely retire due to other air pollution regulations being 
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implemented, they have no plans to retire units 31 and 32 at this time since they have already 

invested to comply. Commenters stated that these units provide critical support for the 

intermittency of their wind farms, operating during peak loads when their wind farm outputs are 

near or at zero.

Commenters stated that their substantial investment in renewable energy and energy efficiency 

(EE) cannot be counted on during periods of peak demand for the utility. Commenters stated that 

they face summer and winter peak periods and showed a graph that overlays annual electric load 

against the availability of their renewable resources. Commenters presented a graph showing 

their On-Peak AVG Hourly Load vs. Hancock Wind Farm Hourly Capacity Factors and stated 

that as the graph demonstrates, during the summer, when average load peaks, wind resources 

average very low capacity factors and as result, they have continued to rely on their smaller coal 

units to fill the gap in the summer months when wind generation is not available.

Commenters stated that while renewables are an important component of the GHG rule to reduce 

carbon emissions, coal-fired units such as units 31 and 32 are necessary for reliability, especially 

in high load periods (summer and recent winter load), as their data demonstrates. Commenters 

stated that the benefit of these units to the community is outsized and their impact on GHG 

emissions is negligible. 

Commenters stated that under the CPP, coal facilities will be forced into load following 

operations to support grid reliability. Commenters stated that wind and solar power require 

supporting sources of power to scale up and down in response to power availability and this role 

is traditionally served by natural gas, which can cycle quickly and efficiently. Commenters stated 

that the CPP will force natural gas to occupy a stronger baseload power position, and will not be 

available to serve its reliability function. Commenters stated that instead, coal facilities will be 

called on to cycle, creating non-optimal operating conditions that will further reduce any positive 

impacts from heat rate improvement investments. 

Commenters stated in its CAA section 111(d) analysis, EPA mentions a number of heat rate 

improvements that are less efficient at part load. Commenters stated that they believe EPA 

should factor part load conditions into its evaluation, because the coal-fired generation fleet faces 

a number of future market conditions that will likely cause it to cycle and operate at part load 

more frequently. Commenters stated that these conditions include low natural gas prices, 

increasing renewables penetration, and limits on total carbon emitted from EGUs. Commenters 

stated that accounting for part load operations and cycling will lower estimates for technical, 

economic, and market potential for heat rate improvements. Commenters stated that most coalfired steam turbine units were designed to be most efficient at or near full load conditions, 

reflecting market conditions when these units were built. Commenters stated that if a solution 

were developed as a part of the final rule that allowed coal-fired power plants to operate at or 

near base load when economic to do so and avoid extended cycling, the overall emissions rate 

would likely be lower than if many of the heat rate improvements of Building Block 1 were 

implemented. 

Commenters stated that in addition to overestimating the amount of plant efficiency available, 

costs notwithstanding, the proposed rule contemplates adding more generation from non-coal 

sources and in order to meet the proposed emission rate targets, this new non-coal generation 
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displaces existing coal fired generation. Commenters stated that displacing existing coal 

generation will reduce overall coal plant capacity factors. Commenters stated that coal plants 

were designed to achieve greatest efficiency when producing high output around the clock. 

Commenters stated that the goal of improving plant efficiencies while shifting away from high 

capacity factors is contradictory. 

Commenters stated that an additional challenge also faces coal units given the CPP's proposed 

Building Block #2 dispatch of existing natural gas combined cycle (NGCC) units. Commenters 

stated that it is well known that all units have a heat rate curve and that decreased utilization 

leads to decreased efficiencies. Commenters stated that the specific heat rate impacts will occur 

on an individual unit basis, and it will not be possible to determine an accurate assessment of the 

overall impact of decreased utilization on a unit's heat rate until after strategies for the CPP have 

been implemented and new market conditions dictate the utilization of remaining units; thus, 

EPA must recognize that if Building Block #2 is implemented then it will be at odds with 

Building Block #1, and will likely increase heat rates (i.e. decrease efficiency) at remaining coal 

units. Commenters stated that a similar reduction of coal unit utilization is also possible due to 

Building Block #3 (renewable energy) and #4 (energy efficiency). 

Commenters stated that heat rate is significantly impacted by fuel quality, unit load, size, and 

rate and frequency of load changes and as more renewable sources are integrated into the grid, 

heat rate at units which change from base load to load following operation will increase. 

Commenters stated that the proposed rule does not address the interaction of block 1's heat rate 

improvements with block 2's re-dispatch to NGCC and block 3's increased deployment of RE 

and notably, achieving the best heat rate naturally occurs when unit operation is maintained as 

close as possible to its rated capacity. Commenters stated that the implementation of building 

blocks 2, 3, and 4 would decrease the average capacity factor of coal-fired EGUs resulting in less 

efficient operations causing heat rate to escalate and furthermore, the increased use of RE will 

clearly result in the coal-fired generation cycling loads up and down in order to balance

intermittent loads from new wind and solar generation. Commenters stated that they recommend 

that EPA factor in the offsetting impacts of these conditions on the heat rates of existing coalfired units in setting the efficiency improvements under building block 1. 

Commenters stated that during the operating cycle between major outages, the heat rates of 

baseload units will naturally deteriorate due to wear on components and fouling of heat 

exchangers and boilers. Commenters stated that in addition, as plant components age, their 

performance will decrease and require periodic replacements. Commenters stated that the 

Proposed Rule needs to recognize this and provide for the natural deterioration and periodic 

upgrades/replacements to allow a plant to recover these heat rates. Commenters stated that in 

addition, increased cycling of the baseload units, which will be the likely result of this Proposed 

Rule, will raise plant heat rates through sub-optimal operations and increased component 

degradation. Commenters stated that the final rule needs to recognize this fact and allow for 

these inevitable heat rate losses caused by increased cycling. 

Commenters stated that EPA's purely statistical approach is not validated with actual case studies 

of base-load EGUs that already employ such best practices to reduce heat rate variability. 

Commenters stated that without any real-world validation, EPA's statistical approach cannot be 

considered to be "adequately demonstrated." Commenters stated that from 2015 on, all 
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remaining coal-fired units in West Virginia will be base-load units, as all load-following units 

will have been retired and that these EGUs minimize heat rate variation due to changes in load, 

because they are designed as base-load units, and therefore are operating at design load with 

peak efficiencies on a nearly constant basis.

Commenters stated that the Agency did not consider the implications of a unit consistently 

operating at lower loads in the future as compared to its historical operations. Commenters stated 

that units are typically more efficient (i.e., have lower heat rates) at higher loading levels and that 

operating consistently at lower loads would therefore reduce any heat rate benefits realized from 

implementing operating and maintenance best practices. 

Commenters believed that EPA's first Building Block is unrealistic. Commenters stated that 

among the G&Ts serving Minnesota, individual generating facilities vary greatly in age, plant 

design, previous equipment upgrades and operational approaches, and the impact of the best 

practices and equipment upgrades is going to vary based on those differences. Commenters 

stated that most of the baseload plants owned by Minnesota G&Ts are more efficient when they 

are operated near full capacity and the sporadic dispatching that the proposed rule seems to push 

could be negated by more inefficient plant operation. 

Commenters stated that current constraints on operation of coal power plants can limit the ability 

of owners/operators to take full advantage of the benefits of specific HRIs. Commenters stated 

that some owners/operators of coal power plants face challenges in maintaining compliance with 

existing emissions requirements and operating their plants safely and reliably and these operating 

challenges are compounded by cyclic operation, due to increased penetration of renewables into 

the power market. Commenters stated that as a result of these challenges, it may be difficult for 

owners/operators to achieve the full potential of some of the identified HRIs, or it may create an 

impediment to the adoption of some HRIs. Commenters stated that this difficulty is further 

compounded if plants do not have the tools and training needed for minimizing heat rate in the 

context of other operating challenges. 

Commenters stated that EPA overlooked the negative impact that operating at partial load may 

have on a unit's heat rate. Commenters stated that elsewhere in the rulemaking, EPA 

acknowledges that EGUs have higher heat rates (and thus higher CO2 emission rates) when 

operating as load-following units and during periods of startup and shutdown. Commenters 

stated that likewise, in its proposed NSPS rulemaking for modified and reconstructed EGUs, the 

Agency recognizes that operating at 50 percent load increases the heat rate of subcritical coalfired units by 10 percent. Commenters stated that efficiency decreases even more dramatically at 

lower capacity factors, yet EPA does not account for this factor at all in developing its proposed 

emission guidelines, instead assuming that a unit's heat rate is independent from its utilization. 

Commenters stated that this omission is particularly egregious, given that the remaining portions 

of EPA's proposed BSER are premised on reducing the capacity factor of existing EGUs well 

below their historical levels; in particular, Building Block 2 reflects re-dispatch of generation 

from existing coal-fired EGUs to existing NGCC units, which will result in more coal-fired 

EGUs being dispatched as load-following units with low annual capacity factors instead of 

providing baseload at high capacity factors. Commenters stated that in many cases, coal-fired 

EGUs will be forced to operate at significantly lower capacity factors (if not forced to retire 
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altogether), thus, the changes in coal-fired EGU utilization contemplated under Building Block 2 

will most likely reduce or eliminate any gains in efficiency achieved through Building Block 1. 

Commenters stated that the drop in natural gas prices has impacted the operation of their coalfired EGUs (which are capable of co-firing natural gas as well) at Mercer and Hudson 

Generating Stations. Commenters stated that these units have been operating as load following 

units since 2005 with steady decreasing capacity factors due to the economic recession and low 

natural gas prices and in fact, these units have been operating on natural gas during the summer 

months due to the lower prices and high availability of gas. Commenters provided a table that 

includes the 2012 capacity factors for their coal units in New Jersey (Table 1). Commenters 

stated that EPA has indicated that there is considerable variability on heat rates for those coalfired units that typically operate as load following units. Commenters stated that their coal-fired 

units typically ramp up and down to different loads throughout the day. Commenters stated that 

they are not able to achieve steady-state operation at higher loads where heat rates are optimal 

due to this constant cycling. Commenters strongly recommended that if a state were to make a 

showing that the majority of in-state coal units operate as load following units, EPA must allow 

for adjustment of the heat rate improvement goal in Building Block 1 for that state. Commenters 

stated that as noted in Table 1, their coal-fired EGUs have capacity factors similar to peaking 

plants versus typical baseload power plants and therefore, the opportunities, as EPA has 

indicated, for heat rate improvements are greatly diminished. 

Commenters stated that Building Block 1 fails to account for the fact that reduced utilization of 

coal-fired EGUs (due to BBs 2, 3, & 4) will increase heat rates, undercutting the potential for 

heat rate improvements (HRI) assumed technically feasible in BB 1. Commenters asked how 

reduced utilization at these facilities factored into technical feasibility.

Commenters stated that a coal-fired power plant's operating load has perhaps an even larger 

impact on momentary heat rate at a given time point. Commenters stated that in general, heat rate 

exponentially increases as a function of decreased operating load with respect to the plant's 

maximum continuous rating (MCR). Commenters stated that such efficiency losses are 

particularly steeper for conventional subcritical units, which constitute the vast majority of the 

coal-fired power plant fleet. Commenters stated that despite the significant nonlinear effect of 

capacity factor on heat rate, EPA's statistical analysis erroneously attempted to determine the 

amount of achievable efficiency improvements by analyzing changes in heat rate, capacity factor 

and temperature among discrete hourly average data. Commenters stated that specifically, EPA 

sorted data based on average capacity factor over distinct hourly points into 168 "bins" based on 

corresponding hourly average heat rate and temperature data. Commenters stated that by using 

these discrete averages over disconnected hourly points, EPA's analysis fails to adequately 

account for dynamic trends in capacity factor that may account for the variability that EPA 

wrongly believes can be addressed through modifying operating practices. 

Commenters stated that EPA also discusses EGU output that increases due to "rebound effects" 

from improvements in heat rates at individual EGUs and mentions that this effect can be 

addressed by establishing BSER as a combination of approaches that will encourage reductions

in electricity demand. 79 Fed. Reg. at 34,859. Commenters stated that EPA's assumption that an 

EGU will spend money on a project that will improve heat rate and then plan to be utilized less is 

not realistic. Commenters stated that while EPA acknowledges that degradation in performance 
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is inevitable, that is not embedded in EPA's modeling, either in determining the cost and benefits 

of the rule, or in reasonably determining the achievability of sustaining the proposed state goals. 

Commenters asked EPA to explain how the "rebound effect" factors into the guidelines for heat 

rate improvements and how the phenomenon of heat rate degradation over time is accounted for 

in the proposed rule.

Commenters stated that EPA's building block 2 adds yet another barrier to achieving the 

assumptions EPA made in developing and applying building block 1. Commenters stated that as 

states attempt to meet EPA's building block 2 assumptions by "re-dispatching" natural gas units 

to displace coal generation, the capacity factors for coal-fired units will drop, and coal-fired units 

will likely increase the extent to which they follow changes in electricity demand. Commenters 

stated that the "re-dispatch" of coal units to natural gas units could also lead to more start-ups 

and shutdowns at coal-fired units. Commenters stated that as these changes occur, the efficiency 

rates of coal-fired units are expected to drop because "load-following" coal-fired units and those 

with lower capacity factors typically have much higher heat rates than those that operated near 

full capacity most of the time, and a coal-fired unit's heat rate is often at its highest during startup.

Commenters stated that the study recently conducted by NERC confirms that EPA's building 

block 2 may interfere with achievement of EPA's building block 1 assumptions, stating that "[a]s 

a result of Building Block 2, coal units will cycle more often; therefore, assumed heat rate 

improvements across the entire coal fleet are unlikely." Commenters stated that EPA readily 

admits these facts, but nevertheless fails to take these building block 2 impacts into account in 

developing its building block 1 assumptions. Commenters stated that EPA also fails to recognize 

that, at lower capacity factors, the possibility that heat rate improvements will be cost-effective is 

also much lower, since any efficiency improvements are the most valuable at units with high 

capacity factors.

Commenters stated that based on their experience, they believe that the reduced capacity factors, 

increased load-following, and increased start-ups expected under EPA's building block 2 

assumptions will more than offset the emission reduction benefits EPA claims to be achievable 

under building block 1. Commenters presented graphs illustrating the significant increase in heat 

rate (representing a degradation in efficiency) that occurs as operating load decreases at the four 

San Juan units. Commenters included scatter charts for Units 1-4 on page 29; these are plotting 

the heat rate (Btu/kWh) vs. Net MW. Commenters stated that applying a linear regress formula 

to this data reveals the percent increase in heat rate between the maximum and minimum load 

and included a table titled: "Percent Difference in Heat Rate from Maximum Load" for Units 1-

4, in where it provided the load, heat rate and percent difference from maximum load of each 

unit.

Commenters stated that these graphs and tables illustrate the significant impact that lower 

capacity factors will have on the heat rate of coal-fired generators as a result of EPA's building 

block 2 assumptions. Commenters stated that they confirm that EPA should not expect building 

block 1 and building block 2 to be additive, but rather a trade-off --as the expected re-dispatch to

natural gas increases, the efficiency of coal-fired units will decrease. Commenters stated that the 

same concern also applies equally to building blocks 3 and 4 as it does to building block 2--

although EPA does not expressly recognize that those building blocks will displace coal 
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generation, in reality they must, in order both to maintain the balance between the supply and 

demand of electricity. Commenters stated that however, EPA unrealistically assumes that any 

shortfall under one building block can be offset by greater efforts under the others, without 

recognizing that any greater efforts under building blocks 2, 3, and 4 will, in reality, degrade heat 

rate and reduce the benefits of building block 1. Commenters stated that EPA should re-evaluate 

its building block 1 assumptions to address this unavoidable trade-off and recognize that a six 

percent heat rate improvement is unachievable in New Mexico and across the country.

Commenters stated that the interaction among Building Blocks 1, 2 and 3 may serve to 

counteract heat rate improvements that can reasonably be achieved. Commenters stated that 

many renewable technologies, such as wind and solar, produce intermittent generation and to 

manage the variability and uncertainty inherent with intermittent renewable resources, system 

operators must have sufficient resources with operational flexibility held in reserve to quickly 

respond to fluctuations in load. Commenters stated that natural-gas fueled resources are designed 

to respond to changes in load more readily than coal-fueled resources, which operate most 

efficiently at or near full load and as coal-fueled units operate at lower loads to accommodate the 

generation shifts brought about by Building Blocks 2 and 3, their overall efficiency declines. 

Commenters stated that as a consequence, the heat rates of the coal-fueled generating assets will 

be negatively impacted.

Commenters stated that as a result of these factors and their experience with heat rate 

improvement opportunities, they estimate that less than a 1% improvement in the average fleetwide heat rate of their coal-fueled units may be economically practicable and/or technically 

feasible if all identified heat-rate improvement opportunities were ultimately implemented. 

Commenters recommended that EPA should adjust Building Block 1 to require no more than a 

1% heat rate improvement across the existing coal-fueled generating fleet. 

Commenters stated that the proposed rule impedes its own goal of heat rate reductions through 

improved economic dispatch. Commenters stated EPA posits that an additional 4% efficiency 

gain can be had through improving plant operations and measures such as greater reliance on 

dispatching the most efficient units first. Commenters stated that neither generation owners nor 

the states determine the dispatch order, amount of run time, or load level required for any 

particular unit. Commenters stated that those decisions are made by the ISO/RTO markets and if 

anything, this proposal would disrupt that market structure by substituting emission rate over 

efficiency as a primary dispatch criterion. 

Commenters stated that they would like to point out that, unlike most coal-fired units, RPS-2 has 

not been, and is not currently, fully base-loaded, and utilization by owners has varied 

significantly due to market conditions and other factors. Commenters stated that generating unit 

efficiency is impacted by both level of output and the number of start-ups experienced by the 

unit.

Commenters stated that EPA incorrectly assumes that coal-fired power plants will maintain a 

heat rate improvement of 6%. Commenters stated that cycling coal-fired power plants erodes 

heat rate improvements and increases CO2 emissions rates. Commenters stated that they are

already experiencing this at their merchant coal plants as a result of low gas prices and market 

dynamics. Commenters stated that by means of example, Pennsylvania's coal plants operated 
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14.7% less during 2012 than in 2005 at a CO2 emission rate that was approximately 13.5% 

greater and on average, Pennsylvania's coal plant heat rate rose by 10% as a result of the 

degradation and cycling discussed herein. 

Commenters stated that EPA's Proposed Rule will materially exacerbate this phenomenon. 

Commenters stated that load-following units experience much higher heat rates as is evident by 

their typical heat rate curves (e.g., the best heat rate is at the top end of a unit's output).

Commenters stated that cycling of coal power plants reduces their efficiency, thereby increasing 

their heat rate and equipment wear and tear. Commenters stated that coal-fired power plants are 

more efficient when run at steady, high capacities than when cycled at low capacities. 

Commenters stated that the increase in heat rate caused by cycling will likely offset any heat rate 

improvement from equipment upgrades and best operating practices that may be realized directly 

following commissioning. Commenters stated that EPA should recognize heat rate degradation 

and swings in this rulemaking. 

Commenters stated that there are a number of ways to look at heat rate. Commenters stated that 

EPA used the gross annual heat rate while EIA publishes the net annual heat rate. Commenters 

stated that EIA published in their "Annual Electric Generation Report" Table 8.2 that provided 

the average tested heat rate by prime movers. Commenters presented a table (titled: “Gross, Net, 

and Tested heat rate (btu/kWhr) with capacity factor %, 2002-2012”), showing the annual and as 

tested heat rates for coal plants.Commenters stated that it is obvious from the above data both the 

annual gross and net heat rates and the capacity factor have declined during this period while the 

tested heat rate has actually improved. Commenters asked why there is a difference. Commenters 

stated that the answer is clear when you look at the operating capacity for the same period of 

time. Commenters stated that there is a direct relationship in the decline of the heat rates as 

related to the capacity factor. Commenters stated that the average full load test heat rate 

improved over the period by roughly 0.50%. Commenters stated that despite an improvement in 

full load heat rate over the period, average annual heat rates deteriorated because of the decrease 

in capacity factor over the period.

Commenters stated that the estimated impact of capacity factor on average annual heat rate over 

those years can be obtained by subtracting the average full load test heat rate from the average 

annual heat rate for the fleet. Commenters stated that when you plot the results, you get a very 

strong correlation. Commenters stated that you expect the average annual heat rate to exceed the 

full load test heat rate. Commenters stated that this data demonstrates a clear trend of 

deteriorating heat rate relative to full load at lower capacity factors and presented a chart (Impact 

of capacity factor on average heat rate versus full load test heat rate).

Commenters stated that there are other correlations that show the impact that diminished 

capacity factor has on heat rate. Commenters presented a graph (titled: “Impact of capacity on 

heat rate”) that comes from an EIA database and shows heat rate as a function of kWhr./ton of 

coal used in power generation vs. capacity factor. Commenters stated that there is a very strong

relationship between capacity factor and efficiency. 

Commenters stated that the assumption of simply operating coal less is not necessarily efficient 

or practical. Commenters stated that unlike most NGCC units, coal units don't use the fuel to 
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operate the turbines that produce the electricity; rather, coal units use the coal to super-heat water 

to create steam which is then used to operate the turbines and produce electricity. Commenters 

stated that large conversions of water to steam cannot vary quickly throughout the day or "backoff" when a certain emissions limitation is reached. Commenters stated that this complex 

process requires planning a significant fuel to steam conversion, for a significant amount of 

power, for an extended period of time. Commenters stated that the complex process to bring the 

water to the appropriate level of steam for production is the same process whether the plant is to 

operate for the next 25 hours or the next 2500 hours. Commenters stated that the direction to 

simply operate a coal-fired plant less, means that the plant would incur the same costs, start-up 

time and wear and tear for less generation output as it would if it ran at full

capacity. Commenters stated that this means a higher cost to operate the plant and a less 

efficient use of the plant (i.e., a lower heat rate). 

Commenters stated that changes in dispatch may also adversely affect the ability of older coalfired plants to operate most efficiently. Commenters stated that historically, coal-fired generation 

was designed to operate optimally in a base load role. Commenters stated that with increased 

reliance on NGCC generation and renewable generation, those older coal plants still operating 

will be required to engage in more flexible operation such as performing load following, 

extended low output generation and cycling which can reduce plant efficiency and adversely 

impact heat rate performance. Commenters stated that this was demonstrated in a 2014 study 

produced by the Electric Power Research Institute (EPRI) "Range and Applicability of Heat Rate 

Improvements" to determine the extent of the efficiency losses associated with increased load 

following. Commenters stated that the report confirmed a substantial loss in heat rate and 

identified the areas in the plant that suffered with the decreased load stability. Commenters stated 

that based on those results, the coal units remaining in service that are no longer base loaded will 

therefore experience higher (and poorer) heat rates.

Commenters stated that PADEP has estimated that PA-based coal-fired units will be forced to 

operate at less than 20% capacity to meet proposed targets. Commenters stated that PADEP also 

contends that coal-fired units are more efficient when operated close to design loads. 

Commenters stated that thermal efficiency decreases when operated at loads less than 60% 

which increases the level of emissions per unit of electricity. 

Commenters stated that besides significantly underestimating the costs of a 6% heat rate 

improvement, EPA failed to consider that the other building blocks make complying with 

Building Block 1 even less attainable. Commenters stated that Building Blocks 2 through 4 are 

expressly geared at reducing operations at coal-fired facilities, but reduced run-time due to redispatch to NGCC or new low- and zero-emitting units means less revenue for coal-fired 

facilities, making it doubly infeasible for a coal-fired EGU to continue operations. Commenters 

stated that reduced run-time for coal-fired facilities also means coal-fired EGUs will more 

frequently run at part load and must cycle more often. Commenters pointed to a graph showing 

most steam turbines are most efficient when running near or at full load, with an average 300 

MW EGU experiencing a 30% efficiency loss between full and minimum load. Commenters 

stated that in fact, depending on a number of variables, they believe that increased part load 

operation could actually impair heat rate by 2% to 4%, thus, reduced operation in response to 

displacement by the Proposed Rule's other Building Blocks is likely only to lower their

efficiency, which in turn would require even more efficiency improvements to offset.
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Commenters stated that this negative feed-back loop is compounded by the fact that they have

already made significant capital investments to comply with MATS and other looming 

environmental regulations. Commenters stated that they have invested upwards of $750 million 

on CSAPR/MATS retrofits alone. Commenters stated that they depend on consistent dispatch of 

their low-cost energy to maintain a sufficient cash flow to cover their investments. Commenters 

stated that regular dispatch becomes even more critical if they are required to make additional 

efficiency upgrades as a result of this proposal. Commenters stated that thus, without some form 

of relief, the combined effect of Building Block 1 with Blocks 2 through 4 and other 

environmental regulations contribute to an economic death spiral for plants like theirs. 

Commenters stated that to make Building Block 1 work, EPA must reassess which HRI 

measures have not been undertaken and are thus available to existing units and must recalculate 

the CO2 reduction potential from this building block. 

Commenters stated that EPA has asked whether electricity used during startup or when the unit 

is not producing electricity for the grid should be included in the determination of net electric 

output. Commenters stated that EPA's regulations define operating day as any day in which fuel 

is being combusted, so electric usage times when a unit is completely idled would not be 

included in the calculation, but electric usage by pumps, fans, and other components during 

startup, or for maintaining a unit at a hot or warm idle readiness state, are part of the normal 

process of generating electricity and should be included. Commenters stated that exempting this 

use of electricity unwisely promotes the use of plants designed for baseload operation in 

inefficient load-following service.

Commenters stated that significantly, EPA also has failed to address the interaction of block 

one's heat rate improvements with block two's re-dispatch to natural gas and block three's 

increased deployment of renewable and nuclear energy. Commenters stated that the most 

significant heat rate improvements naturally occur when units are able to operate as closely as 

possible to their rated capacity at a steady state; however, the implementation of blocks two, 

three, and four would decrease the average capacity factor of coal-fired steam EGUs, forcing 

them to run at lower levels. Commenters stated that the application of block two alone will 

reduce the utilization of South Carolina's coal units by 22% from 2012 levels. Commenters 

stated that the need to run at lower capacity factors will decrease the efficiency of these same 

units for which EPA is assuming 6% efficiency improvements under building block one. 

Commenters stated that for example, for their subcritical coal-fired units, a change in operating 

levels from 100% to 60% of full load results in an approximately 6% efficiency loss based on the 

unit's design heat rate curves. Commenters stated that this efficiency loss would increase to 9% if 

the load level dropped to 50% and 14% if the load level further decreased to 40%. Commenters 

stated that as efficiency is reduced, the CO2 intensity of these units increases. Commenters stated 

that in addition, these adverse impacts on a unit's generating efficiency increase the per-MWh 

cost of any unit-level efficiency improvements even more than EPA estimates, thus making them 

less economical and less likely to realize the heat rate improvements envisioned by the Proposed 

Rule. Commenters stated that as the following chart from a recent presentation to the American 

Society of Mechanical Engineers (ASME) demonstrates, when utilities are forced to operate 

coal-fired EGUs at lower capacity factors, heat rates - and CO2 emissions - increase 

significantly. 
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Commenters stated that EPA recognizes that coal-fueled EGUs operating at lower than optimum 

capacity factors will have sub-optimal heat rates: "Coal-fired units are designed to operate most 

efficiently at full capacity. Commenters stated that as a unit drops below this level, in general, 

heat rate will increase." Commenters stated that this obvious fact was confirmed by Cichanowicz 

& Hein. (See Attachment B). Commenters believed EPA is accurate in this regard, as confirmed 

by a recent analysis examining the operating history of 28 coal-fueled EGUs. Commenters stated 

that this assessment found that on average the plant rate heat penalty (gross basis) incurred at 50 

percent load is about 7 percent for subcritical boilers and 4 percent for supercritical boilers. 

Commenters stated that examining the sixteen units that EPA relied on in building block one, 

this assessment found that the heat rate penalty (gross basis) at these units incurred at 50 percent 

load is 7 percent for subcritical boilers and 9 percent for supercritical boilers. 

Commenters stated that EPA acknowledges that building block two-increased natural gas 

generation-will displace coal: "The electric system's carbon intensity can be lowered through redispatch among existing EGUs, particularly by shifting generation from coal-fired units to 

natural gas combined cycle (NGCC) units." Commenters stated that however, EPA fails to 

recognize that shifting generation from coal to gas will reduce coal unit capacity factors and 

therefore increase coal unit heat rates, thereby undermining EPA's goal of improving coal unit 

efficiency. Commenters stated that in addition, building blocks three and four will also 

necessarily displace coal generation, further reducing coal-fueled EGU capacity factors and 

increasing their heat rates. Commenters stated that electric generation supply and demand must 

remain in balance, so if, as EPA is requiring, that alternative electricity is generated and more 

electricity is conserved, another form of generation must be concomitantly reduced. Commenters 

stated that since coal is the most carbon intensive generation, the overwhelming likelihood is that 

coal will be displaced. Commenters stated that as a result, like building block two, building 

blocks three and four will reduce coal unit capacity factors and increase coal unit heat rates. 

Commenters stated that EPA completely fails to take this into account in its building block one 

calculations. 

Commenters stated that increasing the utilization of NGCC units will displace coal-fired EGU 

output and coal-fired EGU heat rates will actually increase as a result, increasing their CO2 

emission rate. Commenters said coal-fired EGUs are designed to be most efficient when operated 

in a steady state at their full load capacity. Commenters said increases to the NGCC fleet 

capacity factor will necessarily relegate coal-fired EGUs to load following service resulting in 

more time operating at unstable and generally lower loads where they are less efficient. 

Commenters stated the goal of reductions through HRIs is overshadowed by the perceived 

necessity for the ability of natural gas or coal-fired steam EGUs to reduce generation while 

remaining ready to supply electricity when needed in peak demand hours and projected phaseout period at end-of-use. Commenters said redispatch should not be a mainstay of the CPP, only 

an aspect of the phase-in period

Commenters said EPA must consider the effect that shifting generation from coal-fired EGUs to 

existing NGCC units will have on the heat rates as described in building block 2. Commenters 

said the impact of this re-dispatch will reduce the capacity factors and increase heat rate with a 

carryover effect on building block 1. Commenters said as coal fired EGUs are utilized less and 

cycled more, unit efficiency will degrade. Commenters said as an example, if KU's Brown Unit 3 
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were operated at lower loads (e.g. dropping from 300 MW to 200 MW average) to accommodate 

100 MW of increased gas or RE dispatch, its heat rate would be approximately 20% higher. 

Commenters said EPA has also overlooked the negative impact on gas-fired EGU efficiency 

with respect to load following units. Commenters said under building block 2 of the Proposed 

Guidelines, EPA would require states to re-dispatch generation from coal-fired EGUs to NGCC 

units, which will result in more coal-fired EGUs being dispatched as load-following units as well 

as higher heat rate simple cycle combustion turbines.

Commenters stated EPA failed to consider the interaction between building blocks and the 

impact of other EPA rules on heat rate. Commenters said a significant driver of average heat rate 

(building block 1) is the capacity factor of a unit, and coal units are expected to be dispatched at 

reduced load points in the future because of increased utilization of NGCC units (building block 

2) or increased renewable generation (building block 3). Commenters said a coal unit’s heat rates 

will also be degraded by the installation of equipment to meet emission reduction goals such as 

those specified in the MATS rule or compliance with existing EPA consent decrees. Commenters 

said the amount of heat rate degradation at loads less than rated maximum unit loads depends 

upon the plant design; for example, heat rates at Wisconsin Public Service coal units degrade by 

anywhere between 2 and 8 percent as load decreases from rated maximum load to half load. 

Commenters stated the increased use of natural gas will force more coal units to operate more 

cyclically, thus degrading their heat rates and urged EPA to consider how building blocks 1 and 

2 will work together, or rather, against each other

Commenters stated that implementation of the proposed rule would likely change the dispatch of 

coal-fired units, which have historically been designed to operate most efficiently at peak or near 

peak load conditions. Commenters said this raises significant concerns that even if a 6% HRI 

could be achieved, changing fluid dispatch conditions could counteract such measures. 

Commenters said when it is considered that building block 2 calls for the redispatch of natural 

gas units to 70% on a very short timetable, considerable changes to the historic dispatch patterns 

of coal would need to occur on a very compressed time table, as well, which will impact the heat 

rates of coal-fired units. Commenters said an analysis of eGRID and EIA data demonstrate that 

coal-fired units operate at an average capacity of 52%, with many of the larger units operating 

between 70 and 80%.

Commenters urged EPA to review the 2011 EPRI study entitled Cycling and Load Following 

Effects on Heat Rate, 2011. Commenters said this study measured heat rate as function of load 

for three years, during the transition of a 700 MW subcritical coal-fired EGU from a base load 

unit to a cycling unit. Commenters found this study very relevant to the assumptions of the 

proposed rule, in particular the impact that priority dispatch to natural gas units will have on the 

heat rates of coal-fired units. Commenters said it is critical that EPA examine and account for the 

impact of increased cycling at the coal-fired units on heat rate as a direct result of priority 

dispatch to natural gas. Commenters said EPA should consider how the increased dispatch in 

natural gas units will impact the operation of coal-fired power plants and how the 6% HRI goal 

can be part of system or emission reductions that is directly counteracted by the increased 

dispatch of natural gas units. Commenters said the study also examined, via designed cycling 

tests, the impact of load following on heat rate. Commenters said the study clearly demonstrates 
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that operation at lower loads significantly degrades the heat rate performance of a coal-fired 

EGU. Commenters said Sargent & Lundy also agree stating "heat rate is increased when plants 

operate at lower loads, and the benefit of heat rate improvement strategy is reduced at lower 

loads" and "if an existing EGU is currently base-loaded and shifts to a load-cycling...that unit's 

annual average heat rate will increase," they identify that HRI improvements from options 

similar to those in their study "could, in some cases, be negated by HRI losses associated with 

load-cycling."

Commenters said at the same time building block 2 envisions that utilities and grid operators 

would reduce GHG emissions by shifting generation from coal-fired units with higher emissions 

to lower NGCC emitting units, EPA's proposal is essentially seeking to squeeze additional 

efficiencies out of the existing coal fleet (often where little opportunity might exist to do so).

Commenters said this raises a concern that there may not be sufficient load following generation 

capable of meeting the load following needs of transmission grids, such as PJM, as NGCC units 

typically follow load at an order of magnitude faster than coal-fired generating plants

Comment 32: Comments regarding the impact of cooling water temperature on heat rate, and 

treatment of cooling water temperature in the variability analysis.

Response 32: For the EPA’s response to these comments, see section V.C of the final rule 

preamble of the CPP and Chapter 2 of the GHG Mitigation Measures TSD supporting the final 

CPP. For example, as described there, our analysis takes into account unit design characteristics 

such as the type of water cooling system. We do not foresee that EGUs are likely to change their 

water cooling system in order to meet emission standards in state plans.

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

Commenters stated that EPA's statistical analysis is fundamentally flawed, in part, because it 

assumes there is a strong correlation between heat rate and only two other factors: unit load 

(utilization) and differences in ambient air temperature. Commenters stated that while EPA has 

correctly identified unit load as a key variable influencing unit heat rate, its assumptions about 

the impact of ambient air temperatures are not accurate. Commenters stated that cooling water 

temperatures have a much stronger correlation with unit heat rate differences and that cooling 

water temperatures directly affect a unit's ability to remove/recover heat in the thermal cycle. 

Commenters stated that ambient air temperatures eventually affect cooling water temperature, 

but relatively quick changes in ambient air temperatures do not result in equally rapid changes in 

the temperature of a cooling water body. Commenters stated that for example, warmer weather in 

the early spring does not initially elevate cold circulating water temperatures; or vice versa, 

colder early fall days will not immediately reduce warm circulating water temperatures. 

Commenters stated that similarly, day-to-night ambient temperature variations were used to sort 

the hourly data collected by EPA without regard to their actual ability to impact heat rate and 

that these realities skew the temperature "bin" data analysis performed by EPA significantly. 

Commenters presented a figure that shows the wide range of circulating water temperatures 

associated with the "bins" EPA created based on hourly ambient temperature data. Commenters 
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stated that during the hours sorted into EPA's 50 degree Fahrenheit ambient temperature bin, the 

circulating water temperature varies from 62 degrees Fahrenheit to 92 degrees Fahrenheit and for 

some "bins" the circulating water temperatures varied by as much as 34 degrees Fahrenheit.

Commenters stated that EPA oversimplified its analysis approach by simply aggregating data 

based on ambient air temperatures and unit load, then assuming that any remaining variability is 

under the control of unit operators and that such a simplified approach arbitrarily ignores the role 

that other variables, like circulating water temperature, play in heat rate variability. Commenters 

stated that in the figure earlier mentioned the variation (%) in heat rate within each temperature 

bin directly corresponds to the widening range in recorded circulating water temperatures within 

each ambient bin, suggesting a stronger correlation between heat rate and circulating water 

temperature, than ambient temperature. Commenters further stated that the figure does not 

suggest that EPA could simply replace ambient temperature with circulating water temperature 

in its analysis, but is used to point out that EPA dramatically oversimplified its analytical 

approach to explaining controllable heat rate variability. Commenters stated that the Utility Air 

Regulatory Group (UARG) performed a detailed critique of EPA's statistical bin analysis, and 

that using information provided in the EPA-referenced GHG Technical Support Document 

(TSD), UARG successfully reproduced the EPA results. Commenters stated that however, 

UARG further evaluated the units within the EPA bins and discovered that significant design 

differences (e.g. unit age, steam cycle design, capacity factor, cooling system design) exist 

between the analyzed units, and that these design differences contribute to the heat rate 

variability, and cannot necessarily be mitigated through "best practices" or heat rate 

improvement projects. Commenters stated that consequently, EPA's estimate of potential 

improvement opportunities is flawed and inaccurate. 

Commenters stated that cooling water temperature has a large impact on heat rate and while 

ambient air temperature does impact heat rate, its impact is not significant enough to be one of 

the primary factors in EPA's statistical analysis. Commenters believe that cooling water 

temperature would have been a more appropriate factor to consider in EPA's analysis and that 

changes in cooling water temperature, especially in the fresh water once-through cooling water 

systems, do not necessarily follows changes in ambient air temperature. Commenters further 

stated that other factors such as cooling pond depth, river size, lake size, water chemistry, intake 

location, and ocean versus pond play an important role and that a change in cooling water 

temperature of 10 degrees F could result in an increase in heat rate of approximately 1.5%.

Commenters referred to an example addressing the variability between plants found on page 2-

25 of EPA's TSD, where ambient temperature, according to EPA's analysis plays an important 

factor in nearly 25% of the 800+ units studied. Commenters stated that the EPA report indicates 

that most of these units, typically equipped with once through fresh water cooling units, showed 

an increase (i.e., decrease in efficiency) in heat rate of 2% to 4% during the summer months are 

compared to the winter months with a "temperature responsive EGU (electric generating unit)

that figure may be as high as 10%". Commenters stated that part of the reason for this increase is 

indeed higher ambient temperatures (i.e., higher fan duty, etc.), however the major reason is most 

likely the increase in cooling water temperatures used by the plant. Commenters stated that a 10 

degrees F increase in cooling water temperature increases heat rate by approximately 1.3% due 

to an increase in condenser back pressure and it should be pointed out that summer months 

produce the highest capacity factor (see Figure 2-3, page 2-24 of EPA's TSD), where operating at 
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high capacities produces the most favorable heat rate. Commenters summarized that the example 

provides evidence that factors beyond an EGU operator's control (such ambient temperature) 

play an important role in heat rate. 

Commenters further points to the situation at the McMeekin station in South Carolina, a 250 

MW plant that ranks as one of the most efficient power plants in the US even though it operates 

at a subcritical pressure cycle and is 60 years old. Commenters stated that the primary reason for 

this high efficiency is its access to 45 degrees F year round cooling water, generating a very 

highly efficient condenser system resulting in low heat rates and that availability of such a low 

cooling water temperature for a power plant is rare. 

Commenters stated that some of the best practices that EPA focuses on, if implemented, can 

compromise reliability obligations. Commenters provided as an example that it is EPA's 

suggestion to remove large circulating water pumps at lower loads to save parasitic load. 

Commenters stated that these systems have very large butterfly valves that must be closed to 

prevent recirculation of the cooling water when they are removed from service. Commenters 

stated that the large butterfly valves are highly susceptible to re-opening failures when the 

circulating water pumps are placed back in service with increasing load. Commenters stated that

the loss of the water pumps prevents the unit from achieving its full capacity and optimum heat 

rate thereby impacting on capacity which, in turn, increases heat rates and counteracts any 

benefit gained by removing the circulating water pumps to save parasitic load. 

Commenters stated that analysis indicates that Newton Unit 1's heat rate improvements were 

cyclically negated by seasonal variations in the water temperatures of the facility's man-made 

cooling lake. Commenters stated that in that regard, EPA also has failed to consider the impact of 

small cooling lakes/ponds on a unit's heat rate; for example, the Newton cooling lake, which is 

relatively small, was built to dissipate heat from the condensers of two 600 MW units.

Commenters stated that the cooling lake's ability to dissipate heat is diminished during drought 

conditions and above-average ambient air temperature conditions. Commenters stated that both 

situations can lead to higher lake temperatures and higher heat rates for the generating units. 

Commenters stated that even though the Newton plant can maintain compliance with its thermal 

discharge limits, experience suggests factors such as ambient conditions and the resulting 

fluctuations in cooling lake temperature can affect net heat rate as much as performanceimproving actions. Commenters stated that given that several of their facilities rely on man-made 

cooling water impoundments, heat rate improvements projects will not be able to achieve or 

maintain the results EPA concludes are achievable under Building Block 1, particularly at those 

facilities with smaller cooling ponds. 

Commenters questioned why the EPA didn’t analyze the non-air impacts of heat rate 

improvements such as changing cooling systems as mentioned on p. 2-5 of the GHG TSD.

Commenters stated that ambient conditions have been well-demonstrated to influence a plant's 

heat rate. Commenters stated that for instance, increases in temperature of ambient air can 

increase the amount of back pressure on a steam turbine well above design values, which 

consequently reduces turbine efficiency and increases heat rate up to 5%. The commenters stated 

that the magnitude of back pressure generated in response to ambient conditions is largely based 

on the type of cooling system used and for plants using "once-through" water circulation 
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processes, an increase in cooling water temperature can increase pressure within the condenser, 

in tum compromising turbine efficiency. Commenters stated that for such plants, however, 

ambient air temperature does not perfectly correlate with water temperature and can differ by 

several degrees. Commenters stated that considering that differences of just a few degrees can 

result in a heat rate increase of 0.5-1 %, EPA's failure to consider cooling water temperature in 

its heat rate variability analysis reflects a flawed BSER determination. 

Comment 33: Applicable to the supplemental proposal for Tribal and Territorial - Comments 

regarding the impact of cooling water temperature on heat rate 

Response 33: For the EPA’s response to this comment, see section V.C of the final rule 

preamble of the CPP and Chapter 2 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 EPA did not consider cooling water temperature, which in practice has a 

far greater impact on heat rate than ambient temperature.

Comment 34: Comments regarding fuel impacts on heat rate as one of the variability factors not 

considered in the EPA’s analysis 

Response 34: See Chapter 2 of the GHG Mitigation Measures TSD supporting the final CPP for 

EPA’s response to this comment. For example, as explained in those documents, the EPA does 

not assert that all heat rate variability is caused by ambient temperature, capacity factor, and 

differences in implementation of heat rate improvement measures.

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

Commenters stated that changes in fuel can have an impact on heat rate and that the EPA 

analysis does not take into account the impact of fuel changes and more specifically moisture 

content and ash chemistry changes. Commenters stated that there have been a significant number 

of plants that have switched to higher moisture western coal in order to meet emission 

requirements and these plants have subsequently seen an increase in heat rate due to the latent 

heat of vaporization loss of the water present in the fuel and the additional parasitic energy 

required to dry the coal prior to its combustion. Commenters stated that wet (rain or snow) 

weather also impacts the moisture content of coal as coal is stored outdoors.

Commenters added that besides the effect of additional moisture and lower heating value of 

those fuels, furnace, superheater, reheater, and economizer fouling with glassy, hard to remove 

deposits (alkaline earth) have a negative effect on heat rate because those insulating deposits 

make it more difficult to maintain the design superheat and reheat steam temperatures. 

Commenters stated that this may cost 1% heat rate deficit in and of itself. Commenters further 
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stated that there are solutions for this, but NSR provisions can be an obstacle to consideration of 

these solutions. 

Commenters added that the heating value of the coal consumed by the power generation industry 

had changed over the past few years. Commenters presented a table of EIA data that shows that 

the integrated coal used by the power industry had decreased by 2.5% which has a significant 

impact on plant heat rate. 

Commenters stated that using a statistical analysis that presumes that a well-controlled coal unit 

should have very consistent heat rate under a given ambient temperature and average hourly load 

over the eleven-year period that was evaluated, EPA reached the conclusion that 4% 

improvement in heat rate was possible on average by increased use of no or low cost "best 

practices," and that variation in gross heat rate outside of these two variables was regarded as an

opportunity to improve heat rate. Commenters stated that unfortunately, this approach does not 

adequately address all of the factors beyond the operator's control that impact heat rate and that 

over this period many facilities made significant changes to their plants in response to 

environmental regulations that would impact heat rate, to include changes in fuel, addition of 

new equipment, etc. Commenters stated that in the statistical analysis used by EPA, variation in 

heat rate resulting from these other factors that are beyond the operator's control is mistaken as 

variation that can be improved through "best practices ", and as a result, the analysis by EPA 

reaches an incorrect conclusion about the opportunities to improve heat rate through "best 

practices." 

Commenters stated that the heat rate of a plant is impacted by many components and that some 

of the most significant components of heat rate that EPA did not include in their statistical 

analysis were the fuel burned, the heating value of the fuel, and the yearly variation in the fuel 

burned for power generation. Commenters stated that the heating value of coal is primarily 

impacted by the water content of the coal since water has to be evaporated during combustion. 

Commenters stated that during the period of 2002 to 2012 that EPA used in their analysis, the 

use of bituminous coal decreased by about 10% while subbituminous coals (particularly from 

PRB) increased by 28%. Commenters stated that however, actual usage of coals varied 

significantly during this period and that bituminous coals varied +12% to a -24% for the yearly 

average and PRB coals varied +8% to -12% from its annual average usage. 

Commenters stated that PRB fuels typically have about 25% moisture content and a heat value of 

8,700 Btu/lb and that bituminous coals generally have less than 10% moisture and a heating 

value of 11,900 Btu/lb. Commenters stated that as a result of the increase in PRB and decrease in 

bituminous coal during the evaluation period that more than 7% water was "combusted" in coal 

generation resulting in significant heat rate impacts on the coal fleet. Commenters stated that 

according to EIA data there was significant annual variations in moisture content (and ash 

content from 8-30%) of the fuel combusted during this period that resulted in more than the 6% 

used as its model to justification for heat rate improvements. 

Commenters reiterated that in Texas, EPA's assumptions simply do not make sense since Texas 

has a deregulated electricity market. Commenters stated that their members that operate EGUs 

and their members that supply coal, including lignite coal, are well aware that in the competitive 
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electricity market, every bit of efficiency must be drawn out of electric generating units. 

Commenters stated that Texas units have already implemented all best practices and equipment 

upgrades that are available. Commenters were also aware that Texas units that burn Texas lignite 

may have additional complications meeting the 6 percent standard because lignite is a lower 

heat-rate fuel and therefore, lignite fired units have historically been compelled to seek more 

efficiencies than those of units burning higher heat-rate coals. 

Commenters stated that the fuel-derived annual heat rate is highly variable starting in 2008 and 

through 2011 at Antelope Valley Unit 2. Commenters stated that the owner attributes several 

reasons for this, including coal quality. Commenters stated that although the source mine and 

seams for the host lignite coal are unchanged, sodium content increased notably in both 2008 

and 2011, and that the increase in sodium content increases both the propensity of the fuel to 

deposit on boiler surfaces, and to block air heater passages. Commenters stated that both boiler 

and air heater performance could be compromised by the change in fuel properties. 

Commenters stated that the type of coal used is also an important factor that affects heat rate. 

Commenters stated that even within a particular coal species, minor, inherent variations in the 

characteristics of the fuel can cumulatively produce appreciable variations in heat rate. 

Commenters stated that for instance, moisture and ash content within coal can reduce heat 

transfer efficiency and produce latent heat losses. Commenters stated that yet, nowhere did EPA 

consider the possibility that slight deviations among these characteristics could produce heat rate 

variability. 

Commenters stated that the heating value of the coal burned has a significant impact on plant 

heat rate. Commenters presented a table (titled: “Heating Value of Coals in Electric Generation 

Btu/lb. By year for all coals, lignite, bituminous, & subbituminous”) with a summary of heat 

values of coals from EIA used in electric power generation. Commenters stated that between 

2008 and 2012 there was almost a 3% change in the heating value of the coal used in generation 

resulting in about a 1 % increase in heat rate. Commenters stated that this change in heating 

values resulted from the fuel mix used in EGUs over this period resulting in changes in the fleet 

station heat rate. Commenters presented a Table showing annual gross & net heat rate 

(btu/kWhr) & HHV for coal (btu/lb) 2008-2012.

Commenters stated that the EIA data shows the changes in blends of coals used in power 

generation over this period. Commenters presented a chart (titled: “Heat Input to Electric 

Generation 2002-2012, MMBtu, lignite, bituminous, & subbituminous”) that shows the changed 

in the total heat inputs to EGUs on as impacted by the heating value of coals and the rank of coal 

burned. Commenters stated that these all had impacts on station heat rates.

Commenters presented a chart ( EGU tons coal burned per year 2000-2014, lignite, bituminous, 

& subbituminous + linear fits) showing the EIA data for coal by rank burned every year in power 

generation. Commenters stated that PRB which has a lower heating value and 25% moisture has 

significantly increased over the evaluation period. Bituminous coals with moisture content 

generally less than 10% has decreased. Commenters stated that the additional coal moisture has 

had a definite impact on heat rate.
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Commenters presented a chart (Impact of coal rank on heat rate 2000-2014, tons coal & Heat 

Rate, bituminous, & subbituminous, Gross & Net Heat Rate) showing coal rank per year versus 

the gross and net heat rates. Commenters stated that the gross heat rate is shown to be an inverse 

relationship to the amount of PRB burned.

Commenters stated that as they have seen from the data presented in their comment letter, the 

heat rate of a plant is impacted by many components. Commenters stated that some of the most 

significant components of heat rate that EPA did not include in their statistical analysis were the 

fuel burned, the heating value of the fuel, and the yearly variation in the fuel burned for power 

generation. Commenters stated that the heating value of coal is primarily impacted by the water 

content of the coal since water has to be evaporated during combustion.

Commenters stated that during the analysis period used by EPA of 2002 to 2012, the use of 

bituminous coal decreased by about 10% while subbituminous coals (PRB) increased by 28%. 

Commenters stated that however, actual usage of coals varied significantly during this period. 

Commenters stated that bituminous coals varied from a + 12% to a -24% for the yearly average; 

PRB coals varied from a +8% to a -12% from its annual average usage. Commenters stated that 

PRB fuels typically have about 25% moisture content and a heat value of 8, 700 Btu/lb and 

bituminous coals generally have less than 10% moisture and a heating value of 11,900 Btu/lb. 

Commenters stated that as a result of the increase in PRB and decrease in bituminous coal during 

the evaluation period, more than 7% water was "combusted" in coal generation resulting in a 

significant heat rate impact on the coal fleet. Commenters stated that according to EIA data, 

there were significant annual variations in moisture content of the fuel combusted during this 

period that resulted in more than the 6% used in the model justifying for heat rate improvements. 

Commenters stated that second, EPA relies on an outdated, 2009 study by Sargent & Lundy to 

extrapolate achievable efficiency gains through technological upgrades and among other things, 

that study fails to account for the parasitic loads (i.e., heat rate increases) of upgrades that 

operators have made in the last six years, some of which were done in response to other 

environmental regulations, like MATS. Commenters stated that even Sargent & Lundy concede 

that the study's conclusions of potential heat rate improvement are inflated. 

Commenters stated that EPA's broad application of the heat rate improvement assumption fails to 

consider installation of air pollution control systems for compliance with the Mercury & Air 

Toxics Standards (MATS) rule by April 2015. 

Comment 35: Comments regarding the potential for HRI to be offset by the effects of various 

add-on pollution controls installed to comply with other rules

Response 35: For the EPA’s response to these comments, see sections V.C and X.A of the final 

rule preamble of the CPP and Chapter 2 of the GHG Mitigation Measures TSD supporting the 

final CPP.

The following are summaries of the specific public comments under this comment:
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Commenters stated that EPA's heat rate improvement determination was based on an analysis of 

gross heat rate data for a large population of units over a ten-year period, but that EPA did not 

consider or account for the many physical and operational changes that occurred over this period, 

and that have a direct effect on heat rate. Commenters stated that EPA should have considered 

heat rate changes from the installation of new emission control systems, prior heat rate 

improvement projects, and changes in duty cycle before estimating any remaining potential for 

heat rate improvements at existing coal-fired units. 

Commenters stated that installing and operating emission control systems can often mask or 

offset any future heat rate improvement actions. Commenters stated that from a net unit heat rate 

standpoint, these systems have a direct impact as the auxiliary power requirements reduce the 

amount of net energy (MWh) produced. Commenters stated that the retrofit of selective catalytic 

reactors (SCRs) consumes on average about 1.5% of net output and that the retrofit of flue gas 

desulfurization (FGD) systems on units fired by subbituminous coals increases auxiliary power 

usage by approximately 1.5%, while retrofits on units firing bituminous coals or a blend of these 

fuels increases auxiliary power usage by approximately 2.5%. Commenters stated that in 

addition, a limestone-based wet FGD system introduces additional CO2 into the flue gas stream 

as a result of chemical reactions in the scrubber, which increases the CO2 content of the gas 

stream by several percentage points, in addition to the increase in auxiliary power requirements. 

Commenters stated that there may be ways to minimize the detrimental heat rate impacts of 

adding these systems (e.g. employing efficient axial fans, considering variable speed drives 

where practical, optimizing ductwork configurations, etc.), but these design options are sitespecific, and in no case are they enough to offset a net heat rate increase from the addition of 

these control systems. Commenters stated that all of these changes affect heat rate, but do not 

"create" any additional heat rate improvement opportunities and that EPA's analysis failed to 

eliminate these causes of heat rate variability, and thus overstates the remaining opportunities for 

improvement. Commenters concluded that for units with current obligations for future emissions 

control system retrofits, the adverse impact to net heat rate (2-4%) from the control installations 

makes a 6% improvement in heat rate even more unachievable. 

Commenters stated that EPA identified 16 units, based on the results of its statistical analysis, 

that EPA concludes are examples of equipment upgrades that achieved 3-8% gross heat rate 

reductions and that EPA claims that after accounting for "capacity factor, reporting method, or 

other events," these 16 units emerged from the national inventory and reported a single yearover-year improvement in gross heat rate of at least 3-8%. Commenters stated that the sixteen 

units, owned by twelve utilities, were identified in a table posted in the rulemaking docket. 

Commenters further stated that UARG contacted and received technical responses from 10 of the 

12 owners, addressing 14 of the 16 units, and that the UARG investigation found that:

-Five units reported that upgrading the steam turbine appeared to lower gross heat rate, 

with modest payoff of approximately 3%. However, at three units this benefit was more 

than negated by an increase in net heat rate due to retrofit of environmental controls. 

Specifically, the Gibson unit 1 incurred higher net plant heat rate starting in 2007, when 

FGD was retrofit and gas handling was changed to employ a single dedicated stack. 

Petersburg unit 2 similarly observed a net heat rate increase in 2005, following retrofit of 

SCR in 2004. In 2007, King unit 1 completed a significant rehabilitation of the unit, 

including a new steam turbine, feedwater heaters, circulating water system upgrades and 
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coal handling upgrades as part of a project to add SCR, FGD and fabric filter to the unit 

for emissions controls. The upgrade of the steam turbine and other components improved 

heat rate by 2.7% but was offset by the losses imposed by the addition of the emissions 

controls equipment. 

Commenters stated that any assumptions on fleet-wide or unit-specific heat rate improvement 

should also reflect the likelihood of future incremental compliance obligations (i.e. equipment 

retrofits) mandated by states and/or EPA, as well as future operating characteristic changes that 

could ultimately override currently identified heat rate and/or cyclical best-practice type 

improvement opportunities, in particular, selective catalytic reduction ("SCR") technology 

retrofits are required on several of their coal-fueled generation units to reduce NOx emissions 

under EPA's Regional Haze Rule. Commenters stated that it is possible that requirements of SCR 

for Regional Haze compliance could be expanded to other of their EGUs in the future. 

Commenters stated that the currently required SCR equipment retrofits will cause individual 

EGU heat rates to increase (become less efficient). 

Commenters stated that the Proposed Rule fails to recognize future efficiency-compromising 

retrofits that may be required for compliance with upcoming environmental standards, such as 

the MATS Rule.

Commenters stated that EPA's calculation of the state goals did not take into account the 

parasitic impacts of emission control technology and that the installation of control technology 

results in heat rate increases that can be so significant that they eclipse heat rate improvements 

achieved through the types of equipment upgrades on which EPA bases its six percent 

assumption. Commenters stated that this is the case, for example, at Xcel Energy's Allen S. King 

Plant, on which EPA unreasonably relies as adequate demonstration of a six percent heat rate 

improvement [GHG Abatement TSD at 2-32]. Commenters stated that Xcel Energy undertook a 

large, voluntary emissions reduction project that included equipment upgrades to improve heat 

rates, as well as the installation of emission control equipment and that the project included 

installation of selective catalytic reduction technology ("SCR"), dry flue gas desulfurization 

("FGD"), and a fabric filter baghouse; replacement of all three sections of the steam turbine; 

repairs to the steam generator; replacement of the feedwater heaters; changes to the circulating 

water system; upgrades to the coal handling system; and other rehabilitation work to make the 

emission control upgrades cost-effective. Commenters stated that while the installation of the 

new turbine and feedwater heaters successfully improved the heat rate, the improvement was not 

great enough to offset the increase in heat rate resulting mainly from the installation of the 

emission control technology and overall, the net heat rate increased by 4.7 percent, primarily due 

to the installation of the emission control equipment. Commenters stated that in light of this 

significant overall increase in heat rate, it is unreasonable for EPA to rely upon the Allen S. King 

Plant as adequately demonstrating that a six percent heat rate improvement is achievable. 

Commenters stated further, Xcel Energy's experience at the Allen S. King Plant underscores the 

need for EPA to appropriately take into account the heat rate impacts of emission control 

technology because control technologies will be installed on many coal-fired EGUs over the next 

several years to comply with other CAA programs, such as Regional Haze and the Mercury and 

Air Toxics Standards Rule ("MATS"). Commenters stated that if EPA ignores the heat rate 

impacts of these installations in setting the state CO2 goals, states will be required to achieve not 

only the six percent heat rate improvement anticipated under Building Block One, but also an 
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additional heat rate improvement to offset any loss in efficiency from parasitic emission control 

technology.

Commenters stated the EPA did not account for the impact of the installation of pollution control 

equipment on existing generation and the inability of improved O&M practices to mitigate these 

impacts. Commenters stated that for their units there have been substantial investments in 

pollution control technology, and further investments are in progress:

• Flue Gas Desulfurization (FGD) and Selective Catalytic Reduction (SCR) 

equipment has been installed for the control of SO2 and NOx on all four units at 

Monroe Power Plant (3,114 MW total capacity). Operation with this additional 

equipment is estimated to increase heat rate by one to two percent. This is a 

function of the operation of additional plant equipment and cannot be addressed 

through improved O&M practices.

• Their remaining plants are in the process of installing pollution control systems to 

comply with the Mercury and Air Toxics Standards (MATS). The additional 

equipment associated with these installations will also negatively impact unit heat 

rate and CO2 emission rates.

• Commenters stated that these controls have a negative impact on heat rate and this 

impact is ignored in the EPA analysis and that the ability to achieve the assumed 

four percent heat rate improvement through O&M improvements is compromised 

by the degradation in heat rate that is inherent with the operation of this additional 

equipment. 

Commenters stated that twenty-eight units recently retrofit with FGD ranging in generating 

capacity from 400 to 600 MW were evaluated for gross heat rate change with load and that these 

units (Appendix A of Comment EPA-HQ-OAR-2013-0602-22768) required significant 

investment to equip with state-of-art environmental controls and thus will likely be key to an 

owner's generation portfolio. Commenters stated that twelve of these units are also equipped 

with SCR NOx controls. Commenters stated that these units were designed primarily for 

baseload, steady-state operation and that the penalty to an owner operating these units at part 

load could be significant. Commenters presents (Figures 2-1 to 2-6) typical curves defining the 

relationship between gross heat rate and operating load for six units representative of the twentyeight examined. Commenters stated that the units selected represent supercritical and subcritical 

boilers, bituminous and subbituminous coals, and are equipped with FGD, and some with SCR 

and that many units incur significant heat rate penalty at half load or less than half load. 

Commenters further presented a table (Table 2-1) summarizing for all twenty-eight units the 

average increase in heat rate incurred at 50% load as a percentage of the full load heat rate. 

Commenters stated that results are shown separately for subcritical and supercritical units and 

show that on average the plant heat rate penalty (gross basis) incurred at 50% load is about 7% 

for subcritical boilers and 4% for supercritical boilers.

Commenters concluded that the results in Table 2-1 show for two very different classes of units 

that any possible gains in heat rate as determined for full-load operation are on average more 

than offset by penalties for low load operation. 
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Commenters stated that many coal-fired EGUs are installing pollution control systems to comply 

with other regulatory requirements, such as the Mercury and Air Toxics Standards ("MATS"), 

while others must install further retrofits in coming years to comply with regional haze 

requirements, 316(b) requirements, and steam electric effluent guidelines requirements. 

Commenters stated that those systems will reduce net generation and increase net heat rate and 

CO2 emission rates as acknowledged by the EPA. Commenters stated that, as the EPA has 

already noted, controls for sulfur dioxide and acid gases will increase heat rates and CO2 

emissions and the EPA's own analysis indicates that 20 GWs of coal-based units will install dry 

scrubbers and 63 GWs will upgrade currently installed scrubbers in 2015-2016 to comply with 

the MATS. Commenters stated that also, various water regulations may force many coal-fired 

EGUs to move from once through to evaporative or air cooling, further increasing auxiliary loads 

and heat rates. Commenters referred to EPA's October 2010 report "Available And Emerging 

Technologies For Reducing Greenhouse Gas Emissions From Coal-Fired Electric Generating 

Units" acknowledging FGD parasitic load. Commenters stated that because the EPA failed to 

consider the effect of present and future pollution control requirements on EGU heat rate, it has 

set an unsupported and unattainable HRI requirement in Building Block 1 and as such, it does 

not reflect BSER, and even if EPA's Proposed guidelines consisted solely of Building Block 1, 

its proposal would be arbitrary and indefensible. Commenters stated as proposed, the EPA would 

force affected EGUs to overcome the energy penalties associated with these controls and then 

achieve an additional 6 percent heat rate improvement on top of that through HRIs that may no 

longer be available. Commenters stated that in developing the Building Block 1 target, the EPA 

appears to completely ignore the obligations imposed on EGUs by the CAA and other 

environmental statutes. 

Commenters referred to Figure 2, which displays fleet average gross heat rate and annual 

average capacity factor over the eleven year EPA study period, as well as data from NEEDS 

v5.15 showing GW of new scrubbers installed. Commenters stated that EPA's own data shows 

that over the 2002-2008 period, average gross heat rate for their population decreased about 3% 

while capacity factor on average stayed about the same even as scrubbers were being installed. 

Commenters stated that the statistical analysis performed by EPA would incorrectly identify this 

general improvement in heat rate over the period as variability that can be improved upon 

subsequent to 2012 rather than continual improvement that might not be improved upon. 

Commenters stated that beginning 2009 through 2012, the analysis demonstrates that heat rate 

increased about 1% while average capacity factors decreased - demonstrating the important 

impact of capacity factor on heat rate.

Commenters stated that the Flint Creek unit is being retrofitted with additional emission control 

equipment to comply with the Mercury and Air Toxics Standards (hereinafter "MATS") and 

Regional Haze rules and the new equipment will increase the Flint Creek unit's heat rate above 

the 2012 base year heat rate, thus decreasing its efficiency. Commenters stated that this 

environmental control project will thus likely reduce the available HRI assumed for Arkansas in 

Block 1.

Commenters stated that EPA should recognize within the goal-setting formula and for the 

purpose of goal-setting that currently un-scrubbed units which continue to operate at base-load 

levels will likely be required to implement controls that will create parasitic loads that will 

partially negate the theoretical benefits of investments in HRIs. 
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Commenters stated that they are concerned with several aspects of the analysis method 

implemented by U.S. EPA when setting HRI goals and of major concern is the use of gross 

generation in the analysis. Commenters stated that this indicates that the costs and pirate loads 

associated with environmental control equipment were not considered in the heat rate efficiency 

analysis which is a major oversight. Commenters understand that environmental controls require 

a substantial amount of load to operate, significantly worsening the heat rate and efficiencies of 

well-controlled coal-fired power plants relative to uncontrolled units. 

Commenters stated that compliance with MATS can be accomplished through technologies such 

as wet and dry scrubbers, dry sorbent injection systems, activated carbon injection systems and 

fabric filters and that these additional plant controls increase plant heat rates that will offset some 

portion of the heat rate improvements required by the proposed rule. 

Commenters stated that EPA fails to account for the fact that its other regulatory initiatives that it 

has recently imposed on the utility sector will also degrade coal unit efficiency, for example, 

EPA's Mercury and Air Toxics Standards, Cross-State Air Pollution Rule, Effluent Limitation 

Guidelines, and Clean Water Act Section 316(b) Cooling Water Intake Structure Rules, all of 

which will take effect in the next few years are each expected to require existing coal plants to 

install new equipment that will require additional parasitic load, also known as station service, 

that reduces the amount of the "net" electricity generated that can be sold to the grid. 

Commenters stated that as EPA states, "[t]he electric power consumed by air pollution control 

equipment reduces the overall efficiency of the EGU." Commenters stated that as more and more 

equipment at the facility requires more and more of the electricity generated, less electricity will 

be available for distribution, resulting in a lower net heat rate. Commenters stated that since 

EPA's goal calculation is based on pounds of CO2 per net megawatt-hour, the increase in 

parasitic load required by EPA's many other rulemakings will present a direct impediment to 

achieving the 6 percent efficiency improvement that EPA desires. Commenters stated that EPA 

fails to account for this drop in efficiency in claiming that a 6 percent improvement is 

achievable. 

Commenters stated that due to the heat-rate and fuel chemistry of lignite, many Texas lignitefired EGUs' control technologies may be larger or have a greater parasitic load than the controls 

on other non-lignite EGUs - some of these controls were likely required by EPA's MATS Rule or 

other recently proposed/finalized rules. Commenters stated that this impacts heat-rate and the 

ability to comply with Block 1 of EPA's BSER model. 

Commenters stated that EPA would have seen that, rather than opportunities for improvement in 

net heat rate at CGS relative to a 2012 baseline, any heat rate improvement opportunity would be 

negated with the recent addition of the Unit 2 SCR system or the proposed Unit 1 SCR system at 

CGS, as required by other air pollution control requirements imposed by EPA. Commenters 

stated that in particular, in 2012, EPA issued a FIP that would require the installation of an SCR 

system at CGS Unit 1. Commenters stated that compliance with that FIP is expected to increase 

net heat rate at CGS Unit 1 by at least 1%, completely offsetting any potentially achievable 

improvement in heat rate through a costly turbine upgrade at this coal-fired EGU, thus, relative 

to a 2012 baseline, there is no opportunity for heat rate improvement at this unit.
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Commenters stated that the EPA neither analyzed nor addressed the effects of other regulations 

under the CAA that will actually serve to increase average net heat rates over time by adding 

auxiliary loads from additional pollution controls.

Commenters stated that EPA has also failed to factor in the impact on heat rate of existing units 

from installing emission control technology needed to comply with other EPA regulations. 

Commenters stated that in April 2014 PacifiCorp filed its 2014 Fossil Fuel Heat Rate 

Improvement Plan with the Utah Public Service Commission and in the plan, the company 

reported that on average 1.3% in heat rate improvements was possible across its entire fleet of 

coal-fired power plants by 2023. Commenters stated that however, at its Huntington and Hunter 

Power Plants in Utah, PacifiCorp projects a decrease of heat rate efficiency of 4.2% and 1.3% 

respectively, due to the installation of emissions control equipment.

Commenters stated that EPA's generalized heat rate assumptions are unfounded and 

unachievable for all coal-fired power plants in Utah. Commenters stated that moreover, the EPA 

has not accounted for the heat rate penalty of installing parasitic emission control technology in 

its calculations of state emissions reduction goals. Commenters stated that EPA should give 

states the flexibility to adjust their state goals to account for coal-fired power plants that are not 

reasonably able to achieve six percent 6% in heat rate improvements. Commenters stated that 

Building Block 1 assumptions of heat rate improvement achievable for Utah coal-fired power 

plants should be revised to reflect reasonable, achievable heat rate efficiency improvements. 

Commenters stated that Big Stone Plant has already made or plans to make all applicable HRIs 

identified by Sargent & Lundy and furthermore, they are in the process of installing $384 million 

in AQCS upgrades at Big Stone Plant pursuant to EPA's Regional Haze and MATS rules. 

Commenters stated that initial permit estimates indicated approximately 8 to 9 MW of the energy 

produced by Big Stone Plant will be consumed by operation of the newly-installed AQCS, 

degrading the plant's net heat rate by 1.7%. Commenters stated that in the best case scenario, the 

two remaining planned HRI projects at Big Stone Plant will merely offset this degradation and 

return Big Stone Plant to its baseline heat rate and consequently, it will be impossible to attain 

the additional 6% HRI contemplated by the proposed rule. Commenters stated that the lack of a 

site-specific evaluation of feasible HRI at Big Stone Plant illustrates the arbitrary and capricious 

nature of EPA's across-the-board 6% HRI target. Commenters stated that it also demonstrates 

EPA's technical misapprehension of the nature, cost, and availability of HRI measures. 

Commenters stated that the operation of sulfur dioxide scrubbers, selective catalytic reduction 

(SCR) controls, and fabric filter degrades the heat rate of EGUs and to reduce emissions, utilities 

have been installing and will continue to install such pollution control equipment. Commenters 

stated that between 2002 and 2012, a total of 120,000 MW of capacity was fitted with flue gas 

desulfurization (FGD) and 140,000 MW of capacity was fitted with SCR. Commenters stated 

that these projects result in parasitic loads that have a negative effect on unit efficiency, 

offsetting the efficiency gains due to heat rate improvement projects and that for example, an 

FGD retrofit may decrease overall boiler efficiency by 1 to 2 percent, whereas an SCR retrofit 

may decrease boiler efficiencies by up to 1.5 percent. Commenters stated that the efficiency loss 

from such projects is cumulative; therefore, a unit retrofitted with both an FGD and an SCR 

could lose up to 3.5 percent efficiency.
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Commenters stated that APS is required to install pollution control equipment on coal-fired 

boilers in the near future to meet Mercury and Air Toxics Standards and regional haze 

requirements and that heat rate degradation due to future compliance requirements must be 

accounted for prior to any heat rate improvement requirement. Commenters stated that 

accordingly, the six percent heat rate improvement that EPA used to set the goals is arbitrary and 

unrealistic and the heat rate value used to set the goals should be based on real net 

improvements. Commenters stated that each coal plant should be assessed considering the actual 

heat rate improvement projects that can be completed, discounted by the projects required by 

other environmental regulations that will create parasitic loads. Commenters stated that the 

aggregate of the real net heat rate improvement projects, discounted for degradation, should then 

be used to set the state goals. Commenters stated that of the efficiency improvement projects 

suggested by EPA for coal fleet implementation, many of the projects would trigger NSR and 

likely could require the implementation of BACT requirements. Commenters stated that adding 

pollution control devices to meet BACT requirements is another source for parasitic loads and 

therefore most, if not all, of the efficiency gained from the equipment upgrade project could be 

lost due to the additional pollution control equipment that would be needed to implement the 

project. 

Commenters stated that heat rate improvement projects gains are generally swallowed up by the 

addition of more environmental control equipment and that EPA's Title IV Acid Rain provisions, 

Clean Air Interstate Rule, CSAPR, MATS, and Best Available Retrofit Technology rules have 

added environmental control equipment over the past 20 years that increased net overall heat 

rates on coal fired units. Commenters stated that each time the industry is required to reduce 

emitted pollutants, any and all gains to boiler and turbine efficiency are erased by parasitic load 

and as parasitic load rises to serve the environmental control equipment, the overall efficiency of 

the boiler turbine degrades. Commenters stated that with the addition of wet flue gas 

desulfurization equipment, the net effect of CO2 production to the atmosphere rose. Commenters 

stated that scrubbing sulfur dioxide under the guise of EPA rules increased the emissions of CO2 

during the scrubbing process, CO2 is liberated. Commenters stated that installing additional 

environmental control equipment requires coal-fired units to burn more coal to serve the new 

equipment's energy requirements. 

Commenters stated that heat rate benefits are largely unavailable or irrelevant to the coal fleet 

due to the installation and operation of Selective Catalytic Reduction Systems ("SCRs") for 

compliance with other EPA air regulations, including the Clean Air Interstate Rule ("CAIR"), the 

Cross State Air Pollution Rule ("CSAPR"), and MATS. Commenters stated that to avoid

accelerated catalyst degradation and other negative impacts to the SCR, coal-fired EGUs must 

maintain an artificially high boiler exit gas temperature, usually above 600 degrees, thus 

reducing opportunities to absorb additional heat in the economizer to improve a unit's heat rate. 

Commenters stated that in addition, the location of SCRs has made it significantly more difficult 

to access and replace the economizers at many units. Commenters continues that EPA has also 

overstated the benefits associated with the installation of VFD motors by assuming that the 

benefits of VFD motors - i.e., the reduction of station services when less coal is needed - would 

be gained on a constant or frequent basis. Commenters stated that for Southern Company's coalfired EGUs, the potential benefits of VFD motors would be much lower than EPA's predictions 

because there is almost no need for variation in belt speed and that during bunker loading of coal, 

the belts run at one continuous speed until the bunker is full, and then the motor is turned off 
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making EPA's estimate of heat rate improvements associated with VFD motors vastly 

overstated.

Commenters stated that both the "best practices" and "equipment upgrade opportunity" 

assumptions are incorrect for most EGUs. Commenters stated that for example, most of the coalfired units in the United States, particularly those that will still be operating after the compliance 

deadline for the Mercury and Air Toxics Standards (MATS) Rule, are likely to have already 

implemented most of the best practices and equipment upgrades identified by EPA. Commenters 

stated that these are the units that companies have invested in to operate following the MATS 

Rule and transport rule compliance dates. Commenters stated that efficiency is an important 

consideration for their continued operations and while some equipment upgrades may be 

available, the costs of the upgrades would generally be very high and many would be likely to 

trigger NSR permitting, which would add substantial time and expense. Commenters stated that 

in addition, neither the S&L Report nor the preamble discussion addresses degradation in heat 

rate resulting from the application of newly retrofitted emissions controls to comply with federal 

and state requirements such as the MATS Rule, in-state and transport regulations related to 

National Ambient Air Quality Standards (NAAQS) attainment and regional haze programs, or 

the increase in cycling operations due to the application of building blocks 2, 3, and 4 of the 

Proposed Rule. Commenters stated that LPPC members report that the existing coal units that 

they own or jointly own already evaluate equipment upgrade measures such as those identified in 

the S&L Report to achieve the best cost-effective heat rate for each unit and the only options to 

significantly improve heat rate through equipment upgrades would be to radically change boiler 

and/or turbine designs, which could trigger NSR concerns. 

Commenters stated that EPA has ignored the realities of parasitic load in the proposed 

Guidelines. Commenters stated that a primary example of parasitic load is the amount of 

electricity consumed by pollution control equipment mandated by other EPA regulations. 

Commenters stated that heat rate improvement projects have been undertaken at facilities, in 

part, to recoup energy lost to increased auxiliary loads from pollution control equipment, for 

instance, the addition of a fabric filter to meet MATS can often require new or larger fans; or a 

water treatment system installed to meet new water discharge limits frequently requires new 

pumps and mixers. Commenters stated that for a large scale pollution control equipment retrofit 

project such as the installation of a scrubber, SCR, or cooling water tower, the increase in 

auxiliary load can be significant. Commenters stated that it is highly likely that the heat rate for 

many generating units will actually increase compared to the 2012 baseline due to increases in 

parasitic load caused by the pollution control retrofits that have been added in response to recent 

EPA regulations such as MATS. Commenters stated that moreover, a lower heat rate does not 

always equate to lower CO2 emissions and in some cases, new pollution control technologies 

may actually increase CO2 emissions. Commenters stated that limestone based wet scrubbers are 

a common design for removal of SO2 and mercury from flue gas, yet this scrubbing process is 

recognized as a source of incremental CO2. Commenters stated that an October 2010 EPA 

document entitled "Available And Emerging Technologies For Reducing Greenhouse Gas 

Emissions From Coal-Fired Electric Generating Units" identifies scrubbing technologies that add 

to a plant's CO2 GHG emissions in addition to increasing the parasitic load. 

Commenters stated that they believe the proposed rule communicates all the benefits of the 

addition of new control technology without assessing the energy penalty associated with those 
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additions. Commenters stated that every new FGD, SCR, or baghouse installed under MATS or 

CSAPR will carry with it a new parasitic load on the unit. Commenters stated that every new 

pump, cooling tower, or intake improvement under 316(b) and every new package treatment 

plant installed to comply with new ELG requirements will entail the same parasitic load loss. 

Commenters stated that to recognize that these units will encounter these new loads yet claim 

that they can somehow achieve a net 6% gain in generating efficiency is, at best, disingenuous. 

Commenters stated that EPA incorrectly assumes that coal-fired power plants will maintain a 

heat rate improvement of 6%. Commenters stated that heat rate at coal-fired generating units will 

gradually increase over time due to natural degradation of key steam and generation components. 

Commenters stated that adding to the natural degradation of heat rate due to aging equipment is 

the significant degradation resulting from the installation of emissions control technologies. 

Commenters stated that for example, the installation of wet limestone scrubbers at several of 

PPL Energy Supply's plants recently resulted in a parasitic load penalty of approximately 20 

MW per station. 

Commenters stated that in a paper presented by Dr. James Staudt at the 2014 A&WMA Mega 

Symposium, he showed that one of the prime factors that impacted the decrease in gross heat rate 

was the installation of new FGD plants up through 2008. Commenters stated that in the second 

chart below you can see a closer relationship between FGD installations and net heat rate. 

Commenters stated that after 2008 there was a significant decrease in the plant capacity factors 

and it is obvious that plant capacity and cycling of loads plays a significant role in heat rate.

Commenters presented a chart, titled: “Capacity factor, FGD Installations, Heat Rate, 2002-

2012”. Commenters stated that a chart (titled: “Impact of FGD Installations on Heat Rate, 2002-

2015”) included in their comments is a different analysis of Dr. Staudt's data by plotting the 

cumulative FGDs. 

Commenters stated that second, EPA would have seen that, rather than opportunities for 

improvement in net heat rate relative to a 2012 baseline, SRP is required to undertake costly 

capital projects merely to avoid significant increases in net heat rate due to the ill-advised air

pollution control requirements imposed by EPA. Commenters stated that in particular, the 

requirement for SCR at Coronado Unit 1 under the Federal Implementation Plan promulgated in 

2012 (77 Fed. Reg. 72,512) is expected to increase net heat rate by at least one percent, 

completely offsetting the potentially achievable improvement in heat rate through an $11.3 

million turbine upgrade at this coal-fired EGU. Commenters stated that thus, there is no 

opportunity for heat rate improvement as this unit. 

Commenters stated that Building block 1 is unachievable because EPA did not consider the 

decrease in heat rate efficiency resulting from power plants complying with the federal Regional 

Haze Program. Commenters stated that in July 1999, EPA promulgated the regulations for the 

Regional Haze Program. Commenters stated that South Dakota submitted its Regional Haze 

Program in January 2011, and EPA approved South Dakota's program in April 2012. 

Commenters stated that the Regional Haze Program required applicable sources to install the 

Best Available Retrofit Technology. 
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Commenters stated that Big Stone Plant is regulated under the Regional Haze Program and was 

thus required to install Best Available Retrofit Technology. Commenters stated that the Big 

Stone Plant is currently retrofitting the boiler with a selective catalytic reduction system and 

separated over-fire-air to control nitrogen oxide emissions. Commenters stated that it is also 

installing a flue gas desulfurization system to control sulfur dioxide emissions, and replacing the 

existing fabric filter with a new fabric filter system to control particulate matter emissions. 

Commenters stated that to power this $384 million air pollution control project, the Big Stone 

Plant will add a significant amount of station service that will degrade heat rate by approximately 

1 to 2 percent when pollution controls come online during the summer/fall of 2015. Commenters 

stated that the Big Stone Power Plant will attempt to minimize this negative impact by 

performing efficiency upgrades in conjunction with the project; however, unless this issue is 

rectified by EPA, the Big Stone Plant will actually be required to improve its heat rate efficiency 

by up to 8 percent under the proposal, when in reality there may not be any improvements 

available. 

Commenters stated that some affected facility owners have added pollution control equipment, 

such as scrubbers and baghouses to meet other emission standards, which consume station power 

when the unit is operating and have the effect of increasing heat rate. 

Commenters were concerned about the lack of discussion afforded "parasitic load" from 

pollution-control equipment mandated by other EPA environmental regulations. Commenters 

stated that these regulations, which include, among others, Mercury and Air Toxics Standards 

("MATS"), National Ambient Air Quality Standards ("NAAQS"), and Section 316(b) of the 

Clean Water Act ("CWA"), mandate that coal-fired units install equipment that may increase 

current parasitic load and thus reduce the efficiency of a power plant. Commenters stated that in 

regard to this concern, EPA asserts: "Like gross heat rate, parasitic load can be addressed both 

through adoption of best practices and through equipment upgrades..." Commenters stated that it

seems the agency believes concerns about parasitic load are limited to the effects of the proposed 

rule, when, in fact, the primary concern is the interaction between the proposed rule and existing 

environmental regulations. Commenters stated that because the denominator for the unit of 

measure EPA uses to assess heat rate is net MWh, rather than the traditionally used gross MWh, 

the addition of pollution controls needed to comply with other EPA regulations were not 

considered when EPA established their emissions targets. Commenters stated that these 

regulations will result in an increase in the CO2 rate (lb/Net MWh) without increasing the actual 

CO2 mass emission from the source and in effect, power producers are being asked to recover 

the heat rate lost from other EPA rules before they start counting efficiency gains towards the 

average 6 percent heat rate improvement. Commenters stated that the proposed rule states: "We 

have therefore not included any separate estimate of parasitic load reductions achievable through 

best practices in their goal-setting data inputs." Commenters stated that by disregarding potential 

reductions in parasitic load that may result from the proposed rule, EPA also disregards expected 

future increases in parasitic load resulting from existing and expected new EPA regulations. 

Commenters believed the greater potential is for net increases in parasitic load.

Commenters agreed with EPA in recognizing that as units drop below full capacity, heat rates 

generally increase, however stated that EPA failed to account for this effect in establishing the 6 

percent heat rate improvement and therefore, EPA inappropriately established BSER. 

Commenters stated that EPA's 6 percent heat rate improvement assumption would effectively 
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become a much larger requirement when considering the impact of increased "auxiliary load" or 

"parasitic load" of additional required pollution controls. Commenters stated that auxiliary load 

is the amount of electricity consumed by EGU components, including pollution-control 

equipment mandated by other EPA environmental regulations. Commenters stated that new 

regulations (Mercury and Air Toxics Standard, National Ambient Air Quality Standard, Cooling 

Water Intakes under Section 316(b) of the Clean Water Act, etc.) mandate that fossil fuel-fired 

units install equipment that may increase auxiliary load and reduce the efficiency of a power 

plant, thereby making the 6 percent heat rate improvement requirement in the Proposed Rule 

actually much larger. Commenters stated that the impact of startup, shutdown, and off-line 

auxiliary load consumption can also be significant. Commenters stated that standardized 

accounting for auxiliary load, and its impact on net generation, needs to be addressed in the Final 

Rule. Commenters stated that the Proposed Rule's baseline year of 2012 does not consider the 

net heat rate impact of NIPSCO's flue gas desulfurization projects that were, or will be, installed 

at R.M. Schahfer Generating Station (RMSGS) Unit 14 (2013) and Unit 15 (2014) and Michigan 

City Generating Station Unit 12 (2015), the RMSGS Unit 15 selective non-catalytic reduction 

project (2013), nor the recent Mercury and Air Toxics Standard (MATS) compliance projects at 

each NIPSCO coal-fired generating station. Commenters stated that when complete, these 

projects will increase auxiliary load by several megawatts and increase the average net heat rate 

and by choosing a base year before these projects were completed, EPA is effectively punishing 

NIPSCO for NIPSCO's ongoing efforts to significantly reduce emissions of sulfur dioxide, 

nitrogen oxides, and mercury. Commenters stated that EPA should take all actions necessary to 

ensure that the Proposed Rule does not adversely impact local pollution reduction and thus 

should exclude CO2 emissions emitted from power supplied to pollution control systems in 

compliance calculations.

Commenters stated that the Agency readily admits that it failed to determine the efficiency of the 

modern coal-fired fleet. Commenters stated that EPA's apparent lack of documented 

consideration of input from those that know most about potential efficiency improvements is 

disconcerting. Commenters stated that EPA has filled a vacuum of information with a faulty 

literature review and unfounded assumptions and that EPA's literature review must be updated to 

address current projects and specific plant closures. Commenters stated that the Agency 

conducted literature reviews of studies that described historical HRI and how they were 

accomplished and of the 17 articles cited by EPA's literature review, only three were published 

after EPA's MATS rule was finalized. Commenters stated that this is especially critical given 

that, since promulgation of EPA's MATS rule in February 2012, some 60,000 MW of coal-fired 

capacity has been announced for closure. Commenters stated that it is likely that 14 of the 17 

articles, therefore, relied on HRI data from certain plants that closed and can no longer make 

HRIs. Commenters stated that a growing number of utility company experts are testifying that 

EPA's proposed HRI requirement is unrealistic, does not recognize the current high efficiency of 

today's coal-fired power plant fleet, and may be unachievable.

Commenters stated that EPA has not accounted for the effects on net heat rate of installing 

additional environmental controls at coal-fired EGUs. Commenters stated that the Agency's 

analysis of historical changes and variability in heat rate are based on observations of gross heat 

rate and do not adequately describe trends in net heat rate, despite the fact that EPA proposes to 

express the proposed emission guidelines in terms of net electricity output. Commenters stated 

that net heat rate depends significantly on the auxiliary load from a unit that is needed to provide 
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power to pollution control equipment, water pumps, and coal pulverizers, among other systems. 

Commenters stated that retrofitting an existing coal-fired EGU with selective catalytic reduction 

(SCR) can increase auxiliary power consumption by 1.5 percent, while adding flue gas 

desulfurization can increase auxiliary load by 1 to 2 percent, depending on coal type. 

Commenters stated that either of these retrofits would yield a corresponding increase in net heat 

rate, and thus an increase in the unit's CO2 emission rate.

Commenters commented on the degradation of efficiency due to other EPA regulations. 

Commenters stated that the Clean Air Visibility Rule (CAVR) requires the application of Best 

Available Retrofit Technology (BART) and these controls were typically scrubbers for SO2 

control and Selective Catalytic Reduction (SCR) for NOx controls. Commenters stated that since 

most of these plans were finalized in 2012, the added controls would not be reflected in the 

baseline heat inputs. Commenters stated that scrubbers and SCRs can increase the heat rate as 

much as 2-3 percent. Commenters stated that within the 2012 heat rate baseline for Building 

Block 1, EPA has not accounted for the additional controls that will be required and thus, to meet 

EPA's 6 percent HRI, some units, such as BART units that require scrubbers and/or SCRs would 

actually be required to achieve even greater HRIs to offset the additional auxiliary loads that will 

decrease the efficiency of the coal-fired unit. 

Commenters stated that by including these heat rate improvement targets in the determination of 

the state's CO2 goal, EPA's Proposed Rule assumes significant future efficiency improvement 

projects but provides no relief from potential New Source Review (NSR) enforcement action by 

the EPA. Commenters stated that the risk of a heat rate improvement project triggering NSR and 

the subsequent imposed cost of Best Available Control Technology and other permitting 

requirements, can result in costs amounting to hundreds of millions dollars. Commenters stated 

that this risk alone renders the heat rate improvement target of 6%, or any level for that matter, 

an unreasonable strategy for reducing CO2 emissions. Commenters stated that EPA should 

amend its proposed rule and make it clear that heat rate improvements made to comply with any 

finalized version of the proposed rule will not trigger NSR. Commenters stated that EPA must 

also make it clear that any improvement projects undertaken to comply with the proposed rule 

are excluded from NSR as routine maintenance, repair and replacement. Commenters stated that 

to the extent that these projects undergo an emissions increase analysis, the NSPS maximum 

achievable emissions rate test should be applied. Commenters stated that this test is only 

triggered by increases in the maximum achievable emissions rate before and after the physical 

change.

Commenters stated that it is of concern that regulated units could find additional efficiencies 

with significant investment and redesign, the investment may result in additional regulation 

under 111(b) as well as 111(d) (as both a new and existing resource). Commenters stated this is 

not a legal action and is contrary to the governing statutes. Commenters stated that any final 

emission guideline that is based in whole or in part on heat rate improvements must provide 

affected EGU's with relief from New Source Review requirements for implementing those 

measures.

Commenters discussed the Interstate Transport (Cross State Air Pollution Rule). Commenters 

stated that the Supreme Court in April 2014 remanded parts of the Cross State Air Pollution Rule 

(CSAPR) back to the DC Circuit Court for reconsideration and at this time, the DC Circuit has 
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not ruled on the reconsideration and other issues petitioned before the Court. Commenters stated 

that however, the Clean Air Interstate Rule (CAIR) is in effect until the CSAPR ruling is 

determined and although the final outcome of the case cannot be determined at this time, both 

interstate transport rules require reduction of SO2 and NOx. Commenters stated that some 

additional controls may be required that would increase heat rates and these heat rate 

degradations have not been included in the 2012 heat rate baseline for Building Block 1. 

Commenters further discussed the Mercury and Air Toxics (MATS) Rule. Commenters stated 

that under MATS, controls for compliance with this rule include new baghouses or ESP retrofits 

for particulate matter (PM) control, scrubbers or dry sorbent injection (DSI) for acid gas control, 

and activated carbon injection or sorbents for mercury controls and these controls can increase 

the heat rate of a coal-fired unit by 1-2.5 percent, and these additional equipment and system 

additions would not be accounted for in the 2012 heat rate baseline for Building Block 1. 

Commenters stated that as proposed, the ELG rule can require physical, chemical, and/or 

biological treatment as well as thermal zero liquid discharge systems and that his additional 

control equipment and systems can increase plant heat rates. 

Commenters stated that the proposed Coal Combustion Residuals (CCR) rule could eliminate 

wet ash handling for both fly ash and bottom ash and a conversion to dry handling could be 

required, which may impact heat rates. 

Commenters stated that they commented on the National Ambient Air Quality Standards 

(NAAQS). Commenters stated that since 2009, EPA has tightened the SO2 and PM2.5 standards, 

and is in the process of lowering the ozone standard. For these new standards, the compliance 

date is beyond 2017 for coal-fired units that are subject to additional controls. Commenters 

stated that these new standards can result in coal-fired units having to install scrubbers, DSI, 

SCR, SNCR, and/or baghouse controls. 

Commenters stated that some states have regulations which are more stringent than the EPA's 

regulations and these regulations can require additional controls that were not accounted for in 

the 2012 heat rate baseline for Building Block 1. 

Commenters stated that utilizing the NEEDS 5.13v3 database as referenced within the EPA's 

Clean Power Plan rule, an analysis was conducted to determine the control equipment that was 

already installed at the existing coal-fired power plant fleet. Commenters provided a chart (titled: 

“Coal-Fired Power Plant Summary based on NEEDS Database 5.13v3”) which presents the coalfired power plant fleet statistics as summarized from the NEEDS database. Commenters stated 

that the addition of environmental control equipment will negatively impact the overall 

efficiency of the unit and as presented in the chart above for the units that were active within the 

database, nearly 26 percent of installed capacity lack scrubber or reagent technology, 50 percent 

of installed capacity lack SCR, and 54 percent of installed capacity lack baghouse technology. 

Commenters stated as these EPA rules-requiring lower emissions at targeted existing coal-fired 

units-are effectuated, additional emissions control equipment will be required and his equipment 

will require significant auxiliary load to operate heat rates will be negatively affected. 
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Commenters stated that EPA's decision in the proposed regulation to apply the heat efficiency 

improvement goal to coal-fired power plants on a net basis is arbitrary and capricious, because it 

doubly penalizes coal-fired power plants. Commenters stated that these plants have recently 

installed new equipment and revised systems to comply with EPA's other recent emission control 

initiatives directed at such plants, all of which have negatively affected heat rates. Commenters 

stated that the controls impose a parasitic load on the plant that degrades net output.

Commenters stated that EPA's projected reductions in heat rate variability are based on a 

statistical study that is not supported by any actual case studies of base-load EGUs that already 

employ best practices of operation and maintenance, nor did EPA consider the performance of 

West Virginia's base-load EGUs that comply with other emission limitation requirements, 

including those of the ARP, CAIR, PSD, CSAPR, and the MATS. Commenters stated that EPA's 

projected four percent reduction in heat rate variability from implementation of best practices of 

operation and maintenance includes reductions that, if at all possible, have already been largely 

realized for the base-load units in West Virginia. Commenters stated that these units are already 

implementing best practices of operation and maintenance to offset heat rate degradation from 

the installation of emission control devices. Commenters stated that EPA's goal of a specific 

percentage CO2 improvement for states is not a reasonable standard given the reality of the 

variable CO2 emissions that can be expected from modern coal-fired EGUs.

Commenters stated that EPA fails to account for the fact that its other regulatory initiatives that it 

has recently imposed on the utility sector will also degrade coal unit efficiency, for example, 

EPA's Mercury and Air Toxics Standards, Cross-State Air Pollution Rule, Effluent Limitation 

Guidelines, and Clean Water Act Section 316(b) Cooling Water Intake Structure Rules, all of 

which will take effect in the next few years are each expected to require existing coal plants to 

install new equipment that will require additional parasitic load, also known as station service, 

that reduces the amount of the "net" electricity generated that can be sold to the grid. 

Commenters stated that as EPA states, "[t]he electric power consumed by air pollution control 

equipment reduces the overall efficiency of the EGU." Commenters stated that as more and more 

equipment at the facility requires more and more of the electricity generated, less electricity will 

be available for distribution, resulting in a lower net heat rate. Commenters stated that since 

EPA's goal calculation is based on pounds of CO2 per net megawatt-hour, the increase in 

parasitic load required by EPA's many other rulemakings will present a direct impediment to 

achieving the 6 percent efficiency improvement that EPA desires. Commenters stated that EPA 

fails to account for this drop in efficiency in claiming that a 6 percent improvement is 

achievable. 

Commenters stated that EPA's assessment that plants can undertake projects to improve 

efficiency by 2% across the nation is incorrect. Commenters stated that as consumer owned 

utilities, they have an obligation to provide all possible cost savings to customers and cost 

effective efficiency investments are regularly assessed and undertaken when financially prudent. 

Commenters stated that the first building block assumes that a 4 to 6% reduction in carbon 

emissions can be achieved on each electric generating unit through tuning and improved burner 

efficiency. Commenters stated that in an effort to keep costs as low as possible for their 

customers they do regular maintenance on their generating units to keep them operating as 

efficiently as possible. Commenters stated that although they may be able to gain some modest 
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reduction, it will more than likely be offset by the additional house power required to operate a 

bag house, scrubber, and other equipment required by the MATS rule that are currently being 

installed on their facility. Commenters stated that as a result of adding this equipment, it will 

require additional house power to generate each megawatt and therefore, the carbon emitted per 

net megawatt will increase making it all the more difficult to achieve a reduction per net 

megawatt as the proposed rule assumes can be done. 

Commenters stated that as previously noted, converting EGUs to cleaner fuels, or installing 

pollution control equipment, will change the base heat rate for individual EGUs and therefore the 

achievability of building block 1. Commenters stated that in addition, there are also other actions 

that will affect EGU heat rates (such as the new cooling water discharge regulations under 40 

CFR part 316) which may also decrease EGU efficiency. Commenters stated that an EGU may 

also switch from bituminous to subbituminous fuel to reduce SO2 emissions. Commenters stated 

that the rule must somehow account for and allow these changes which affect heat rates and at a 

minimum, states should be able to make these adjustments to their building block 1 goal. 

Commenters stated that EPA's current approach penalizes EGUs that have implemented 

pollution control equipment. Commenters stated that EGUs that have implemented controls to 

comply with other federal regulations such as the Clean Air Interstate Rule (CAIR), the Best 

Available Retrofit Technology rule (BART) and the Mercury and Air Toxics Standards rule 

(MATS) are less efficient on a net heat rate basis (i.e., have a higher heat rate) due to the 

parasitic load of their environmental controls. Commenters stated that uncontrolled EGUs have 

lower heat rates and therefore would not have to improve their heat rates as much after applying 

the 6% HRI. Commenters stated that therefore, applying a 6% HRI (or other fixed HRI 

percentage) to all units is inequitable and penalizes those EGUs that have already installed 

pollution control equipment.

Commenters stated that in addition, future federal criteria pollutant standards may require 

existing pollution control equipment to be operated more frequently or require additional EGUs 

to install controls. Commenters stated that States should also not be penalized for complying 

with any future CAA regulations, which will cause their EGUs to lose efficiency on a net basis.

Commenters stated that the best and most appropriate means of addressing these issues is to 

eliminate HRI actions for pollution control equipment from building block 1. Commenters stated 

that both the states and utilities must be free to respond to pollution control requirements outside 

of any CO2-related requirement. 

Commenters stated that the installation of additional pollution controls such as those required by 

regulations including regional haze rules and MATS, will decrease the heat rate efficiency of any 

unit as compared to its heat rate efficiency before the installation. Commenters stated that even if 

EGUs can improve the heat rate using any of these improvements the rules needs to stipulate that 

it will not trigger a New Source Review. 

Commenters stated that compliance with MATS can be accomplished through technologies such 

as wet and dry scrubbers, dry sorbent injection systems, activated carbon injection systems and 

fabric filters and that these additional plant controls increase plant heat rates that will offset some 

portion of the heat rate improvements required by the proposed rule. 
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Commenters stated that environmental rules and actions, such as the Mercury and Air Toxics 

Standards (MATS) and Cross State Air Pollution Rule (CSAPR) that will result in heat rate 

degradation were not taken into account. 

Commenters stated that as EPA is well aware, other environmental regulations, such as the 

Mercury and Air Toxics Standards and the Cross-State Air Pollution Rule, required many 

existing coal plants to implement emissions reduction projects. Commenters stated that these 

projects frequently result in a decrease in the unit's gross output and/or an increase in the unit's 

auxiliary load: both of which increase the unit's net heat rate. Commenters stated that EPA failed 

to consider heat rate increases from these emission reduction projects when determining the heat 

rate improvement that can be achieved by the implementing coal units. Commenters stated that 

EPA should revise its assumptions about heat rate improvement potential to account for the 

effects on heat rate of compliance with other environmental regulations.

Commenters stated that EPA did not consider the parasitic load and lost efficiency of new 

emission control systems required by the Mercury and Air Toxic Standard (MATS) and other 

new and potential regulations including cooling water standards, regional haze, and fine 

particulates. Commenters stated these problems illustrate the danger in a state relying on heat 

rate improvements as high as 6% in their plans to achieve the rule's goals.

Commenters stated that EPA is well aware that other air regulations have required additional 

emission controls and thus substantially increased parasitic load and increased heat rates and 

accordingly, this worsening of the heat rates negates any improvements resulting from specific 

projects. 

Commenters that the parasitic load necessary to operate controls required by the 2012 MATS 

Rule, BART requirements, or other CAA obligations will increase a unit's net heat rate, making 

EPA's heat rate improvement target under Building Block 1 much more difficult to achieve. 

Commenters stated that complying with more stringent traditional environmental regulations 

regarding air and water quality and once through cooling will have a detrimental effect on heat 

rate.

Commenters stated that in technical support documents, EPA frequently mentions prior heat rate 

improvement studies as the source for information about technologies and improvement 

opportunities. Commenters stated that nearly all of the studies, however, are at least four years 

old and predate recent environmental regulations such as the Mercury and Air Toxics Standards 

(MATS) that will require many units to add additional pollution control technologies which will 

negatively affect heat rate.

Commenters stated that EPA also attempts to look at the entire "existing" pool of coal fired units 

for heat rate improvement opportunities, however, these studies were completed prior to the 

significant round of coal fired plant retirements that have occurred in the last 2-5 years as a result 

of lower natural gas prices, increased generation from renewables, and costly control retrofits to 

meet new pollution standards. 

Commenters stated that compliance with EPA's Mercury and Air Toxics Standards (MATS) 

requires additional plant controls which increase plant heat rates and as EPA notes, controls for 
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sulfur dioxide and acid gases could increase heat rates and CO2 emissions. See Abatement 

Measures Technical Support Document (TSD) at 2-4. Commenters stated that EPA's own 

analysis indicates that many coal-based units will install dry scrubbers or upgrade currently 

installed scrubbers to comply with the MATS. Commenters stated that Empire is currently 

installing pollution control systems which reduce net generation and increase net heat rates. 

Commenters stated that the EPA did not, but should, take into account the efficiency degradation 

that will occur as a result of adding equipment required under current and proposed EPA 

regulations when establishing state emission targets. 

Commenters stated that implementing measures to ensure that New Source Review (NSR) 

concerns do not discourage heat rate improvements at existing coal-fired power plants. 

Commenters stated that capital projects designed to assist with unit efficiency improvements 

have historically been the subject of litigation filed by EPA and third party environmental groups 

against coal-fired electric utilities. Commenters stated that in the Proposed Rule, EPA explains 

that a state could "develop conditions for a source expected to trigger NSR that would limit the 

unit's ability to move up in the dispatch enough to result in a significant net emissions increase 

that would trigger NSR (effectively establishing a synthetic minor limit)," in other words, EPA 

suggests that fossil fuel-fired units can avoid triggering NSR by limiting their utilization such 

that there is no increase in annual emissions. Commenters stated that EPA's proposal that some 

sources could avoid NSR through synthetic minor limits is not a viable option. Commenters 

further stated that increases in heat rate due to air quality control equipment installed due to other 

federal regulations. Commenters stated that for example, it appears EPA did not consider the 

decrease in heat rate efficiency resulting from power plants complying with the federal Regional 

Haze Program. 

Commenters stated that EPA also failed to consider the heat rate ramifications of other 

regulations. Commenters stated that post-combustion controls to remove pollutants and improve 

environmental performance require energy to operate and so reduce a unit's net heat rate. 

Commenters stated that new regulations are expected to have a considerable impact on the 

existing coal fleet, particularly MATS and pending 316(b) regulations under the Clean Water 

Act. Commenters stated that achieving 6 percent efficiency gains while adding additional 

environmental protections unrelated to the CPP may not be possible for the fleet. 

Commenters stated that increased environmental requirements for emissions control equipment 

result in additional onsite energy demands due to the parasitic load, leading to overall net energy 

losses at the generating unit, and federal environmental regulations such as the Mercury and Air 

Toxics Standards (MATS) and the Cross-State Air Pollution Rule (CSAPR) compliance retrofits 

affect all of Consumers Energy's coal-fired units post 2016. Commenters stated that with the 

significant capital expenses undertaken by Consumers Energy to comply with MATS and 

CSAPR, EPA must recognize that they have already invested in improving the efficiencies of the 

coal units and additional large efficiency improvements are not possible. Commenters stated that 

it is in the best interests of Consumers Energy and its customers to be as efficient as possible. 

Commenters stated that many existing coal plants will be required to implement emission 

reduction projects to comply with the Mercury and Air Toxics Standards (MATS), Cross State 

Air Pollution Rule (CSAPR), Consent Decrees and other environmental regulations and these 

projects frequently decrease a unit's gross output and/or increase the unit's auxiliary load, both of 
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which will increase the unit's net heat rate. Commenters recommended to consider heat rate 

increases from emission reduction projects when determining the heat rate improvement that can 

be achieved by units that are required to implement these projects.

Commenters stated that EPA's argument presupposes that such coal-fired EGUs will be able to 

be kept in operation long enough to reap the benefits of equipment upgrades. Commenters stated 

that when considered in conjunction with retrofit demands imposed by other EPA programs, 

including the onerous MATS regulations, the high upfront costs of installing heat rate 

improvement equipment are all-the-more unreasonable in a regulatory setting that is highly 

inhospitable for coal-fired EGUs. Commenters stated that specifically, due to EPA's repeated 

failure to acknowledge the continued viability of coal as a vital energy source for the country, 

coal-fired power plant operators are unlikely to be able to shoulder such retrofit costs without 

affirmation that their investments will bear fruit over the long-term. 

Commenters stated that they are concerned about the lack of discussion afforded "parasitic load" 

in the proposed CPP. Commenters stated that parasitic load is the amount of electricity 

consumed by EGU components, including pollution-control equipment mandated by other EPA 

regulations. Commenters stated that these regulations, which include, among others, Mercury 

and Air Toxics Standards ("MATS"), National Ambient Air Quality Standards ("NAAQS"), the 

Cross State Air Pollution Rule ("CSAPR"), and Section 316(b) of the Clean Water Act 

("CWA"}, mandate that coal-fired units install equipment that may increase current parasitic 

load and thus reduce the net efficiency of a power plant. Commenters stated that in regard to this 

concern, EPA asserts: "Like gross heat rate, parasitic load can be addressed both through 

adoption of best practices and through equipment upgrades ... " Commenters stated that it seems 

the agency believes concerns about parasitic load are limited to the effects of the proposed rule, 

when, in fact, the primary concern is the interaction between the proposed rule and existing 

environmental regulations. Commenters stated that because the denominator for the unit of 

measure EPA uses to assess heat rate is net MWh, rather than the traditionally used gross MWh, 

the addition of pollution controls needed to comply with other EPA regulations were not 

considered when EPA established their emissions targets. Commenters stated that these 

regulations will result in an increase in the CO2 rate (lb/Net MWh) without increasing the actual 

CO2 mass emission from the source. Commenters stated that in effect, power producers are 

being asked to recover the heat rate lost from other EPA rules before they start counting 

efficiency gains towards the average 6 percent heat rate improvement. Commenters stated that 

the proposed rule states: "We have therefore not included any separate estimate of parasitic load 

reductions achievable through best practices in their goal-setting data inputs." Commenters 

stated that by disregarding potential reductions in parasitic load that may result from the 

proposed rule, EPA also disregards expected future increases in parasitic load resulting from 

existing and expected new EPA regulations.

Commenters stated that they provide a specific example illustrating this point. Commenters 

stated that their IKEC-Clifty Creek Station's two JBR FGD scrubbers installed to comply with 

CSAPR and MATS regulations came on line in March and May of 2013, a year after the baseline 

year used by EPA as its base case year for heat rate in its proposed CPP. Commenters stated that 

when these FGD systems came on line, the auxiliary, or "parasitic", power needs to operate this 

advanced pollution control system has been estimated at approximately 2 to 2.5% of the plant 

output. Commenters stated that this effectively means that this facility has an additional 2-2.5% 
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heat rate "deficit" to dig out of under the proposed CPP because, the rule, as currently drafted 

does not provide a credit for this type of real-world "parasitic" power need. Commenters stated 

that they believe it is clearly not the only power plant in this situation, and EPA's failure to take 

these real world examples of "parasitic load" into account is, by its very nature, is a deficiency in 

the proposed CPP that they ask the EPA to address in any future subsequent rulemaking. 

Commenters stated that a problem with EPA's BSER approach to block one is that EPA largely 

fails to consider the impact of implementing the other blocks as well as other environmental 

regulations. Commenters stated that for example, although EPA acknowledges that parasitic load 

from pollution control devices can reduce coal units' efficiency, EPA has failed to take into 

account the potential limits that running this pollution control technology could have on potential 

heat rate improvements (and the resulting CO2 emission reductions) that the Agency states are 

available from the 2012 baseline.

Commenters stated that EPA does not consider the adverse heat rate impacts of implementing 

new pollution control measures, such as those that are necessary to comply with the MATS Rule 

or the Cross-State Air Pollution Rule. Commenters stated that for example, their Cross 1 and 2 

units were originally designed to include three scrubber modules per unit, with an original goal 

of two being actively utilized at a time with one remaining as a backup. Commenters stated that 

however, to comply with recent environmental regulations, these units must now use all three 

modules simultaneously. Commenters stated that operating all three modules requires additional 

power to be diverted to pumps, fans, and other ancillary equipment, thus increasing the units' 

heat rate and CO2 emissions while decreasing the emissions of other pollutants. Commenters 

stated that EPA should consider the cumulative impacts of its environmental regulations on 

affected EGUs, and should revise its block one approach to explicitly account for the impact that 

other pollution measures could have on operators' ability to improve heat rate and thereby reduce 

CO2 emissions at existing EGUs. 

Commenters stated the underlying goals in each building block are not required in a state's 

compliance plan, however the goals in each building block must be based on what is 

technologically achievable in each state. Commenters said for example, with regard to building 

block 1, EPA's analysis in the development of the six percent HRI target is flawed because EPA 

failed to take into consideration several factors, including: (1) industry actions to maintain the 

efficiencies of these units in the normal course of business, (2) that installation of back-end air 

pollution control technology for compliance with the MATS Rule will have a negative impact on 

heat rates, and (3) the redispatch of NGCC units along with increased deployment of renewables 

will cause coal-fired power plants to operate less, thereby decreasing the efficiency of these units 

as well as the cost-benefit associated with investing in HRIs. 

Commenters said minimizing heat losses is the most significant factor affecting plant efficiency 

and, therefore, GHG emissions associated with energy production; however, there is 

considerable debate regarding the reality of EPA's estimates of a 6% improvement being 

achievable with the current coal fleet, since some of these coal facilities have already made 

efficiency improvements in order to meet other state or federal standards. Commenters said any 

further improvements, whether from best practices or equipment upgrades, certainly will not 

equate to 6% "on average" and will not come without significant cost, if at all.
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Comment 36: Applicable to the supplemental proposal for Tribal and Territorial – Comments 

regarding the potential for HRI to be offset by the effects of various add-on pollution 

controls installed to comply with other rules

Response 36: See section V.C of the final rule preamble of the CPP and Chapter 2 of the GHG 

Mitigation Measures TSD supporting the final CPP for EPA’s response to this comment.

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

Commenters stated that although the study did identify some projects that could be implemented 

on the Four Corners units to further improve the heat rate, these minor improvements must be 

considered in light of the degradation in efficiency that will result from the parasitic load of 

pollution control projects required to comply with the Regional Haze rule, such as SCR controls 

and a stack liner. Commenters stated that this parasitic load will negatively impact unit heat rate 

and result in a maximum potential efficiency improvement no greater than 1.6 percent. 

Commenters stated that heat rate degradation due to future compliance requirements must be 

accounted for, in addition to any available heat rate improvement potential and that accordingly, 

each coal-fired unit should be assessed considering the actual heat rate improvement projects that 

can be completed, and any projects required by other environmental regulations that result in 

parasitic loads should be discounted. 

Comment 37: Applicable to the supplemental proposal for Tribal and Territorial - Units with 

large heat rate changes

Response 37: See section V.C of the final rule preamble of the CPP and Chapter 2 of the GHG 

Mitigation Measures TSD supporting the final CPP for EPA’s response to this comment.

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

Commenters stated that in its statistical analysis EPA found a large number of facilities with 

year-to-year heat rate variability in excess of +/-8.5% and a large portion of this was explained 

by changes in reporting methods. Commenters stated that Staudt's independent analysis also 

found a high degree of "noisiness" and large changes in heat rates between periods (two different 

three-year periods were examined) for some units that are not explained and much of the data, 

therefore, have a degree of "noisiness" that is unexplained and may be simply due to reporting 

errors, changes in reporting or other inaccuracies. Commenters stated that while some 

improvements in heat rate may be possible, until this "noise" in the data is better understood and 

other questions raised in these comments about the EPA analysis are addressed, heat rate 

variability as used in EPA's analysis is not a reliable means to arrive at a good, quantitative 

estimate of heat rate improvement potential. 
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Comment 38: Comments regarding EPA's assessment of heat rate improvement potential via 

best practices

Response 38: For the EPA’s response to these comments, see section V.C of the final rule 

preamble of the CPP and Chapter 2 of the GHG Mitigation Measures TSD supporting the final 

CPP. The heat rate improvement measures discussed there are merely illustrative of some of the 

measures that can improve heat rate at EGUs, and is not intended to be an exhaustive list.

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

Commenters stated that EPA's assumptions regarding the magnitude of improvements in gross 

heat rate achievable through adoption of best practices for operation and maintenance are invalid. 

Commenters stated EPA assumes that heat rate improvements are achievable through "practices 

such as turning off unneeded pumps at reduced loads, installation of digital control systems, 

more frequent tuning of existing control systems, or earlier like-kind replacement of worn 

existing components." Commenters stated although it is true that these practices may improve 

heat rate performance at a given EGU at which they have not already been implemented, EPA 

has provided no data or information that connects these practices to its assumptions regarding 

achievability, costs, and overall reasonableness of improvements in gross heat rate. Commenters 

stated that instead, EPA's estimate of a 4% across-the-board improvement reflects nothing more 

than an arbitrary fraction of the variability in hourly heat input which EPA believes it has 

observed in the data set for its "study population."

Commenters cited: "Assuming that between 10 percent and 50 percent of the deviation from top 

decile performance in each subset of hourly heat rate observations within defined ranges of 

temperature and load could be eliminated through adoption of best practices, the result is a 

corresponding estimated range of 1.3 percent to 6.7 percent technical potential for improvement 

in the average heat rate of the entire fleet of coal-fired EGUs. Based on this analysis, we believe 

a reasonable estimate for purposes of developing state-specific goals is that affected coal-fired 

steam EGUs on average could achieve a four percent improvement in heat rate through adoption 

of best practices to reduce hourly heat rate variability. This estimate corresponds to the 

elimination, on average across the fleet of affected EGUs, of 30 percent of the deviation from 

top-decile performance in the hourly heat rate for each EGU not attributable to hourly 

temperature and load variation."

Commenters stated in addition to the analysis of hourly data discussed above, EPA offers 

another explanation for its assumption that 4% improvement in gross heat rate is achievable, 

based on a more simplistic analysis of data for the same "study population" and cited "[I]f each 

unit achieved heat rate performance equal to its best three-year moving average, the study 

population as a whole would post a 3.9% heat rate improvement."

Commenters stated this explanation is similar to, but even less technically supportable than, the 

first. Commenters stated that one example involving a unit at which a change in coal source was 

implemented will illustrate the problem with EPA's conclusion: at CGS Unit 2, which SRP owns 

and operates, the average gross heat rate from 2004 through 2006 was 9,257 British thermal units 

per kilowatt-hour (Btu/kWh), the best three-year average for this EGU during EPA's study 

period. Commenters stated that following a switch to Powder River Basin (PRB) coal, the 
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average gross heat rate from 2007 through 2011 was 9,827 Btu/kWh and this represents an 

increase in gross heat rate of approximately 6%, at least in part due to the higher moisture 

content of PRB coal. Commenters stated that the only sensible conclusions that can be drawn 

from these data with respect to Building Block 1 are that switching to a high-moisture coal, such 

as PRB coal, causes an increase in heat rate, which can be reversed by switching to a lowmoisture coal. Commenters stated EPA incorrectly characterizes this change as "heat rate 

variability" which can be reversed through "practices such as turning off unneeded pumps at 

reduced loads, installation of digital control systems, more frequent tuning of existing control 

systems, or earlier like-kind replacement of worn existing components." Commenters stated that 

having failed to identify the cause of the increase in heat rate (switching to PRB coal) and the 

potentially available method of reversing it (switching to low-moisture coal), EPA fails to assess 

the economic and non-GHG environmental impacts of this technique for improving heat rate.

Commenters stated that EPA's calculation of a 4% HRI from best management practices (BMPs)

is speculative and while EPA's analysis uses data points through an analysis of 884 units in the 

Air Markets Program, EPA erroneously concludes that high variability in heat rate values 

indicates opportunities for HRI across the board. Commenters stated that EPA provided no 

engineering analysis or data to support the notion that variable heat rate values demonstrate that 

BMPs are lacking throughout the industry or at any given unit and in fact, EPA's methodology 

failed to even measure actual BMP (or lack thereof) at the highest performing units. 

Commenters stated that for the best practices portion of its assumption, EPA analyzed the hourly 

data these plants reported to the EPA from 2002-2012, which included hourly heat input and, for 

most EGUs, hourly gross generation. Commenters stated that after analyzing this data, EPA 

determined a range of 1.3% to 6.7% potential for improvement in the average heat rate of the 

entire national fleet of coal-fired EGUs as a result of best practices, with each of the best 

practices assumed to additively improve heat rate and EPA then arbitrarily determines that a 

"reasonable" estimate of heat rate improvement is 4% without justifying why 4% (rather than say 

3.8% or 4.2%) is "reasonable." 79 Fed. Reg. at 34,859. Commenters stated that EPA makes the 

arithmetic assumption that higher heat rate units can improve their efficiency to more closely 

resemble lower heat rate units without accounting for the many types of coal-burning 

technologies. Commenters stated that EPA lists examples of best practices, including turning off 

unneeded pumps at reduced loads, installation of digital control systems, more frequent tuning of 

existing control systems, or earlier like-kind replacement of worn existing components. 

Commenters stated that however, in arriving at its projection, EPA did not assess which plants in 

a state can or already have adopted these measures, rather, it has simply analyzed aggregated 

data, assumed that all improvements are achieved additively, and then drawn its conclusion. 

Commenters stated that in determining the appropriate target under Building Block 1, EPA first 

examined the level of emission reductions that has been demonstrated at existing units, then 

determined the additional reductions that have been demonstrated to be achievable from plant 

upgrades. Commenters stated that in quantifying the O&M component of Block 1, EPA 

reasonably considered the level of performance that each unit has demonstrated in the past. 

Commenters stated that the agency first looked at the hourly average heat rate for essentially all 

(96 percent) of the units in the system between 2002 and 2012, correcting for differences in heat 

rate that could be correlated to temperature and load. EPA then calculated what would happen to 

the average heat rate at each unit if the heat rate at every given hour were reduced by a specified 
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percentage of the difference between the heat rate for that hour and the average heat rate for the 

top 10 percent of all hours for that unit. Commenters stated that EPA reports that a fleet wide 

improvement of 1.3 percent would result if units, on average, reduced their heat rate by 10 

percent of the difference between the average and top decile heat rates and that reducing heat 

rates by 50 percent of that difference would produce a 6.7 percent improvement fleetwide. 

Commenters stated that EPA acknowledges that its selection of 30 percent of the difference 

between the average and top decile heat rates (resulting in a 4 percent heat-rate improvement 

fleet wide) is conservative, justifying its selection with the observation that it is in the middle of 

the range (10 to 50 percent) that EPA chose to analyze and notably, EPA does not justify its 

choice of a range to analyze. Commenters stated that had the agency chosen to analyze a range of 

30 to 70 percent, for instance, the mid-point of its chosen range would be 50 percent. 

Commenters stated that EPA acknowledges that a 50 percent reduction in the difference between 

the fleet's average and top decile rates would yield a 6 percent heat rate improvement fleet-wide 

and the agency rationalizes its decision to select a lower figure of 30 percent by analogizing to a 

standard based on a three-year rolling average rather than a rolling annual average. Commenters 

stated that EPA notes that plants would achieve a 6.7 percent heat-rate improvement if they were 

to meet their top rolling annual average over the 11-year study period and a 3.9 percent 

improvement if they were to meet their best rolling three-year average. Commenters stated these 

numbers correspond fairly closely to the 6 and 4 percent improvements that would result from 50 

and 30 percent reductions (respectively) in the difference between the annual and top decile heat 

rates. Commenters stated that EPA then states that a hypothetical selection of the three-year 

rolling average would be more appropriate than a rolling annual average due to potential 

differences in weather and load; hence, it avers that a 30 percent reduction between the average 

and top decile heat rates (analogous to a three-year rolling average) is a superior target than a 50 

percent reduction (analogous to a rolling annual average). 

Commenters stated that EPA's reasoning here is flawed and as noted above, EPA already 

controls its data pool for temperature and capacity factor. Commenters stated that to select a 

more lenient standard in order to smooth out difference in weather and load is, in effect, double 

controlling for these variables, and is a methodological error. Commenters stated that 

furthermore, in actuality, differences in temperature profiles and loads from one year to the next 

are relatively small and are not large enough to justify the EPA accommodation. Commenters 

stated that EPA's analogy to annual vs. three-year rolling averages is inappropriate, and the 

agency has not justified its decision to select a 30 percent rather than 50 percent reduction 

between the average and top decile heat rates as the basis for its calculations. Commenters stated 

that the agency correctly focuses on annual averages and here, too, differences in annual 

temperature profiles and load are relatively small and are not large enough to justify the EPA 

accommodation. Commenters stated that accordingly, each of EPA's analyses demonstrates that 

a 6 percent fleet-wide improvement is achievable and that its choice of 4 percent is overly 

conservative. 

Commenters agreed with UARG that EPA's "model" assessing potential heat rate improvements 

via "best practices" is arbitrary and capricious. Commenters stated that in this "model," the 

Agency grouped hourly heat input data into "bins" representing ranges of load and ambient 

temperature, then performed crude calculations to reduce the variation among observations in 

each bin by arbitrary increments of 10, 20, 30, 40, and 50 percent. Commenters stated that EPA 
335

used these adjusted values to calculate an adjusted heat rate for each unit, then compared the 

study population's average adjusted heat rate under each scenario to the population's actual 

average heat rate in order to determine the "improvement" under each scenario, with a roughly 

30 percent reduction in each unit's variation corresponding to a 4 percent improvement in the 

overall study population's heat rate. Commenters agreed with UARG that this conclusion is 

arbitrary and unfounded. Commenters stated that absent from EPA's analysis is any discussion 

linking the 4 percent "best practices" estimate to any identifiable, technically feasible heat rate 

improvement measures. Commenters stated that at most, EPA's discussion shows that a 4 percent 

reduction in overall heat rate is mathematically feasible if sources can find a way to reduce 

variation in hourly heat input. Commenters stated the Agency makes no attempt to show whether 

the measures it identifies as "best practices" are technically capable of reducing heat input 

variation at individual units at all, let alone reducing variation to a sufficient degree to reach the 

target efficiency level. 

Commenters stated that EPA's so-called "statistical analysis" of heat rate improvements available 

through "best practices" is fundamentally flawed and does not support EPA's chosen target of 4 

percent. Indeed, it does not support any estimate of heat rate improvements at individual units or 

for the fleet as a whole. In particular, EPA's "model" assessing potential heat rate improvements 

via "best practices" is unfounded, arbitrary and capricious, and misleading. In this "model," EPA 

grouped hourly heat input data into "bins" representing ranges of load and ambient temperature,

then performed crude calculations to reduce the variation among observations in each bin by 

arbitrary increments of 10, 20, 30, 40, and 50 percent. Id. at 2-30 to 2-31. The Agency used these 

adjusted values to calculate an adjusted heat rate for each unit, then compared the study 

population's average adjusted heat rate under each scenario to the population's actual average 

heat rate in order to determine the "improvement" under each scenario, with a roughly 30 percent 

reduction in each unit's variation corresponding to a 4.0 percent improvement in the overall study 

population's heat rate. Id. at 2-31. Accordingly, EPA "conservatively" proposed to find that a 4 

percent improvement in heat rate is achievable by applying "best practices" of EGU operation 

because that level "is in the middle of the range of options" that EPA explored. Id. at 2-34. 

Commenters further stated that as detailed in the attached report by UARG's consultants, this 

conclusion is arbitrary and totally unfounded. J. Edward Cichanowicz & Michael C. Hein, 

"Critique of EPA's Statistical Evaluation Defining Feasible Heat Rate Improvements," at 8-9 

(Dec. 1, 2014) (Attachment E) ("Cichanowicz Statistical Critique"). Conspicuously absent from 

EPA's "analysis" is any discussion linking the 4 percent "best practices" estimate to any 

identifiable, technically feasible heat rate improvement measures. See Id. at 9. At most, EPA's 

discussion shows that a 4 percent reduction in overall heat rate is mathematically feasible if 

sources can find a way to reduce variation in hourly heat input. The Agency makes no attempt to 

show whether the measures it identifies as "best practices" are technically capable of reducing 

heat input variation at individual units at all, let alone reducing variation to a sufficient degree to 

reach the target efficiency level. Indeed, as UARG's consultants note, if EPA had undertaken 

such an analysis it would have realized that the 9 "No Cost or Low Cost Options" the Agency 

identified as "best practices" are incapable of achieving such reductions as a technical matter. 

Each individually offers 0.1 to 0.35 percent improvement at most, and several of these options 

have benefits that are not additive. Id. at 10. Moreover, the 10, 20, 30, 40, and 50 percent 

reductions in heat input variation that EPA calculates at each unit do not represent varying 

implementation levels of "best practices" measures: they were apparently selected without any 
336

technical basis. Thus, EPA's decision to "conservatively" select a level of reduction that is "in the 

middle of the range of options" it arbitrarily chose is itself arbitrary. GHG Abatement Measures 

TSD at 2-34.

Commenters described in detail Figure 2 (titled: “Representation of EPA Model to Quantify Heat 

Rate Benefits”) in the 2014 GHG TSD and then stated that EPA decided - on an arbitrary basis -

that by adopting so-called "best practices" the heat input for each data point could be reduced by 

30% of the difference between that observed and the "p10" value - in other words, the required 

heat input for any data point could be reduced by 30% of the value incurred beyond the "p10" 

value. Commenters then stated that EPA provides no justification for assuming that, for any 

given operating conditions, the same power output can be achieved using heat input that is 

reduced from observed levels by 70% of the value beyond the lowest 10% of the data. 

Commenters stated that a rigorous analysis to determine fleet-wide savings could theoretically be 

conducted, but would require a scope of data that EPA does not have access to on a national 

basis. Commenters explained that key components of such a study would be boiler thermal 

efficiency and heat recovery, steam turbine design, and managing off-peak auxiliary load with 

advanced control software and that calculations could model the behavior over the load range 

and determine an outcome for each unit, but that this clearly requires site-specific data that only 

the operator has access to. Commenters concluded that the statistical analysis performed by EPA 

is inadequate to capture the complexities of the factors that define plant heat rate over an 11-year 

period. 

Commenters stated that EPA expects the adoption of best practices to yield an average 4 percent 

improvement in heat rate. Commenters stated that this number is overly ambitious and that 

utilities already have a significant financial incentive to locate and eliminate inefficiencies in 

their operations. Commenters stated that any inefficiency resulting from suboptimal operating 

practices represents a potential financial loss for the plant owner, thus, many Indiana plant 

operators have already implemented what they believe to be the best practices. Commenters 

stated that EPA argues that "[h]eat rate improvements yield important benefits to affected 

sources by reducing their fuel costs." Commenters stated that they agree with this 

characterization, and it is for precisely this reason that mandating additional heat rate 

improvements merely reinforces an existing incentive structure. Commenters stated that the idea 

that Indiana utilities are deliberately overlooking potential improvements in their operations in 

the status quo is unsubstantiated and counter-intuitive, yet, it is precisely this assumption upon 

which EPA's proposal for large improvements relies.

Commenters said that the EPA derives the 4% HRI by sorting data from each unit into "bins," 

finds the 10th percentile value in each bin, and reduces all of the other values in the bin by a set 

percentage (10, 20, 30, 40, 50) of the difference between that value and the 10th percentile value. 

Commenters asked:

1. What was the EPA's technical basis for selecting these percentage reductions?

2. Do these represent the use of specific HRI measures? 

Commenters summarized that EPA said that "...[b]y applying best practices to their operating 

and maintenance procedures owners and operators of EGUs could reduce heat rate variability 
337

relative to average heat rates and, because deviations generally result in performance worse that 

optimal heat rates, improve the EGUs' average heat rate." Commenters then stated that to justify 

the proposed 4% HRI attributable to best practices, EPA apparently identified 355 coal-fired 

EGUs that had heat rate variations of 8.5 % or more from year to year and further stated that 

remarkably, EPA finds "...that approximately two-thirds of the large decreases in heat rate can be 

associated with changes in reporting methods implemented to provide more accurate heat input 

data. Commenters stated that the large changes noted at the remaining one third could not be 

explained by changes in reporting methodology" but that EPA fails to factor this finding that the 

majority of heat rate variation originated with faulty reporting methods into its matrix analysis. 

Commenters stated that this failure to factor in reporting variabilities is a fundamental flaw.

Commenters stated that regarding the matrix itself, EPA constructs a 168-bin matrix to identify 

coal-fired EGU BP HRI potential and that it reasons that, "other factors held equal, the range of 

variation indicates that significant potential for heat rate improvement is available through 

application of best practices." Commenters stated that the known factors EPA believes contribute 

to heat rate variation that it holds constant are unit capacity factor and ambient temperature and 

that EPA determines through a regression analysis that 26 percent of heat rate variation is due to 

temperature and capacity factor, and to determine the portion of the remaining 74 percent that 

can be ascribed to best practices, EPA constructs its 168-bin matrix containing 14 temperature 

bins and 12 capacity factor bins, for a total of 168 bins. Commenters stated that it then arbitrarily 

assumes that, for each generating unit, the same output can be produced by reducing the heat 

input by 30 percent of the difference between the reported value and the value that represents the 

top 10 percent (the 10th percentile lowest heat rates) in each bin, to arrive at a 4% HRI due to 

best practices across the fleet. Commenters stated that EPA fails to provide any rational basis for 

this methodology and questions if it is only coincidence that when the 30-percent factor is 

applied to the reported bin values, the resulting best practice HRI just happens to equal the 4 

percent that EPA incorrectly derived from the 2009 S&L study as attributable to best practices.

Commenters stated that EPA clearly recognizes that reporting errors, recalibration, and other 

factors significantly affect fleetwide heat rate data, but the Agency apparently made no attempt 

to explain how these types of errors were accounted for in the 168bin study, or if not why not. 

Commenters stated that clearly the matrix analysis is an arbitrary exercise not supported by any 

technical explanation and thus cannot be accorded any weight. 

Commenters also stated that EPA's analyses and conclusions are completely arbitrary and 

unsupported and that EPA's calculations to reduce the difference between the 10th percentile 

heat rate and less efficient heat rates by 10, 20, 30, 40, and 50 percent are not connected or 

correlated to any set of best practices. Commenters stated that, while EPA has listed generic best 

practices such as "turning off unneeded pumps at reduced loads," "installation of digital control 

systems," "more frequent turning of existing control systems," and "earlier like-kind replacement 

of worn existing components," the Agency makes no attempt to apply these generic practices 

within the bin analysis described above, and, moreover, the Agency has failed to establish that 

these practices are technically feasible across affected sources and in fact are capable in and of 

themselves of achieving the estimated heat rate improvements. 

Commenters stated that for the "best practices" analysis, EPA examined affected EGU hourly 

heat rate data for 884 coal-based EGUs for the years 2002-2012 to determine the amount of 

variability in heat rates across the existing fleet. See Id. at 34,860. Commenters stated that 
338

recognizing that ambient temperature and hourly load levels (capacity factors) have a direct 

impact on a unit's heat rate and are outside a unit's control, EPA grouped the hourly data into 

"bins" to attempt to control for these variables. See GHG Abatement Measures Technical 

Support Document at 2-15 (Abatement Measures TSD). Commenters stated that the Agency 

assumed that any remaining variability in heat rate data in the various bins would be "an 

indication of the degree of technical potential to improve the consistency with which optimal 

heat rate performance is achieved by adopting operating and maintenance best practices." 79 

Fed. Reg. at 34,860. Commenters stated that for each bin, EPA then calculated a "top decile" 

heat rate performance - presumably the heat rate of the 10th percentile lowest value in each bin. 

See Id. at 34,860. Commenters stated that EPA further calculated a range of 1.3 to 6.7 percent 

"technical potential for improvement of the average heat rate of the entire fleet of coal-fired 

EGUs" by "assuming that between 10 percent and 50 percent of the deviation from top decile 

performance in each subset of hourly heat rate observations within defined ranges of temperature 

and load could be eliminated through adoption of best practices." Id. at 34,860. Commenters 

stated that based on this analysis, EPA concluded that: A reasonable estimate for purposes of 

developing state-specific goals is that affected coal-fired steam EGUs on average could achieve a 

four percent improvement in heat rate through adoption of best practices to reduce hourly heat 

rate variability. Commenters stated this estimate corresponds to the elimination, on average

across the fleet of affected EGUs, of 30 percent of the deviation from top-decile performance in 

the hourly heat rate for each EGU not attributable to hourly temperature and load variation. 

Commenters stated that in short, the proposed four percent "best practices" reduction in average 

coal-based unit heat rate rests most heavily on the assumed 30 percent factor applied by EPA in 

the Agency's bin analysis. Commenters stated that in the absence of a clearly articulated basis for 

this 30 percent value, it can only be described as arbitrary, rendering the resulting four percent 

HRI mandate arbitrary as well. 

Commenters stated that EPA's bin analysis is flawed and does not demonstrate that most heat 

rate variability is caused by O&M practices. Commenters stated that as a preliminary matter, 

EPA's assumption that reduced variability in heat rate implies improvement in a unit's heat rate 

fails to understand what "variability" is. Commenters stated that variability is change relative to 

an average value, not relative to an optimal (in the case of heat rate, minimal) value. 

Commenters stated that nevertheless, EPA conducted a regression analysis of 884 generating

units and concluded that units with more variable heat rates tend to have higher heat rates. See 

Abatement Measures TSD at 2-22. Commenters stated that even if this is true, the regression 

analysis only identified the relationship between variability and higher heat rates; it did not 

identify the cause of the variability, and that in other words, correlation is not causation. 

Commenters stated that EPA assumes that the cause must be deficient O&M, but there are other 

factors that could cause this variability that EPA did not address. Commenters stated that EPA 

cited nine different categories of factors influencing heat rate. See Abatement Measures TSD at 

2-4 to 2-5. EPA's analysis attempted to partially account for some of these, including load factor 

(capacity factor) and ambient temperature. Commenters stated that as NERC has noted, EPA's 

regression analysis did not adjust for factors that have a "profound" effect on the process 

efficiency of a coal-based EGU, including boiler design; unit size and age; and coal quality 

variations. See Initial Reliability Review at 8. Commenters stated that EPA's only attempt to 

recognize and control for the range of factors that might affect heat rate variability is to assume 

that 30 percent (instead of 50 percent) of the variability observed in bin data is caused by O&M 

practices. Commenters stated that no analysis supports this assumption and assigning the cause 
339

of 30 percent of the variability to O&M practices, therefore, is arbitrary. Commenters stated that 

accordingly, EPA's analysis did not identify the cause of the observed variability in heat rates. 

Commenters further stated, if heat rate variability cannot be attributed to O&M practices, EPA 

has no basis for asserting that O&M "best practices" will result in HRI of four percent. 

Commenters also stated that EPA's assumption that fleet-wide, existing coal-based units can 

improve heat rates by four percent through O&M "best practices" is not supported by the 

Agency's assessment of recent heat rate data and, therefore, is not reasonable. EPA's "best 

practices" analysis begins with the premise that any variability in a unit's heat rate represents an 

opportunity to improve heat rate and reduce emissions. See Id. at 34,860. Commenters stated that 

EPA further assumes that most heat rate variability can be attributed to deficient O&M practices 

and, therefore, can be eliminated through improved O&M practices. Commenters stated that 

while EPA is correct that improved heat rates result in reduced emissions from coal-based EGUs 

on a rate basis, see Id. at 34,905, EPA has failed to produce a reasoned analysis to quantify how 

much average heat rates can be improved by implementing additional O&M measures. 

Commenters stated that many factors contribute to heat rate variability; some of these are outside 

the control of the unit operator and can never be eliminated. Commenters stated that more 

importantly, EPA's assumption that improved O&M can ameliorate most variation in heat rate 

ignores the existence of these other factors and is not supported by any analysis. Commenters 

stated this undermines EPA's determination that a four percent HRI is both reasonable and 

economic. 

Commenters stated that EPA's analysis demonstrates that, even after attempts to control for load 

factor via the bin analysis, load factor is a very important determinant of heat rate for units with 

varying load. [See Abatement Measures TSD at 2-25.] Commenters stated that the bin analysis 

reduced the effect of load factor changes, but each bin itself includes a 10 percent range of load 

factors. [See Abatement Measures TSD at 2-24 to 2-25.] Commenters stated that an International 

Energy Agency (IEA) report found that a 10 percent change in load factor can result in a four 

percent change in heat rate. Commenters stated that thus, the bin approach reduced, but did not

eliminate, the very significant impact of variable load factor on heat rate. Commenters stated that 

as explained in detail in EEI's comments on the proposed CO2 standards for new units, load 

factor (capacity factor) has an inverse relationship to heat rate for fossil-based EGUs. See 

Appendix C at 4-5. Commenters stated the higher the load factor, the lower the heat rate. 

Commenters stated that lower capacity factors or increased cycling increase heat rates and 

increase heat rate variability. Commenters stated that in the integrated electric system, units are 

dispatched to respond to load, following economic merit order principles and consistent with 

reliability requirements, thus reducing generator control over specific dispatch levels. 

Commenters stated that unit owners and operators, therefore, cannot control load factor to 

address concerns about heat rate. Commenters stated that if the variation within bins is 

significantly influenced by load factor, less variability would be amenable to improvement via 

O&M practices, and, such variability may not be able to be addressed by O&M practices at all.

Commenters stated that EPA's data and conclusions do not match. Commenters stated that first, 

EPA makes several unfounded assumptions about the coal-fired EGU fleet that fail to account 

for significant variations in geography, fuel diversity, electricity demand, age, and design of 

individual facilities. Commenters stated these variables affect heat rate and, thus, the potential 

for efficiency gains through best operating practices. 
340

Commenters summarized EPA's approach to determine estimated efficiency gains of 4% from 

best operating practices Commenters stated that EPA then estimated a range of 1.3% to 6.7% in 

potential untapped gains across the entire coal-fired EGU fleet that could be achieved through 

changes in operating practices. And from this range, EPA decided that, on average, coal-fired 

EGUs could reasonably achieve a 4% heat rate improvement. Commenters stated that EPA based 

its 4% figure on a series of erroneous assumptions. Commenters stated that EPA first assumed 

that, other than ambient temperature and operating load, which account for only 26% of the 

variability in heat rate efficiencies across the fleet, any other variation was within the control of 

the plant operator. Commenters stated that however, this assumption fails to account for other 

factors that explain most of the unaccounted for variability, and which are not within the 

operator's control. Commenters stated that for example, existing coal-fired EGUs are spread 

across varying geographic and climatic zones and facilities that operate in more extreme 

climates, e.g., the Northeast and Southwest, are likely to be dispatched for longer continuous 

periods, resulting in higher attainable efficiencies. Commenters stated that moreover, facilities 

located at higher altitudes operate in relatively oxygen-deprived environments, resulting in 

higher heat rates - i.e., lower efficiencies and yet EPA failed to account for these variables, a 

perplexing omission considering that EPA itself conceded that geographic and environmental 

conditions impact efficiency.

Commenters stated that fuel diversity in a given area also affects heat rate. Commenters stated in 

regions where baseload capacity is spread across coal, nuclear, and natural gas facilities, coalfired facilities will cycle more often, meaning they operate at higher heat rates. Commenters 

stated that overall electricity demand is also a factor. Higher demand means less cycling and, 

thus, higher operating efficiency and EPA similarly fails to account for variations in heat rate 

among different types and ages of facilities, even while acknowledging that larger units tend to 

operate more efficiently than smaller ones. 

Commenters stated that the Nation's coal-fired fleet is anything but monolithic and yet, by 

prescribing an across-the-board 4% efficiency improvement through best operating practices, 

EPA papers over important differences in geography, climate, electric demand, fuel composition, 

and facility design and age. Commenters stated that its conclusion that a 4% heat rate 

improvement is achievable through best practices is therefore arbitrary and capricious. 

Commenters stated that, to support its determination that best practices could achieve a four 

percent net heat rate improvement at coal-fired EGUs, EPA analyzed hourly gross heat rate data 

from approximately 884 coal- and petroleum coke-fired units from 2002 to 2012, but that EPA's 

analysis, does not support its conclusion. Commenters then described EPA's methodology and 

concluded that EPA "conservatively" claimed four percent was achievable because it was in the 

middle of EPA's arbitrary range of options.

Commenters stated that EPA made overly simplistic assumptions concerning the ability of likesituated plants to reduce heat input for every megawatt hour generated. Commenters stated that 

EPA divided the existing coal fleet into a variety of bins based on ambient temperature and load 

and presumed that each power plant in each bin could improve their performance by an arbitrary 

30 percent relative to the best performing plants in that bin. Commenters stated that EPA 

provides no justification for such an assumption and that in fact, units already have an incentive 

to operate as efficiently as possible. Commenters stated that because EPA's assumption 
341

concerning best practices is not supported, it leads to an arbitrary conclusion that coal fired 

power plants can improve heat rate by four percent. 

Commenters stated that EPA's assumption that a 4% heat rate improvement is available based on 

use of operating best practices is inaccurate. Commenters stated that the existing coal units that 

they own or jointly own already employ best practices to achieve the best possible heat rate for 

each unit and significant improvements in efficiency through the adoption of best practices are 

not possible. Commenters stated that for example, operators utilize a heat rate team, including an 

engineer, that monitors heat rate on a daily basis; have heat rate reviews performed annually by 

independent external resources; have maintained and calibrated instrumentation to track unit 

performance; have personnel training on heat rate performance; utilize heat rate improvement 

plans and goals to achieve the best attainable heat rate; conduct performance testing on key unit 

components; and use unit-specific procedures for maintaining and improving heat rate. 

Commenters stated that operations and maintenance practices already include "turning off 

unneeded pumps at reduced loads, installation of digital control systems, more frequent tuning of 

existing control systems, or earlier like-kind replacement of worn existing components," as well 

as regular checks for air leakage and overhauls of major equipment, and these measures are cited 

by EPA as methods that, taken together, would shrink the heat rate gap between the average 

coal-fired steam EGU and the top decile of such units by 30%. LPPC's member utilities, whose 

customers own their public power systems, already have every incentive-the most important 

being to keep customers" rates low-to operate facilities as efficiently as possible. 

Commenters stated that EPA determined the fleet-wide potential for the two types of HRI using 

fundamentally different analyses. Commenters stated that both of these approaches are flawed, 

resulting in overly optimistic projections for fleet-wide HRI that may result in state emission rate 

targets that are unachievable. Commenters stated that EPA's approach to costs and fuel also 

overestimates the value of fuel costs savings to an affected EGU. Commenters stated that EPA 

should revise the analyses used to determine the potential fleet-wide HRI that could result from 

both O&M "best practices" and equipment upgrades. Commenters stated that in addition, EPA 

should revise the HRI goals for any state that can show that EPA's assumptions about HRI 

potential are flawed with respect to the existing fossil-based units in that state and at minimum, 

EPA should address state-specific concerns about the proposed emission rate goals before 

finalizing these goals. Commenters stated EPA should work with the states to set achievable 

state goals that reflect in-state conditions.

Commenters stated that EPA's assumption that fleet-wide, existing coal-based units can improve 

heat rates by four percent through O&M "best practices" is not supported by the Agency's 

assessment of recent heat rate data and, therefore, is not reasonable. Commenters stated that 

EPA's "best practices" analysis begins with the premise that any variability in a unit's heat rate 

represents an opportunity to improve heat rate and reduce emissions. Id. at 34,860. Commenters 

stated that EPA further assumes that most heat rate variability can be attributed to deficient 

O&M practices and, therefore, can be eliminated through improved O&M practices. 

Commenters stated that while EPA is correct that improved heat rates result in reduced emissions 

from coal-based EGUs, see Id. at 34,905, EPA is not correct in stating that all heat rate 

variability can be eliminated. Commenters stated that many factors contribute to heat rate 

variability; some of these are outside the control of the unit operator and can never be eliminated 

and more importantly, EPA's assumption that improved O&M can ameliorate variation in heat 
342

rate ignores the existence of these other factors and is unsupported by any analysis. Commenters 

stated that this undermines EPA's determination that a four percent HRI improvement through 

O&M best practices is both reasonable and economic. Id. at 34,860. 

Commenters stated that EPA's assumptions about Operating "Best Practices" is incorrect, as 

exemplified by their units. Commenters stated that EPA's initial assumption that a 4% heat rate 

improvement is available based on use of operating best practices is unreasonably 

ambitious. Commenters stated that EPA identifies operations and maintenance practices such as 

"turning off unneeded pumps at reduced loads, installation of digital control systems, more 

frequent tuning of existing control systems, or earlier like-kind replacement of worn existing 

components" as methods that, collectively, would shrink the heat rate gap between the average 

coal-fired steam EGU and the top decile of such units by 30%. Commenters stated that however, 

most utilities, including their plant, already run their fleet as efficiently as possible, making 

significant further improvements through best practices impossible. Commenters stated that 

indeed, most utilities, including theirs, have a staff of engineers and technicians dedicated to 

finding and implementing efficiency improvements and keeping these units running as 

efficiently as possible. Commenters stated that indeed, Sargent & Lundy itself concludes that "it 

appears that most of the utilities are employing best operational and maintenance practices. 

Commenters stated that in light of this observation, it appears that significant further reduction in 

heat rate, such as that assumed by the EPA, may not be feasible."

Commenters stated that in their case, EPA-identified "best practices" such as turbine and boiler 

feed pump overhauls, as well as regular checks for air heater seals and ductwork leaks, are 

already routine aspects of their plant operating procedures. Commenters further stated that all of 

their EGUs now use digital control systems that allow them to monitor unit efficiency in real 

time and to analyze data on a daily basis to find and correct unit inefficiencies. Commenters 

stated that as a result, all of their coal units - even those as old as Winyah Unit 1, which was built 

in 1971 - are operating very near design values. Commenters stated that the comprehensive best 

management practice spreadsheet, included in Appendix A, demonstrates that they are already 

implementing most of the "best practices" identified by EPA in the Proposed Rule. 

Commenters stated that EPA's conclusions as to efficiency improvements from O&M activities, 

however, are not based on a review of the potential effectiveness of available O&M practices, 

instead, EPA's 4 percent conclusion depends on the stated assumption that reducing the 

variability of coal unit heat rates is possible through "best practices" and that reducing that 

variability will lead to better performance. Commenters noted that, as EPA states, "using heat 

rate variability as an indicator of the application of best practices and potential for 

improvement." Commenters stated that although EPA claims it has accounted for all sources of 

heat rate variability, in fact EPA really only accounts for two--operating load and ambient 

temperature. Commenters stated that according to EPA's own analysis, these two factors explain 

only 26 percent of heat rate variability. Commenters stated that EPA assumes that the other 

"residual" 74 percent of heat rate variability must be within the control of unit operators and so 

can be improved, but EPA's assumption ignores numerous causes of heat rate variability that are 

beyond the ability of coal-fueled EGU operators to control, such as: 

(i) Variability in coal quality, (i.e. heat content (Btu's) and moisture).

(ii) Variability in pollution control efficiency and electricity demand.
343

(iii) Variability in other ambient and weather conditions.

(iv) Variability attributable to unavoidable cycles in the degradation of components that 

wear out over time (e.g., air heater baskets, pulverizer rollers, baghouse bags, cooling 

tower fill, etc.).

(v) Variability attributable to changes in heat rate calculation methods.

(vi) Variability based on unit characteristics that cannot be replicated at other facilities.

Commenters stated that EPA's analysis thus fails to account for all the possible source of heat 

rate variability and also fails to address the potential cumulative effect of all of those factors 

together and in short, EPA has not provided sufficient or rational support for its assumption that 

the "residual" variability in existing coal unit heat rates can be eliminated through the 

implementation of improved O&M practices. 

Commenters stated that EPA claims that improvements in O&M activities alone can achieve, on 

average, a 4 percent improvement in efficiency at all existing coal-fired units. Commenters 

stated that the preamble to the Proposed Rule indicates that this category of activities includes 

measures such as such as "turning off unneeded pumps at reduced loads, installing digital control 

systems, more frequent tuning of existing control systems, or earlier like-kind replacement of 

worn components."

Commenters stated that EPA's conclusions as to efficiency improvements from O&M activities, 

however, are not based on a review of the potential effectiveness of available O&M practices at 

all, instead, EPA's 4 percent conclusion depends on the assumption that reducing the variability 

of coal unit heat rates is possible through "best practices" and that reducing that variability will 

lead to better performance. Commenters stated that, as EPA states, "using heat rate variability as 

an indicator of the application of best practices and potential for improvement." Commenters 

stated that although EPA claims it has accounted for all sources of heat rate variability, in fact 

the Agency accounts for only two--operating load and ambient temperature. Commenters stated 

that according to EPA's own analysis, these two factors explain only 26 percent of heat rate 

variability. EPA assumes that the other "residual" 74 percent of heat rate variability must be 

within the control of unit operators and so can be improved. Commenters stated that EPA's 

assumption ignores numerous causes of heat rate variability that are beyond the ability of coal 

units to control, such as:

(i) Variability in coal quality, (i.e. heat content (Btus) and moisture). Commenters stated 

that EPA recognizes, for instance, that coal rank quality can have an impact on heat rate,

and that reducing coal moisture through drying can improve heat rate (which confirms 

that high moisture can degrade heat rate. 

(ii) Variability in pollution control efficiency and electricity demand (which can also be 

affected by variability in coal quality). Commenters stated that although EPA recognizes 

that pollution controls can affect heat rate, EPA fails to recognize the unavoidable 

variability inherent in the operation of those controls.

(iii) Variability in other ambient and weather conditions that can impact heat rate, such as 

humidity and rainfall (which can affect the temperature of the cooling water resource and 

the moisture of the coal. Commenters stated that although EPA recognizes that 

barometric pressure and cooling water temperature affect heat rate, EPA fails to account 

for anything other than air temperature in its analysis. 
344

(iv) Variability attributable to unavoidable cycles in the degradation of components that 

are designed to wear out over time (e.g., air heater baskets, pulverizer rollers, baghouse 

bags, cooling tower fill, etc.). Commenters stated that although EPA recognizes that 

component replacements can improve heat rate, EPA fails to account for the varying, 

rates of degradation of

components over time that can affect heat rate variability. 

(v) Variability attributable to changes in heat rate calculation method. Commenters stated 

that EPA recognizes that, of the 355 units with large year-to-year changes in heat rate, 

two-thirds of those large changes were attributable to changes in reporting method. EPA, 

however, continues to count the data affected by those changes in reporting method in its 

calculations. 

(vi) Commenters stated that EPA fails to recognize that some plants may have lower heat 

rate variability for otherunavoidable reasons, which may skew the data based on unit 

characteristics that cannot be replicated at other facilities. 

Commenters stated the Proposed Rule fails to account for known sources of heat rate variability 

and also fails to address the potential cumulative effect of those factors together. Commenters 

stated the Proposed Rule is simply not based on a rational assumption that the "residual" 

variability in existing coal unit heat rates can be eliminated through the implementation of 

improved O&M practices. 

Commenters objected to requiring specific technology as a means to meet performance 

measures, because by requiring that specific best practices be incorporated, rather than allowing 

the industry to innovate and adopt technologies to meet certain targets, the agency would be 

stifling the knowledge creation and entrepreneurship needed to meet current and future 

challenges. Commenters stated that realistically, it is not the job or area of expertise of the 

USEPA to know all EGU-specific operating environments, management and the stage of 

depreciation or life of existing equipment to be able to estimate how well the prescribed practices 

would perform at each site.

Commenters stated that EPA's "best practices" analysis assumes that any variability in a unit's 

heat rate represents a correctable flaw that can be fixed by improving an inadequate O&M 

program - in other words, EPA claims that variability can be reduced through better O&M 

practices and that lower variability will result in an improvement in heat rate. Commenters 

stated that the analysis assumes that existing O&M practices are inadequate, and EPA has 

provided no evidence to support that assumption and EPA also fails to consider dozens of factors 

that contribute to heat rate variability, many of which are outside of the control of the 

operator. Commenters stated that since EPA only considered two of those factors, and ignored 

many more, its claim that a four percent heat rate improvement is achievable on a fleet-wide 

basis through O&M practices remains unsupported. 

Commenters stated that EPA's detailed statistical analyses fail to support its 

assumptions. Commenters stated that EPA analyzed hourly heat rate data over a 10-year period 

for a number of EGUs and although EPA controlled for variability in heat rate associated with 

ambient temperature and capacity factors, EPA assumed that all of the remaining variability 

could be controlled through operating and maintenance best practices. Commenters stated that 

under that assumption, EPA concluded that EGUs on average could eliminate 30 percent of the 
345

deviation from top-decile performance that is not attributable to hourly temperature and load 

variation. 

Commenters stated that EPA's analysis, however, fails to explain why it assumed that most heat 

rate variability in the sampling is caused by O&M practices, thus ignoring other sources of 

uncontrollable variability, such as unit size, steam conditions, thus, the key assumption in EPA's 

analysis is also its key flaw. Commenters stated that rather than assuming that all heat rate 

variability beyond that associated with temperature and load is attributable to O&M, EPA should 

have attempted to determine what portion of variability is directly attributable to poor O&M 

practices. Commenters stated that EPA should also have considered other factors that could 

have skewed its analysis, such as: 

• Heat rate increases related to the installation of pollution control technologies 

required by other EPA regulations;

• Changes in equipment replacement practices for units scheduled to retire in the 

near future, some of which will likely be attributable to EPA's Proposal;

• Implementation of best O&M practices during the 10-year study period that are 

now already in place, but were not in effect during a significant portion of the 

study. 

Commenters stated that EPA's determination that a 4 percent heat rate improvement is 

achievable by implementation of these "best practices" is arbitrary and capricious. For example, 

EPA has listed generic measures such as "turning off unneeded pumps at reduced loads," 

"installation of digital control systems," "more frequent turning of existing control systems," and 

"earlier like kind replacement of worn existing components" to support its 4 percent 

improvement rate. 79 Fed. Reg. at 34,860. Commenters stated that yet, EPA provides no actual 

evidence that those measures can bring about such an improvement. Commenters stated that 

rather, EPA assumes that the difference in heat rate between the most efficient coal-fired EGUs 

and less efficient EGUs can be minimized by implementing operating and maintenance best 

practices. Commenters stated that EPA apparently believes that most coal units across the 

country operate in a persistent degraded and inefficient state and that to the contrary, they

already engage in many measures to ensure Lowman's efficiency. Commenters stated that these 

activities attempt to restore and/or improve equipment efficiency while balancing consumer costs 

and reliability. Commenters stated that as routine maintenance occurs, an attempt to restore or 

increase efficiency is made to minimize the amount of heat rate degradation. Commenters stated 

that for them, having a large contention of low-income, rural residential consumers, it is very 

cost-conscious and therefore they take extra care to operate as efficiently as possible. 

Commenters stated that the proposed rule includes 4% HRI related to maintenance and operating 

practices that is based on an unsubstantiated statistical analysis. Commenters stated that serious 

flaws in that statistical analysis include several coal-fired units listed with gross efficiencies over 

42% which is impossible; while others are listed with heat rates under 20% - very unlikely. 

Commenters stated that another serious flaw is EPA's assumption that 30% of the heat rate 

variance from the top decile is associated with controllable operating and maintenance practices 

that would be cost effective to perform. Commenters stated that EPA fails to consider that what 
346

may be cost effective in a state with regulated markets with a guaranteed rate of return on 

investments may not be "cost-effective" in states with competitive markets where market prices 

determine what is "cost-effective." Commenters stated that EPA only adjusted the data for 

ambient temperature and capacity factor, however, there are many factors other than 

maintenance and operating practices that likely contributed to heat rate variability on the units in 

the dataset. Commenters stated that these include, among others, heat rate improvement projects 

(that results in a double impact because they are included as potential operating practice heat rate 

improvements when, in fact, they are heat rate improvement opportunities that have already been 

completed); capacity factor changes within the EPA bands; fuel switching; and additions of 

environmental controls. 

Commenters stated that EPA expects the adoption of best practices to yield an average 4 percent 

improvement in heat rate and that this number is overly ambitious; utilities already have a 

significant financial incentive to locate and eliminate inefficiencies in their operations. 

Commenters stated that any inefficiency resulting from suboptimal operating practices represents 

a potential financial loss for the plant owner, thus, many plant operators have already 

implemented what they believe to be the best practices. Commenters stated that any with the 

competitive nature surrounding the dispatch of the electricity, sources need to optimize their 

performance or run the risk of being priced out of power markets. 

Commenters stated that EPA lists examples of best practices, including turning off unneeded 

pumps at reduced loads, installation of digital control systems, more frequent tuning of existing 

control systems, or earlier like-kind replacement of worn existing components; however, it has 

made no attempt to actually determine which plants in a state have already adopted these 

measures. Commenters stated that rather, it has simply analyzed aggregated data from which it 

has drawn an unsupported conclusion and incorporated the conclusions into state goals.

Commenters stated that there are concerns about EPA's analysis. Commenters stated that EPA's 

conclusion that a 4 percent improvement using "best practices" is possible at no or low cost was 

based upon an analysis of more than 800 units, using what EPA describes as statistical process 

control methods. Commenters stated that for each unit, the gross heat rate in a given hour over an 

11-year period was compared against hourly ambient temperature data and hourly average load 

as a percent of maximum load. Commenters stated that EPA calls this latter variable a "capacity 

factor", although others consider a capacity factor as averaged over a much longer time. 

Commenters stated that the degree to which the heat rate for the unit is consistent or inconsistent 

over the 11-year period for any given temperature and hourly average load is, according to EPA, 

a measure of how well or how poorly the facility is being controlled. Commenters stated that a 

well-controlled unit should, EPA argues, have a very consistent heat rate under a given ambient 

temperature and average hourly load. Commenters stated that to the extent that there is scatter in 

gross heat rate data for any given hourly load or temperature condition over this 11 year period, 

EPA considers that a sign that more consistent process control can improve heat rate. 

Commenters stated that it appears that EPA meant that plants could be better controlled with 

neural networks. Commenters stated that many plants already have a neural network control 

system and an upgrade to a plant without such a system may see a heat rate improvement of 0.75 

to 1.5 percent.
347

Commenters stated that however, the statistical approach EPA used did not consider any 

technical aspects of the facility, or if any characteristics changed over the 11-year period, 

including a change in operating mode (switching from base load to cycling), whether the facility 

conducted a retrofit (installing low nitrous oxides burners, selective catalytic reduction 

installations, scrubbers, new burner or furnace management systems), or if the facility changed 

coals or any other characteristics of the fuel. Commenters stated that EPA also did not compare 

units against one another or do any sort of subcategorization. Commenters stated that 

unfortunately, because there are many more factors that impact heat rate that are beyond the 

operator's control than just ambient temperature and average hourly load, and because EPA did 

not factor changes to the plant over that 11-year period, EPA's statistical approach likely mistook 

the effects of these other parameters and changes to the plant as indicators of poor process 

control.

Commenters stated that moreover, most power plants are already equipped with statistical 

process control systems that monitor thousands of plant parameters and are designed to optimize 

operation of the plant. Commenters stated that EPA's analysis that only looked at two parameters 

is much less reliable than the advanced process optimizers that are already installed at the plants. 

Commenters stated that the methodology used by EPA in determining the amount of heat rate 

improvement from operating and maintenance optimization is flawed. Commenters stated that 

EPA states that "by applying best practices to their operating and maintenance procedures, 

owners and operators of EGUs could ... improve the EGUs' average heat rates" by an average 

magnitude of 4%. Commenters stated that in particular, EPA's Heat Rate technical support 

document (TSD) assumes that observed variability in hourly heat rates is entirely the product of 

sub-optimal plant operating practices, ambient air temperature and load factor. Commenters 

stated that such an assumption is flawed as it fails to acknowledge that ambient conditions other 

than temperature and load factor are important determinants of heat rate. Commenters stated that 

moreover, EPA's analysis presumes the perfect accuracy of all data used in its analysis, despite 

the fact that such data cannot accurately be measured on a consistent basis thus, EPA's 

calculation of achievable heat rate improvements and its associated state goals are erroneous and 

must be withdrawn. 

Commenters stated that in its proposal, EPA stated that "... [b]y applying best practices to their 

operating and maintenance procedures owners and operators of EGUs could reduce heat rate 

variability relative to average heat rates and, because deviations generally result in performance 

worse than optimal heat rates, improve the EGUs' average heat rate." 79 Fed. Reg. at 34,860. 

Commenters stated that EPA then justified this statement and its proposed 4% HRI by providing 

examples of 335 coal-fired EGUs that had heat rate variations of 8.5% or more each year. 

Commenters stated that from this review, EPA concluded that "...other factors held equal, the 

range of variation indicates that significant potential for heat rate improvement is available 

through application of best practices." GHG Abatement Measures 2- 30. Commenters stated that 

EPA then determined through a regression analysis that 26% of heat rate variation is generally 

due to temperature and capacity factors. Commenters stated that in order to determine the 

remaining portion of the 74% that could then be attributed to best practices, EPA constructed a 

168-bin matrix, containing 14 temperature bins by 12 capacity factor bins. Commenters stated 

that EPA then arbitrarily and capriciously assumed that for each EGU the same output can be 

produced by reducing the heat input by 30% of the difference between the reported value
348

representing the top 10% in each bin -therefore arriving at a 4% HRI across the entire EGU fleet 

contributed to best practices. Commenters stated that EPA does not provide any additional 

explanation or rational basis to support this matrix methodology and it is not supported by any 

technical explanation. Commenters stated that therefore, the 4% HRI assumption should not be 

afforded any weight. Id. 

Commenters stated that EPA claims that improvements in O&M activities alone can achieve, on 

average, a 4% improvement in efficiency at all existing coal-fired EGUs. Commenters stated that 

the preamble to the Proposed Rule indicates that this category of activities includes measures 

such as "turning off unneeded pumps at reduced loads, installing digital control systems, more 

frequent tuning of existing control systems, or earlier like-kind replacement of worn 

components."

Commenters stated that EPA's conclusions as to efficiency improvements from O&M activities, 

however, are not based on a review of the potential effectiveness of available O&M practices at 

Montana EGUs at all. Commenters stated that instead, EPA's 4% conclusion depends on the 

untested assumption that reducing the variability of coal unit heat rates is possible through "best 

practices" and that reducing that variability will lead to better performance. Commenters stated 

that EPA relies nearly exclusively on "using heat rate variability as an indicator of the 

application of best practices and potential for improvement."

Commenters stated that although EPA claims it has accounted for all sources of heat rate 

variability, in fact EPA accounts for only two-operating load and ambient temperature. 

Commenters stated that according to EPA's own analysis, these two factors explain only 26% of 

heat rate variability. Commenters stated that EPA assumes that the other "residual" 74% of heat 

rate variability must be within the control of unit operators and so can be improved but that 

EPA's assumption ignores numerous causes of heat rate variability that are beyond the ability of 

coal-fueled units to control, such as: (1) variability in pollution control efficiency and electricity 

demand; (2) variability in coal quality, (i.e., heat content (Btus) and moisture); 3) variability in 

other ambient conditions and weather; 4) variability attributable to unavoidable cycles in the 

degradation of components that are designed to wear out over time; and 5) variability attributable 

to changes in heat rate calculation method. 

Commenters stated that EPA's anticipated improvement in heat rate for coal power plants 

through best practices is too optimistic. Commenters stated that a skilled statistician can 

"demonstrate" many points using selected data and various tools, however, when these results 

are developed, you still need to do a reality check. Commenters stated that in the case of EPA's 

analysis, it appears that a check against the laws of thermodynamics was not done. Commenters 

stated that using a statistical analysis that presumes that a well-controlled coal unit should have a 

very consistent heat rate under a given ambient temperature, and an average hourly load over the 

eleven-year period that was evaluated, EPA reached the conclusion that a 4% improvement in 

heat rate was possible on average by increased the use of no or low cost best practices. 

Commenters stated that variability in gross heat rate that was not explained by these two 

variables was regarded as an opportunity to improve heat rate. Commenters stated that 

unfortunately, this approach does not adequately address all of the factors beyond the operator's 

control that impact heat rate. Commenters stated that over this period, many facilities made 

significant changes to their plants in response to environmental regulations that would impact 
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heat rate including changes in fuel, changes in load distribution, addition of new equipment, etc. 

Commenters stated that in the statistical analysis used by EPA, variability in heat rate resulting 

from these other factors that are beyond the operator's control is mistaken as variability that can 

be improved through best practices modifications. Commenters stated that as a result, the 

analysis by EPA reaches an incorrect conclusion about the opportunities to improve heat rate 

through best practices. 

Comment 39: Comments stating that potential heat rate improvement through best practices is 

not achievable

Response 39: The response to comments regarding reliability is addressed in section 8.0. For

the EPA’s response to the remainder of these comments, see section V.C of the final rule 

preamble of the CPP and Chapter 2 of the GHG Mitigation Measures TSD supporting the final 

CPP. Among other things, with respect to concerns about individual EGUs or groups of EGUs, 

the final CPP provides states the flexibility to develop plans with emission standards that more 

precisely take into account the potential heat rate improvement of individual EGUs—should 

states desire to consider potential heat rate improvement at all. Furthermore, if an affected EGU 

cannot meet the particular emission standard solely because it has below-average potential to 

reduce emissions through heat rate improvements, then in instances where the EGU’s state plan 

allows emissions trading, the EGU can acquire credits or allowances from affected EGUs that 

have above-average potential.

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

Commenters stated that the methodology used by EPA assumed the variability in heat rate of 

EGUs is directly correlated to operating practices of the units. Commenters stated that however, 

EPA doesn't identify a specific efficiency gain that corresponds to a specific operating practice. 

Commenters stated that EPA does point out operating practices, such as, shutting down 

unneeded pumps, installing digital control systems, more frequent tuning of existing control 

systems, and more frequent change out of like-kind replacement components, but EPA does not 

identify a corresponding efficiency gain by these actions. Commenters stated that in the 

Proposed Rule, EPA states:

"Assuming that between 10 percent and 50 percent of the deviation from top decile 

performance in each subset of hourly heat rate observations within defined ranges of 

temperature and load could be eliminated through adoption of best practices, the result is 

a corresponding estimated range of 1.3 percent to 6.7 percent technical potential for 

improvement in the average heat rate of the entire fleet of coal-fired EGUs."

Commenters stated that based on EPA's language, it is clear that EPA is uncertain whether a four 

percent efficiency gain can be achieved with better practices. Commenters are certain, however, 

that they cannot achieve this magnitude of efficiency gain on the EGUs because they already 

employ the industry's best operating and maintenance practices on their coal-fired units and 

therefore, there is little to no room for additional efficiency gains in this area. Commenters stated 

that this means in order to achieve an overall six percent efficiency improvement, more 
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efficiency gains would have to be achieved through equipment upgrades, in which there is no 

certainty that even the two percent gain proposed by EPA can be achieved. 

Commenters stated that EPA did not attempt to determine the technical feasibility of sustaining a 

four percent heat rate improvement from implementing operating and maintenance best 

practices. Commenters stated that because Southern Company already has a robust heat rate 

program that maintains unit heat rates, and because additional practices suggested by EPA would 

threaten reliability, it is not reasonable to assume any incremental reduction in heat rate is 

achievable and sustainable based on the implementation of additional practices at Southern 

Company's coal-fired units. Commenters referred to Sargent & Lundy who stated that "most 

utilities are employing best operational and maintenance practices" and that "significant further 

reduction in heat rate, such as that assumed by EPA, may not be feasible."

Commenters stated that even if permissible it is not at all clear that it is feasible for the states to 

meet the proposed required emission reductions. Commenters stated that under building block 

one, EPA posits that a six percent improvement in heat rates is possible, with four percent 

coming from adopting, operating, and maintenance best practices and that EPA presumes that 

plant operators do not already run and maintain their facilities according to best practices so as to 

minimize unit power production costs. 

Commenters stated that EPA's initial assumption that a 4% heat rate improvement is available 

based on use of operating best practices is unreasonably ambitious. Commenters stated that EPA 

identifies operations and maintenance practices such as "turning off unneeded pumps at reduced 

loads, installation of digital control systems, more frequent tuning of existing control systems, or 

earlier like-kind replacement of worn existing components" as methods that, collectively, would 

shrink the heat rate gap between the average coal-fired steam EGU and the top decile of such 

units by 30%. Commenters stated that however, most other electric utilities already run their fleet 

as efficiently as possible, making significant further improvements through best practices very 

unlikely. Commenters stated that their engineers and technicians are dedicated to finding and 

implementing efficiency improvements and keeping these units running as efficiently as 

possible. Commenters stated that as a general matter, the EPA-identified "best practices," such as 

turbine and boiler feed pump overhauls and regular checks for air heater seals and ductwork 

leaks, are already routine aspects of plant operating procedures for most electric utilities. 

Commenters stated that furthermore, many, if not most, electric utilities now use digital control 

systems that allow their power plant operators to monitor unit efficiency in real time and analyze 

data on a daily basis to find and correct unit inefficiencies and as a result, many existing coalfired EGUs are able to operate very near design values. 

Commenters stated that the initial assumption that a 4% heat rate improvement is available based 

on use of operating best practices is ambitious. Commenters stated that EPA identifies operations 

and maintenance practices such as "turning off unneeded pumps at reduced loads, installation of 

digital control systems, more frequent tuning of existing control systems, or earlier like-kind 

replacement of worn existing components" as methods that, collectively, would shrink the heat 

rate gap between the average coal-fired steam EGU and the top decile of such units by 30%. 

Commenters stated that most utilities, including CPS Energy, already run their fleet as efficiently 

as possible, because of the costs to customers associated with inefficient operations, making 

significant further improvements through best practices infeasible. Commenters stated that CPS 
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Energy has a staff of engineers and technicians dedicated to identifying and implementing 

efficiency improvements and keeping these units running as efficiently as possible. 

Commenters stated that to achieve a 4 percent improvement in heat rate through best practices, 

EPA surveyed heat rate efficiencies across the Nation's coal-fired fleet, evaluating the hourly 

heat input and gross generation data reported by EGUs to EPA, and the Agency then sought to 

bring the fleet up to the standards of the best performers, adjusting for variations in ambient 

temperature and hourly load, which EPA recognized were out of the control of individual 

generators. Commenters stated that EPA then estimated a range of 1.3 to 6.7 percent in potential 

untapped gains across the entire coal-fired EGU fleet that could be achieved through changes in 

operating practices. Commenters stated that from this range, EPA decided that, on average, coalfired EGUs could reasonably achieve a 4 percent heat rate improvement.

Commenters stated that EPA based its 4 percent figure on several erroneous assumptions. EPA 

assumed that, other than ambient temperature and operating load, which account for only 26 

percent of the variability in heat rate efficiencies across the fleet, any other variation was within 

the control of the plant operator, but this assumption fails to account for other factors that explain 

most of the unaccounted for variability, and which are not within the operator's control. 

Commenters stated that fuel diversity in any given area affects heat rate. Commenters stated that 

in regions where baseload capacity is spread across coal, nuclear, and gas facilities, coal-fired 

facilities will cycle more often, which translates into operating at higher heat rates. Commenters 

stated that overall electricity demand is also `a factor. Commenters stated that higher demand 

means less cycling and, thus, higher operating efficiency. Commenters stated that EPA similarly 

fails to account for variations in heat rate among different types and ages of facilities. 

Commenters stated that EPA projects that a universally applied average 6% reduction in GHG 

emissions will result from their building block 1 heat rate improvement assumptions. 

Commenters stated that for such reductions to be achievable on average, and recognizing that 

many well-maintained EGUs will not be able to achieve such improvements, it is necessary to 

speculate that there must be equally as many poor-maintained units that EPA expects to survive 

their rulemaking. Commenters stated that such an expectation is unreasonable in view of the 

expected retirements projected by EPA and the reduced utilization that EPA expects from their 

re-dispatch decisions arising under building blocks 2 through 4.

Commenters stated that EPA estimates that EGUs can achieve a 4% heat rate improvement by 

"tightening" their operations and maintenance (O&M) decision-making, and that a further 2% 

can be gained by undertaking capital improvement projects. Commenters stated that contrary to 

that conclusion, EPA overestimates the potential heat rate O&M-based improvements, at least 

for well-maintained EGUs, by 200% to 400%; that is most EGUs could gain improvements of 

only about 1% to 2%. Commenters stated that Sunflower has evaluated the relevant heat rate 

improvements for the Holcomb 1 EGU following the general outlines established in the Sargent 

& Lundy Report and the NETL reports cited by EPA as the basis for their conclusions. 

Commenters stated that the assumptions made in the first two building blocks are not technically 

feasible and viable for Michigan or most other states; therefore the methodology in the goal 

calculation must be reconsidered
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Comment 40: Comments stating that heat rate improvement potential via best practices can 

achieve 4%

Response 40: For the EPA’s response to these comments, see section V.C of the final rule 

preamble of the CPP and Chapter 2 of the GHG Mitigation Measures TSD supporting the final 

CPP. The EPA agrees that the degree of potential HRI varies between individual EGUs.

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

Commenters believed that it is technically possible that implementation of "best practices" 

(operational and maintenance improvements) could result in an average of 4% heat rate 

improvement across the coal fleet. Commenters stated that despite the currently available

technology, services, and solutions, however, there is wide variation in what can be achieved at 

any given plant and determining what a particular plant could implement will require considering 

a number of factors, including:

• Whether solutions have already been implemented;

• The level of training, skills, and experience of operations and maintenance 

personnel that affect plant performance and rate of degradation over time 

(personnel impact the effectiveness of O&M improvements, and this directly 

relates to best practices opportunities);

• The extent and interval at which maintenance is performed;

• Operating practices and operational profile/demographics of the plant (e.g. 

amount of operation at significant part load and cyclic operation);

• The market in which the plant operates;

• Age of the plant and duration of operational time since last major outage;

• The configuration and design of the plant/major equipment, which places 

limitations upon the heat rate improvement entitlement.

Comment 41: Applicable to the supplemental proposal for Tribal and Territorial - heat rate 

improvement potential via best practices can achieve 4% - alternate approach

Response 41: See Chapter 2 of the GHG Mitigation Measures TSD supporting the final CPP for 

EPA’s response to this comment.

The following are summaries of the specific public comments under this comment:
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Commenters stated that in keeping with the CPP, the agency sets the expected HRI at six percent 

- four percent from operation and maintenance ("O&M") best practices and two percent from 

equipment upgrades. Commenters discussed in the 111(d) comments how this approach 

underestimates the true HRI that can be achieved at coal-fired plants. Commenters stated that for 

O&M best practices, their alternative approach would expect a unit to achieve the 95th percentile 

of its best rolling annual average efficiency performance during the 12-year interval from 2001 

to 2012. Commenters stated that for equipment upgrades, EPA itself has determined that four 

percent HRI is achievable, and the agency should adhere to this number, rather than the lower 

two percent value. 

Commenters noted that while an average HRI improvement of six percent from O&M best 

practices and an additional four percent from plant upgrades is reasonable, industry has argued 

that such an improvement may not be feasible where an individual plant made the technical and 

operational improvements in recent years. Commenters suggested a metric for O&M that 

resolves this problem by expecting each EGU to achieve a level of performance they have 

actually demonstrated in the past: the 95th percentile of its lowest rolling annual average 

emission rates between 2001 and 2012. Commenters stated that this represents a rolling annual 

average that the source has met approximately 200 times over the course of that 12-year period. 

Commenters stated that therefore, there can be no valid claim that the O&M improvements under 

Block 1 penalize sources that have already made significant technical or operational 

improvements in recent years. Commenters stated that furthermore, states and other jurisdictions 

(including the Navajo Nation, should it elect to develop an implementation plan) may choose to 

reduce or eliminate the HRI requirements on individual sources if they determine that equivalent 

emission reductions can be achieved through other accepted measures. 

Comment 42: Comments regarding EPA's assessment of the potential for heat rate 

improvement from equipment upgrades

Response 42: For the EPA’s response to these comments, see section V.C of the final rule 

preamble of the CPP and Chapter 2 of the GHG Mitigation Measures TSD supporting the final 

CPP. The 16-unit study in the proposal was used to investigate the potential heat rate 

improvement achievable specifically from equipment upgrades. For the reasons stated in the 

preamble and TSD, the EPA decided not to include a separate identification of the average 

quantity of heat rate improvement achievable solely through equipment upgrades. Our final 

assessment of potential heat rate improvement is comprehensive, reasonable, and appropriate 

given the nature of this rulemaking.

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

Commenters stated that EPA failed to include in the Existing Source Rule's docket vital net heat 

rate and emissions data, which are central to EPA's assertion that existing power plants are able 

to achieve a four to six percent heat rate improvement under EPA's first "building block." 

Commenters stated that for example, EPA claims in the proposed Existing Source Rule to have 

reviewed its database of existing coal-fired units and found 16 facilities that have achieved heat 

rate improvements of three to eight percent "year-to-year." but it does not include any supporting 
354

data. Commenters stated that without the "year-to-year" data showing that facilities can comply 

with the four to six percent heat rate improvement, the States and the public cannot meaningfully 

comment on the achievability of EPA's heat rate projections. 

Commenters stated that over an 11-year period, the Agency identified 16 units out of 884 that 

achieved a three to eight percent annual gross heat rate reduction and that EPA claimed these 16 

units Adequately Demonstrated a sustained two percent net heat rate improvement from 

equipment upgrades. Commenters stated that the 16 units, however, provide no justification for 

the achievability and sustainability of a two percent net heat rate improvement from equipment 

upgrades and that, first, 16 units represent only 1.8 percent of the study population; second, the 

16 annual occurrences identified by EPA represent 0.16 percent of the total occurrences 

evaluated; third, the unit-level evaluation does not provide any evidence of the sustainability of 

the heat rate reductions; fourth, EPA was only able to identify that equipment upgrades at two of 

the 16 units were responsible for the heat rate improvements, and, fifth, EPA did not evaluate net 

heat rates. 

Commenters stated out of the 16 units, EPA confirmed that only 2 units had made equipment 

upgrades to improve efficiency by 2% to 3%. Commenters stated that EPA also cites several 

studies with limited actual plant data to base its BSER of 2% efficiency improvement due to 

equipment upgrades and these studies are used as illustrative examples and do not provide 

achievable coal unit efficiency improvements for today's plants to bolster EPA's reasoning. 

Commenters stated that the 16 EGUs examined by EPA cover a typical, representative range of 

U.S. boiler characteristics in terms of capacity, age, manufacturers, firing design, and coal type; 

they do not, however, have emission controls suitable to meet the upcoming EGU MACT 

standards. Commenters stated emissions controls require electricity to operate and increase the 

net heat rate of the unit. 

Commenters stated that in addition, EPA did not report any absolute values of heat rates for the 

group, only the decrease in heat rate and therefore, it is not possible for NCDENR to know what 

rate these units started at and if their heat rate improvements are appropriate for their units. 

Commenters stated that if the units had heat rates of above 10,000 Btu/kWh and reduced their 

heat rate by 6%, the same improvement may not be possible on a unit already operating at 9,500 

Btu/kWh or lower. Commenters stated that the establishment of a 2% or 4% heat rate 

improvement requirement from equipment upgrades for all EGUs in the U.S., regardless of 

current performance, is arbitrary, given the analysis presented in the rule and TSDs. Commenters 

stated that since it is not known at this time if a 2% equipment upgrade on units that are 

performing well below the national average is achievable, they recommend EPA to provide 

states with possible upgrade-technologies to allow states to consider each on a case by case basis 

in developing their plans. 

Commenters stated that EPA makes an arbitrary determination that does not naturally stem from 

the data it relies upon and it cites one study - conducted by Sargent & Lundy - as its source and 

then improperly uses the data in the study. Commenters stated that it then determined that by 

adopting all relevant upgrades at a facility, an EGU could achieve a 4% heat rate improvement. 

Commenters cited EPA in saying: [W]e recognize that this total may overstate the average 

equipment upgrade opportunity across all EGUs because some EGUs may have already 

implemented some of these upgrades. Commenters stated that they propose to use as a data input 
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for purposes of developing state goals an estimate that, on average across the fleet of affected 

EGUs, only half of the full equipment upgrade opportunity just described remains--i.e., that for 

the fleet of affected EGUs as a whole, the technical potential for heat rate improvements from 

equipment upgrades incremental to the best-practices opportunity is on average two percent 

rather than four percent. 79 Fed. Reg. at 34,860.

Commenters stated that EPA's halving of the 4% potential improvement from equipment 

upgrades to account for plants that have already implemented such upgrades, rather than actually 

analyzing each state's fleet, falls far short of the "substantial evidence" requirement. See Sierra 

Club, 657 F.2d at 364. Commenters stated that rather than actually making an effort to determine 

which facilities have adopted heat rate improvements to determine an accurate estimate, it draws 

unsubstantiated conclusions based on aggregated data and thus, EPA fails to show that including 

a 6% heat rate reduction in each state goal is "reasonably reliable," "reasonably efficient," 

"feasible," or will produce the improved performance necessary to achieve the goal, as required 

by the D.C. Circuit. 

Commenters indicated that on pages 2-32 of the Greenhouse Gas Abatement Measures Technical 

Support Document, the EPA identified 16 units with 3-8% HRI and asked 

1. These 16 were out of how many?

2. Over how many years?

3. Please provide the details of this analysis and record of peer-review. 

Commenters asked, with regards to the EPA identifying modifications at 3 plants collectively 

achieving 0.25% to 3.5% HRI:

1. Why didn't the EPA provide more details or consider a great sample size? Over how 

many years was this sample taken?

2. What was the fleet average HRI when including all Region 7 coal-fired EGUs?

3. How did the EPA ensure these units were representative of the fleet as a whole?

4. What other real-world HRI implementation experience did EPA solicit and consider? 

Commenters cited the EPA's GHG TSD WEPCO two-phase efficiency program and asked how 

did the EPA determine that this program was representative of HRI technically feasible today?

Commenters stated that EPA has broad authority to gather information for the purpose of 

carrying out its responsibilities under the CAA, and frequently exercises that authority for 

purposes of collecting information from entities potentially subject to a new regulation, however, 

in this instance, EPA chose to forgo a search for relevant data to support its 

analysis. Commenters cited GHG Abatement Measures, at 2-36. Commenters stated that instead, 

EPA proceeds to establish emission guidelines for Arizona and other states, believing it can 

compensate for the absent unit-specific data by cutting in half the unrepresentative estimate 

generated by the agency using generic data. Commenters cited 79 Fed. Reg. at 34,860.
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Commenters stated that a review of pertinent data for Units 1 and 2 at CGS illustrates the type of 

information that EPA would have collected had it undertaken the data-gathering that is crucial 

for reasoned decision-making. Commenters stated that EPA would have seen that SRP already 

performed several of the equipment upgrades identified in the 2009 S&L study for these units 

before 2012, eliminating opportunities for heat improvements relative to a 2012 baseline. 

Commenters stated that as detailed in the S&L study specific to the CGS units, rather than an 

opportunity for an aggregate heat rate improvement of 2% as suggested by EPA, the achievable 

improvement in net heat rate through equipment upgrades at each of the two coal-fired EGUs at 

CGS is at most 1%. Commenters stated that the analysis specific to the SGS units shows that 3 of 

the 4 units at SGS do not have any opportunities to further improve heat rate through equipment 

upgrades. Commenters stated that in 2012, at the conclusion of EPA's study period, of the 16 

referenced EGUs at which EPA touts the efficiency gains purportedly achieved through 

equipment upgrades, eight had a gross heat rate higher than the 9,753 Btu/kWh, which EPA 

claims is the average for the "study population" as a whole - in other words, EPA's presumption, 

even if it were true, would show only that equipment upgrades can be used to achieve the 2012 

baseline level. Commenters stated that it would not be informative as to whether widespread 

equipment upgrades can be used to achieve heat rate improvements beyond that level, which is 

what EPA's proposal would require. 

Commenters stated that a consideration is that the heat rate of any coal-fired EGU changes with 

the scheduled maintenance cycle, and thus, any heat rate improvement goal for coal-fired units 

should consider all of the significant variables so unit heat rate is compared to a best achievable 

heat rate.

Commenters stated that EPA assumes the four "Higher Cost Options" can cumulatively deliver a 

2% heat rate improvement. Commenters stated the 2014 UARG Heat Rate Assessment Report 

cites typical gains in efficiency for these options; steam turbine overhaul or upgrade can provide 

a 2-3% improvement in heat rate, and EPA is correct in not assigning all of this benefit on fleetwide basis as many of these overhauls are implemented as usual practice, and the benefits 

decrease with time. Commenters then described the remaining options. Commenters stated that 

Acid Dew Point Control is not broadly available as it is not proven for the bulk of the generating 

fleet and the retrofit of Variable Frequency Drives for gas fans is noted to deliver approximately 

0.05 - 0.5% net heat rate improvement. Commenters added that the action of Economizer 

Replacement according to a survey of UARG members could lower heat rate by 0.20 - 0.40%. 

Commenters stated that as the NCC Report and the Cichanowicz Heat Rate Report emphasize, 

the feasibility, availability, and potential improvements to be realized from heat rate 

improvement measures at any particular EGU are highly site-specific and cannot be generalized 

across the coal-fired EGU fleet as a whole. Commenters stated that as the NCC noted, "the 

opportunity to apply these efficiency improvements across the existing fleet will vary 

significantly." Commenters stated that measures that may improve heat rate at an individual 

plant by as much as 1 percent may yield only negligible or nonexistent benefits at many others 

that have already implemented similar measures or that are otherwise operating in a highly 

efficient manner. Commenters stated that for example, the NCC Report estimates that the benefit 

of deploying variable speed drives to reduce auxiliary load may vary from 0.05 percent to 0.50 

percent, depending on the state of a unit's existing drive motors. Commenters stated that large 

benefits from steam turbine upgrades (the measure with the highest estimated payoff) are only 
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possible for units that are already severely degraded; for most units, the available payoffs would 

lie at the low end of the possible range. Commenters stated that many of the available heat rate 

improvements for which the efficiency benefits outweigh the costs have already been 

implemented by EGU owners for economic reasons, either as onetime upgrades or as part of 

consistent routine operating and maintenance practices, and would not yield substantial benefits 

if they were implemented again. Commenters stated that other measures are simply not 

compatible with the design of particular units.

Commenters stated that in evaluating the equipment upgrades expected under Building Block 1,

EPA provides an extensive literature review and discusses the leading technical analysis by the 

NETL129 and other relevant documents and based on its review, the agency selected four 

specific technologies on which to base the Block 1 heat-rate improvements: economizer 

replacements, acid dew point controls, variable frequency drives for use with fans, and turbine 

blade overhauls. Commenters stated that in addition, the technical literature identifies the 

following upgrades for existing coal-fired EGUs that EPA does not include in its Block 1 

calculations: condenser cleaning, intelligent soot blowers, electrostatic precipitator 

modifications, boiler feed pump rebuilds, air heater and duct leakage controls, neural networks, 

modifications of criteria pollutant control systems (selective catalytic reduction equipment and 

flue-gas desulfurization configurations), and advanced packing at cooling towers. Commenters 

stated that, describing the four equipment upgrades underscoring its Block 1 methodology, EPA 

concludes that [t]he remaining four methods are higher cost heat rate improvement items that 

they believe properly fall into the category discussed as upgrades and using an average of the 

ranges of potential Btu improvements estimated by Sargent & Lundy for the four upgrade 

methods, upgrades, as defined here, could provide a 4% heat rate improvement if all were 

applied on an EGU that has not already made these upgrades. . . . Commenters stated that the 

equipment upgrades results are supported by numerous studies and by the EPA's analysis of the 

costs and associated improvements in heat rate that can be attributed to equipment and system 

upgrades.

Commenters stated that EPA declines to adopt a four percent reduction in heat rate because of 

uncertainty as to the extent to which these technologies have been adopted while acknowledging 

that this approach is conservative: 

"We considered that a 4% reduction in heat rate might be achieved on a coal-steam unit by 

applying the four higher cost upgrade actions described in Table 2-13. However, because details 

of current actual unit configurations are unknown, and some units may have applied at least 

some of the upgrades, we conservatively estimate the heat rate improvement potential for 

upgrades at 2%." 

Commenters stated that EPA need not - and, indeed, may not - vary from its technically sound 

determination that an additional four percent heat rate reduction is demonstrated through 

equipment upgrades, especially where it can either directly determine or infer from existing data 

the extent to which these techniques have been employed in the industry. Commenters stated that 

the agency still has time to issue an information request under section 114 of the CAA to the five 

or six largest operators of coal-fired power plants if comprehensive information is not provided 

in their comments.
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Commenters stated that several of the most effective upgrades, such as turbine upgrades, can 

only be performed during extended outages and may require either major or minor CAA 

permitting. Commenters stated that EPA can by itself determine the number of permits (if any) 

that have been issued for such projects and additionally, it is likely that the long-term emission 

profile of a unit undergoing such an upgrade would show a significant emission rate reduction 

immediately following an extended outage and that this improvement would be sustained for 

several years. Commenters stated that notably, the emission profiles of only a small percentage 

of the plants in the 52-Unit Study demonstrate this characteristic. Some units, such as Mill Creek 

Unit One, do show the emission profile that one would expect following a significant upgrade. 

Commenters stated that other units, such as Cayuga Unit One, show a significant improvement 

that is not sustained over the long term, suggesting that whatever upgrade led to the improvement 

needs to be renewed or maintained. 

Commenters stated that the data suggest that only four of the 52 units demonstrate a significant, 

sustained long-term improvement in CO2 emission rates, such that one might conclude that they 

had undergone capital upgrades that yielded a sustained and substantial improvement in 

performance. Commenters stated that this indicates both that operation and maintenance 

practices alone (rather than equipment upgrades) can account for the six percent emission 

reduction indicated by the 52-Unit Study and that such upgrades have not been undertaken at 

most plants. Commenters stated that while a number of facilities completed turbine blade 

replacement projects approximately 15 years ago, those units may well be due for additional 

upgrading after 20 years, in line with the compliance schedule for the Clean Power Plan. 

Commenters stated that moreover, published reports by industry demonstrate the relative 

infrequency of these types of projects to date. Commenters stated that Siemens asserts that over 

the past 20 years, it and companies that it has acquired - Westinghouse and Parsons Steam 

Turbine - have upgraded turbines at 214 units comprising 88 GW of capacity worldwide. 

Commenters stated that Siemens also asserts that GE and Alstom have upgraded only two 

turbines each and MHI only two turbines worldwide. Commenters stated that however, 

information in other documents suggests that GE and Alstom may have upgraded 30 or 40 units 

each. Commenters stated that while Siemens may not be correct in its determination of the 

number of turbines upgraded by its competition, it can be presumed that Siemens knows how 

many turbines it has upgraded between 1992 and 2012. Commenters stated that this information 

supports a conclusion that turbine upgrades to achieve efficiency improvements are not common 

worldwide or in the United States.

Commenters recognized that some plant operators may object that an incremental emission 

reduction of four percent based on equipment upgrades overestimates what the fleet is actually 

capable of achieving. Commenters urged the agency to reject this argument. Commenters stated 

that as the commenters' study indicates, few plants have actually invested in the equipment 

upgrades that Building Block 1 contemplates, and a four percent heat rate improvement from 

such upgrades is entirely reasonable. Commenters stated that while no company is obliged to 

comment on an EPA proposal, where an operator or trade association submits a comment and 

makes a generalized assertion but fails to provide specific information that can be presumed to 

be in its possession, EPA may take note of the omission. 
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Commenters stated that although EPA is clear that the 2009 Sargent & Lundy study is the sole 

basis for its assumption regarding the achievability of heat rate improvements through equipment 

upgrades, EPA also summarily discusses other sources of purportedly pertinent data that it 

considered. Commenters stated that one of those is a subset of the "study population" of 884 

EGU's discussed previously: 

The EPA inspected the study population to find examples of EGUs that made significant year-toyear improvements in heat rate. After filtering out those cases that may have been the result of 

changes in capacity factor, reporting method, or other events, the EPA identified 16 EGUs that 

reported a single year-to-year heat rate improvement of 3-8%. In two of these cases they were 

able to identify equipment upgrades responsible for 2-3% heat rate improvement using the 

applicable estimates from the Sargent & Lundy 2009 study. Similarly, in the other cases, while 

their research was unable to confirm specific equipment upgrades, based on the elimination of 

other possible explanations they believe that equipment upgrades were the most likely cause of 

some of the observed heat rate improvements. 

Commenters stated that as with the earlier discussion of hour-to-hour variability, the inferences 

drawn by EPA based on apparent year-to-year improvements in gross heat rate shown by the 

"study population" data set are not appropriate. Commenters stated that there are at least two 

fatal flaws in EPA's logic with respect to this data set. Commenters stated that first, as discussed 

previously, fluctuations in reported heat input rate are more likely the result of measurement 

error or factors other than actual improvements in EGU efficiency. Commenters stated that here, 

having admitted that it had no basis for presuming that the observed fluctuation in gross heat rate 

at fourteen of the sixteen referenced EGU's was attributable to an equipment upgrade, EPA did 

not even attempt to determine whether the purported improvements in heat rate were sustained. 

Commenters stated that second, in 2012, at the conclusion of EPA's study period, of the sixteen 

referenced EGU's at which EPA touts the efficiency gains purportedly achieved through 

equipment upgrades, eight had a gross heat rate higher than the 9,753 Btu/kWh which EPA 

claims is the average for the "study population" as a whole. Commenters stated that in other 

words, EPA's presumption, even if it were true, would show only that equipment upgrades can 

be used to achieve the 2012 baseline level; it would not be informative as to whether widespread 

equipment upgrades can be used to achieve heat rate improvements beyond that level, which is 

what EPA's proposal would require.

Commenters stated that more robust analyses of the potential improvements in heat rate of coalfired EGU's have been performed by agencies within the federal government which, in contrast 

with EPA, have particular expertise in efficiency and reliability of fossil fuel-fired EGU's. 

Commenters stated that the results of these analyses include key findings overlooked by EPA:

As these results show, the potential reduction in emissions (in percent terms) is greatest when the 

base plant (before retrofit) is less efficient. This is a recurring theme throughout the analysis, and 

is intuitive: when efficiency improvements are performed at an existing coal unit, there is greater 

potential for improvement at a unit that operates less efficiently to begin with, than at a newer 

unit with an already-low heat rate.
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These results illustrate that a "one-size fits all" solution does not exist when it comes to power 

plant retrofits, and that some retrofits may not make sense for certain plants, such as pulverizer 

upgrade for Plant B. Instead, utilities are likely to weigh their options based on the expected

plant life, anticipated fuel costs, and other such factors - such as familiarity with a technology -

before making the decision to invest in capital improvements. (Emphasis in original.) (Options 

for Improving the Efficiency of Existing Coal-Fired Power Plants, DOE/NETL-2013/1611. U.S. 

Department of Energy, National Energy Technology Laboratory. April 1, 2014.) 

Commenters stated that they had previously initiated more detailed engineering analysis on two 

of the more impacting technologies (intelligent sootblowers system and reverse air system/ID 

fans) as part of a boiler improvement bundle identified below. Commenters stated that they have

begun replacement of Holcomb 1's current high-performance cooling tower fill upgrade, which is 

approaching the end of its 20-year life, with an identical high-performance fill. Commenters 

stated that finally, two of the technologies (combustion optimization and boiler feed pump 

turbine overhauls) are currently being evaluated in a normal fashion for inclusion in a scheduled 

major maintenance outage for 2017. Commenters stated that finally, please note that these 

projects are not all necessarily independent in execution nor is their effect on the NUHR 

necessarily additive. 

Commenters stated that EPA projects that an additional 2% heat rate improvement is available, 

on average, through equipment upgrades. Commenters stated that this assumption is incorrect for 

most of the industry in general and CPS Energy in particular. Commenters stated that for 

example, a $23 million efficiency improvement to the turbine on Spruce 1 would achieve only an 

estimated 1% improvement on that unit alone. Commenters stated that a larger reduction would 

call for extremely expensive changes and would require drastic operational steps such as tearing 

down the existing boiler and turbine and replacing them with a supercritical boiler with higher 

temperature design, effectively building an entirely new unit. Commenters stated that even with 

that, changing from a subcritical design to a supercritical design, boiler efficiency can only be 

improved by about 3%, rather than the 6% required by the proposed rule (best operating 

practices are already utilized).

Comment 43: Comments stating that HRI goals via equipment upgrades cannot be achieved

Response 43: For the EPA’s response to these comments, see section V.C of the final rule 

preamble of the CPP and Chapter 2 of the GHG Mitigation Measures TSD supporting the final 

CPP. For the reasons stated in the preamble and TSD, the EPA decided not to include a separate 

identification of the average quantity of heat rate improvement achievable solely through 

equipment upgrades.

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

Commenters stated that EPA's attempt to account for individual characteristics by 

"conservatively estimat[ing]" a potential improvement of 2 percent instead of 4 percent is 

arbitrary and unreasonable. [GHG Abatement Measures TSD at 2-35.] Commenters stated that 

reducing the already-inflated target by half without further analysis is not "conservative," it is 
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merely guesswork. Commenters stated the actual potential for efficiency improvements via 

equipment upgrades is likely much lower, given that "[m]any of these measures have been 

already applied on units in the existing inventory." NCC Report at 71; Cichanowicz Statistical 

Critique at 10. Commenters stated that EPA cannot require affected EGUs to duplicate emission 

reductions they have achieved using measures they have already taken. Commenters stated that 

therefore, EPA must assess what efficiency upgrades have already been implemented by affected 

coal-fired EGUs in order to determine what level of additional heat rate improvements is 

achievable. Commenters stated the Agency has simply failed to adequately prepare the necessary 

background information for this rule. Commenters stated that likewise, EPA must also assess 

other factors that will determine what level of heat rate improvements is achievable for 

individual coal-fired EGUs across the source category as a whole, such as whether the upgrades 

are compatible with the design and hardware present at a unit and whether the upgrades may 

present operational reliability issues at a particular unit. See NCC Report at 71. 

Commenters stated that 2% is flawed and based on outdated information. Commenters stated that 

EPA relied on an exceedingly small sampling of coal-fired units to project a fleetwide standard 

onto the Nation's approximately 500 coal-fired plants and that in fact, using Sargent & Lundy 

data, EPA could identify just two cases that supported its conclusion that a 2% gain can be 

obtained fleetwide. Commenters stated that other sources cited by EPA, e.g., EPA Region 7 and 

a 2001 EPA study of WEPCO's "two-phase efficiency program at four coal-fired plants," 

similarly identified only a few units that achieved any heat rate improvements through 

equipment upgrades. Commenters stated that the former study analyzed heat rates at "three 

anonymous plants," while the latter study looked at a total of four plants and EPA even conceded 

the inadequacy of its dataset, noting elsewhere that it "was unable to confirm specific equipment 

upgrades." Commenters stated that even more problematic is EPA's failure to account for 

efficiency gains already secured through equipment upgrades, meaning that the achievability of 

further improvements is, at best, uncertain. Commenters stated that EPA began by estimating 4% 

in efficiency gains that could be secured at all coal-fired EGUs, assuming none had already 

undergone upgrades. Commenters stated that of course, that figure is not conclusive because it is 

based on Sargent & Lundy data from 2008, making the projection six years out-of-date. 

Commenters stated that calculating a reasonable goal for efficiency gains from 2014 onwards 

would require data reflecting equipment upgrades that have already been made and that only then 

could EPA project untapped potential. Commenters stated that instead of investigating actual 

upgrades, EPA fell back on pure speculation. Commenters stated that EPA supposed that some 

facilities have undergone upgrades in the last six years and some have not, and then split the 

difference and if 4% reflects no upgrades, then 2% must hit closer to the mark, EPA reasoned. 

Commenters stated that that figure is entirely arbitrary, as EPA itself indicated when it conceded 

that it "does not have sufficient site specific information to accurately estimate what percentage 

of the fleet has adopted various HRI methods, nor how effectively, and is not aware of any other 

investigator having sufficient information." Commenters stated that GE has access to data that 

are instructive in this regard and approximately half of the existing coal-fired EGU fleet runs on 

GE technology, and GE is a major provider of equipment and services to coal-fired EGUs. Of 

that subset, more than 75% of the units have already undergone efficiency improvements. 

Commenters stated that indeed they think it is likely that when facilities installed technology to 

comply with other CAA requirements, they simultaneously made heat rate improvements to 

recover parasitic load loss. Commenters stated that for its part, EPA's analysis relies on 

suppositions of what heat rate improvements are yet untapped that fall far short of the requisite 
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"reasoned basis" for determining an "achievable" standard and moreover, EPA failed to 

acknowledge that equipment upgrades made in the last several years might actually increase heat 

rate. Commenters stated that many of those upgrades were made to comply with other looming 

regulations, such as MATS, CSAPR, and the Clean Water Act cooling water intake rule. 

Installation of control devices to comply with these rules reduces some emissions - namely, those 

targeted by the rulemakings - but also reduces plant efficiency by increasing parasitic load. 

Commenters stated that because EPA's CO2 emissions target is based on net rather than gross 

MWh, any increase in parasitic load will decrease net electric generating efficiency, thereby 

making EPA's endorsed 6% target even less attainable. Commenters stated that GE estimates that 

parasitic load created by additional pollution controls is responsible for an approximately 0.5% 

heat rate impact across the fleet in 2012, though actual efficiency loss could be greater. 

Commenters stated that EPA must take into account the need to offset such efficiency losses in 

determining what net heat rate improvements are actually achievable. 

Commenters stated that even if EPA had the requisite data, the Sargent & Lundy findings are a 

poor proxy for estimating attainable heat rate improvements because for one thing, the study was 

expressly not published to prescribe potential efficiency gains in coal-fired EGUs, let alone 

determine achievable efficiency gains at the unit level nor could it, because the study does not 

account for variabilities in the existing fleet of coal-fired EGUs, such as geographic location, 

age, size, and design. Commenters stated that while EPA lacks data on upgrades already made, 

they have collected information reflecting upgrades that have been made to the coal-fired fleet, 

and it is the commenters' understanding that many units have already undergone modifications to 

improve heat rates. Commenters stated that because EPA relied on unfounded assumptions and a 

dearth of relevant data, its conclusion that a 2% heat rate improvement is achievable through 

equipment upgrades is arbitrary and capricious. 

Commenters stated that the CPP in establishing the 6% heat rate improvement target used 16 

plants in the data set to calculate an achievable average and that the so called "Sweet 16" plants 

selected are not representative of the entire fossil fleet and the EPA has the time, resources and 

capabilities to use all plants to conduct their analysis. Commenters recommended the final CPP 

expand the number of plants and reevaluate the additional heat rate improvements achievable by 

existing fossil generating stations.

Commenters stated that EPA's analysis of the heat rate improvement from equipment upgrades at 

coal-fired power plants is flawed because EPA's assessment is not representative of most coalfired power plant. Commenters stated that EPA cannot conclude that a heat rate improvement of 

two percent is attainable from equipment upgrades at all coal plants based on sixteen units. 

Commenters stated that EPA determined potential heat rate improvement opportunities related to 

equipment upgrades based on a review of engineering studies, an evaluation of year-to-year 

performance trends, and an analysis of data from units identified by EPA that allegedly 

demonstrate that such improvements are achievable. Commenters stated that for each of these 

areas, EPA generalized data and assumptions on potential heat rate improvement opportunities 

and concluded that a 2% improvement from equipment upgrades is achievable across the U.S. 

coal fleet without any serious consideration of unit-specific factors. Commenters stated that 

EPA's determination significantly overstates the technical potential and cost of such 
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improvement opportunities, while ignoring significant feasibility, sustainability, measurability, 

and regulatory challenges.

Commenters stated that EPA's potential heat rate improvement estimates from turbine upgrades 

are relatively consistent with utility experience. Commenters stated that Southern Company has 

performed turbine upgrades at select units when cost-effective opportunities have arisen, but that, 

due to other factors impacting a unit's heat rate, turbine upgrades cannot necessarily support a 

sustained heat rate reduction. Commenters stated that for example, in 2010, Georgia Power 

reconfigured the High Pressure ("HP") turbine nozzle block at Plant Bowen Unit 1, but due to 

unrelated operational realities, the net heat rate at Plant Bowen Unit 1 actually increased after the 

turbine project was performed, caused in part by a declining load factor at Plant Bowen Unit 1 

stemming from uncontrollable factors such as mild weather.

Commenters believed that it is unlikely that coal plants can achieve a 2% heat rate improvement, 

on average, across the fleet from major equipment upgrades. Commenters stated that plant 

owners have already performed a significant amount of steam turbine upgrades, and have 

implemented state-of-the-art technologies broadly across the fleet. Commenters stated that based 

on GE's installed base of steam turbine-generators, Commenters estimated an average unit in the 

fleet could achieve closer to a 1% heat rate improvement. Commenters stated that existing 

upgrade technologies are primarily focused on improved steam path designs and low pressure 

turbine retrofits that may include larger annulus last stage buckets. Commenters recognized that 

there are other, higher cost options and upgrades available such as economizer replacement, acid 

dew point control, combined variable frequency drive (VFD) and fan that are applicable to many 

units. Commenters stated that GE does not have sufficient information on how much of the 

existing fleet already incorporates these upgrades, nevertheless, given the limited opportunities 

for improvements within the steam turbine-generator (which constitutes a significant portion of 

the overall driver of heat rate for the plant) they believe total opportunities are limited.

Commenters stated that EPA's 2% heat rate improvement assumption may be technically 

possible in the portion of the fleet that has not already implemented existing upgrade technology. 

Commenters stated that implementing new advanced technology, assuming the investment is 

cost-justified, may also be possible with some units. Commenters stated that still, to achieve 2% 

on average across the fleet would likely require very significant capital investment that extends 

beyond what plant owners and operators would feel is justified.

Commenters stated that EPA's assessment that plants can undertake projects to improve 

efficiency by 2% across the nation is incorrect and as consumer owned utilities, AFFORD 

members have an obligation to provide all possible cost savings to customers. Commenters 

stated that cost effective efficiency investments are regularly assessed and undertaken when 

financially prudent.

Commenters stated that with respect to the 2% HRI from equipment upgrades, EPA analyzed a 

sample size of sixteen coal-fired EGUs that have achieved significant heat rate improvements. 

Commenters stated that out of this sample size, EPA identified only two EGUs that completed 

equipment upgrades that improved efficiency by 2%-3% and rather than collect and analyze data 

on BMPs at the remaining units or expand its sample size, EPA relied on generic heat rate 

studies that included limited actual plant data. Commenters stated that while a plethora of data 
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sources exists with respect to potential HRI at individual power plants across the country, EPA 

has cited virtually no hard data that provide an accurate picture of realistically achievable HRI 

from equipment upgrades.

Commenters stated that EPA relies on the Sargent and Lundy (S&L) report prepared for EPA in 

2009 to justify an additional 2% HRI from future plant modifications. Commenters stated that a 

cursory review of the S&L report shows that it outlines a group of upgrades that have been 

known and practiced by the industry for years and S&L specifically stated in their report that 

"[t]he primary intent of the study was to focus on methods that have been successfully 

implemented by the utility industry." Commenters stated that since utilities have already 

completed the actions that S&L includes in the study at many EGUs or have already 

determined them to be inapplicable to their EGUs, the additional 2% HRI is unachievable and 

should be removed from Building Block #1.

Commenters stated that for equipment upgrades, EPA determined that an EGU could improve 

heat rate by 2 percent through application of a "reasonable subset" of equipment upgrades 

identified in a 2009 study by Sargent & Lundy. Commenters stated that EPA relied on an 

exceedingly small sampling of coal-fired units to project a fleet-wide standard onto the Nation's 

approximately 500 coal-fired plants. Commenters stated that in fact, using Sargent & Lundy 

data, EPA could identify just two cases that supported its conclusion that a 2 percent gain can be 

obtained fleet-wide. Commenters stated that other sources cited by EPA, e.g., EPA Region 7 and 

a 2001 EPA study of WEPCO's "two-phase efficiency program at four coal-fired plants," 

similarly identified only a few units that achieved any heat rate improvements through 

equipment upgrades. Commenters stated that the former study analyzed heat rates at "three 

anonymous plants," while the latter study looked at a total of four plants. Commenters stated that 

EPA even conceded the inadequacy of its dataset, noting elsewhere that it "was unable to 

confirm specific equipment upgrades." 

Commenters stated that even more problematic is EPA's failure to account for efficiency gains 

already secured through equipment upgrades, meaning that the achievability of further 

improvements is, at best, uncertain. Commenters stated that EPA began by estimating 4 percent 

in efficiency gains that could be secured at all coal-fired EGUs, assuming none had already 

undergone upgrades. Commenters stated that calculating a reasonable goal for efficiency gains 

from 2014 onwards requires data reflecting equipment upgrades that have already been made. 

Commenters stated that instead of investigating real data reflecting upgrades actually made, EPA 

fell back on speculative assumptions. Commenters stated that EPA supposed that some facilities 

have undergone upgrades in the last six years and some have not, and then split the difference. 

Commenters stated that EPA reasoned that if 4 percent reflects no upgrades, then 2 percent must 

hit closer to the mark. Commenters stated that EPA's suppositions of what heat rate 

improvements are yet untapped is not supported by the record. 

Commenters stated that EPA expects the additional 2 percent improvement in heat rate to come 

from equipment upgrades, selected from a list provided by the aforementioned Sargent & Lundy 

study. Commenters stated that the agency rightly recognizes that "some EGUs may have already 

implemented some of these upgrades." Commenters stated that however, the proposed rule 

assumes without justification that roughly half of the equipment upgrades in question remain and 

are thus realizable at EGUs across the country. Commenters stated that EPA presents no data to 
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support this assertion and furthermore, the equipment profile of coal-fired EGUs in Indiana and 

Ohio may vary substantially from that of the average U.S. unit. Commenters stated that there are 

myriad problems with EPA's methodology for calculating heat rate improvements from 

equipment upgrades that OVEC believes need to be corrected in the proposed CPP. Commenters 

stated that first, EPA's 2 percent target for gains from equipment upgrades does not assume 

degradation, which results in year-over-year reductions in equipment efficiency. Commenters 

stated that as soon as new equipment is installed, its ability to improve the operational 

performance of the unit starts to decline, yet, it appears EPA assumes improvements from 

equipment upgrades will remain constant into perpetuity. Commenters stated that if an EGU 

owner wanted to address the degradation in equipment, additional costs, above those assumed by 

EPA in the proposed rule, would be incurred by the owner to attempt to maintain heat rate 

improvements. Commenters stated that, EPA assumes the gains from equipment upgrades are 

additive, when some of the recommended retrofits obviate other possible improvements (e.g., 

installing a new turbine vs. retrofitting the seals on an older turbine). 

Commenters stated that it is technologically impossible to apply all the improvements assumed 

under BSER and obtain the combined heat rate improvements outlined in the Sargent & Lundy 

study. Commenters stated that for example, one of the technologies discussed are intelligent soot 

blowers and this technology could increase heat rate efficiencies by up to 1.5%, but on average 

would improve heat rates by 0.6%. Commenters stated that many facilities in Indiana already 

have intelligent soot blowers so there would be little improvement over the baseline, thus 

affecting the overall ability for facilities to achieve a heat rate improvement of 6% as established 

by BSER. 

Commenters stated that with regard to equipment upgrades, EPA makes an arbitrary 

determination that does not naturally stem from the data it relies upon and that it cites one study -

conducted by Sargent & Lundy- as its source. Commenters stated that it then determined that by 

adopting all relevant upgrades at a facility, an EGU could achieve a 4% heat rate improvement. 

Commenters stated that however, EPA states that:

"We recognize that this total may overstate the average equipment upgrade opportunity across all 

EGUs because some EGUs may have already implemented some of these upgrades. Commenters 

stated that they therefore propose to use as a data input for purposes of developing state goals an 

estimate that, on average across the fleet of affected EGUs, only half of the full equipment 

upgrade opportunity just described remains- i.e., that for the fleet of affected EGUs as a whole, 

the technical potential for heat rate improvements from equipment upgrades incremental to the 

best-practices opportunity is on average two percent rather than four percent."

Commenters stated that EPA's halving of the 4% potential improvement from equipment 

upgrades to account for some plants that have already implemented such upgrades, falls far short 

of the "substantial evidence" requirement in Sierra Club v. Costle, 657 F.2d at 364. Commenters 

stated that rather than actually making an effort to determine which facilities have adopted heat 

rate improvements to determine an accurate estimate, EPA draws unsubstantiated conclusions 

based on aggregated data, thus, EPA fails to show that including a 6% heat rate reduction in each 

state goal is "reasonably reliable," "reasonably efficient," "feasible," or will produce the 

improved performance necessary to achieve the goal, as required by the D.C. Circuit. 
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Commenters said for example, EPA's HRI assumption of 6% may well be achievable in states 

that have not invested in upgrades; however, this rate is simply not realistic for Wisconsin or 

other states with regulated utilities that already operate highly efficient plants.

Comment 44: Applicable to the supplemental proposal for Tribal and Territorial - HRI via 

equipment upgrades cannot achieve 2%

Response 44: For the EPA’s response to these comments, see section V.C of the final rule 

preamble of the CPP and Chapter 2 of the GHG Mitigation Measures TSD supporting the final 

CPP. For the reasons stated in the preamble and TSD, the EPA decided not to include a 2-percent 

average heat rate improvement achievable solely through equipment upgrades.

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

Commenters stated that the EPA has concluded that unit-specific "equipment upgrades" could 

result in a HRI of 2 percent at coal-fired EGUs. Commenters stated that EPA's conclusion is 

unsupported by its analysis and accordingly, the EPA lacks a sufficient and reasonable basis for 

concluding that equipment upgrades can achieve an average HRI of 2 percent across the existing 

coal-fired EGU fleet. Commenters stated that the EPA arrived at its 2 percent HRI target from 

"equipment upgrades" by separating the 13 different HRI measures listed the S&L report into 

two categories based on their average estimated $/kW costs and the four higher cost measures 

were then characterized as "equipment upgrades."

• Economizer replacement;

• Acid dew point control;

• Combined VFD (variable frequency drive) and fan replacement; and

• Turbine overhaul (which appears to include rotor replacement).

Commenters stated that the EPA simply added the average estimated Btu/kWh improvements of 

the four "equipment upgrades." Commenters stated that based on this overly simplistic and 

technically unsupportable approach, the EPA concluded that these four specified equipment 

upgrades could provide a 4 percent heat rate improvement if all were applied on an EGU that has 

not already made them. Commenters stated that the EPA then "conservatively reduced the target 

to 2 percent as "some units may have applied at least some of the upgrades."

Commenters stated that this methodology erroneously assumes that the heat rate improvements 

from these upgrades are cumulative and that they provide consistent long-term benefits and in 

reality, the combined heat rate benefit from applying all four of these upgrades will be less than 

the sum of each measure's individual heat rate benefit when applied to an EGU. Commenters 

stated that these heat rate benefits will begin to degrade immediately once the unit returns to 

service. Commenters stated that also the EPA's reliance on the average Btu/kWh improvement of 

each measure is flawed because the potential benefit of each upgrade is highly unit-specific. 
367

Commenters stated that the four HRI measures may not even be feasible for many EGUs due to 

design limitations or backend pollution controls.

Commenters stated that for example, the S&L report states that additional surface area can be 

added to an economizer to gain a heat rate improvement by recovering heat and thereby reducing 

exit gas temperature. Commenters stated that however, over 50 percent of coal-fired EGUs 

presently have SCR installed for NOx control and that percentage will only grow as smaller units 

are retired and larger units continue to be retrofitted to meet present and future environmental 

regulations under the CAA. Commenters stated that reducing the temperature out of the 

economizer can interfere with SCR operation as SCRs require minimum operation temperatures 

to function properly across the load range. Commenters stated that the need to maintain a 

minimum SCR operating temperature could eliminate a large percentage of the eligible EGUs 

that may otherwise be capable of increasing their economizer surface area. Commenters stated 

that a similar limitation is imposed on employing acid dew point control due to potential 

downstream effects on electrostatic precipitators ("ESP") and FGDs. 

Commenters stated that EPA points to operating practices, such as shutting down unneeded 

pumps, installing digital control systems, more frequent tuning of existing control systems, and 

more frequent change out of like-kind replacement components, as means of achieving unit 

efficiency. Commenters agreed that incorporation of best operational and maintenance practices 

may achieve efficiency improvement at some coal-fired EGUs, but that however, the FCPP 

already employs the industry's best operating and maintenance practices and, therefore, there is 

little to no room for additional efficiency gains in this area. Commenters stated that this means in 

order to achieve an overall six percent efficiency improvement standard, higher efficiency gains 

must somehow be achieved through equipment upgrades.

Commenters stated that the only units remaining in operation at the FCPP are two 770 MW 

(nominal rated) supercritical boilers that are equipped with flue gas desulfurization and fabric 

filters, and soon will be equipped with selective catalytic reduction ("SCR") controls and that 

APS conducted a study to inventory the heat rate improvement projects that have already been 

performed on the Four Corners units and other projects that could be implemented to achieve 

further efficiency improvements. Commenters stated that APS determined that many of the 

projects EPA suggests can be implemented to achieve unit efficiencies, such as new boiler 

control systems, soot blower optimization, economizer upgrades, and air and feedwater heaters 

upgrades, have already been implemented at Four Corners and that accordingly, no further heat 

rate improvements are available from these types of projects.

Comment 45: Applicable to the supplemental proposal for Tribal and Territorial - heat rate 

improvement potential via equipment upgrades can achieve 2% - alternate approach

Response 45: For the EPA’s response to these comments, see section V.C of the final rule 

preamble of the CPP and Chapter 2 of the GHG Mitigation Measures TSD supporting the final 

CPP. The EPA appreciates commenters’ support, suggestions, and constructive criticism. Where 

appropriate, the EPA has refined its methodology accordingly. The EPA believes that the 

methodology described in the above-referenced portions of the preamble and TSD provides the 
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best method of determining the heat rate improvement component of the BSER, for the reasons 

described therein.

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

Commenters stated that reviewing the plots for the six units still operating on Navajo land, 

commenters saw that two of those units - Navajo Units Two and Three - operated at relatively 

low emission rates in 2012 compared to their emissions in prior years. Commenters stated that 

since the 2012 emission rates for Four Corners Units Four and Five and Navajo Unit One were 

well above the best rates achieved by those units during the 2001-2012 period, EPA's 

"averaging" approach would result in reasonable emission reductions through O&M practices at 

Navajo coal plants. Commenters stated that yet because the agency uses an overly lenient 

estimate of the amount of improvement that can be achieved by hardware upgrades, its final 

calculation understates the available improvement at these facilities. Commenters stated that 

under the commenters' approach, the "best" Block 1 emission rate for units located on Navajo 

lands is 1,930 lbs CO2/MWh, rather than the 1,993 lbs CO2/MWh standard proposed by EPA.

Commenters stated that however, Bonanza Unit One is the only operating regulated unit on Ute 

land, and it too had a 2012 operating rate that is well below its long term average rate and only 

2.5 percent higher than its 95th percentile low rolling average. Commenters stated that, as 

depicted in Table 1 (Evaluation of Indian Lands' Coal-fired EGUs) Commenters calculated a 

Block 1 emission rate of 2,044 Lb/MWh rather than the 2,016 lb/MWh proposed by EPA. 

Commenters also urged EPA to apply this HRI formula to all fossil-fired EGUs, not just coal 

plants. Commenters stated that for tribal nation lands, this would affect the three NGCC units 

that constitute the South Point Energy Center on Fort Mojave territory. Commenters stated that 

these units should be expected to meet the 95th percentile emission rate and make additional 

equipment upgrades in line with their recommended requirements for coal plants. 

Comment 46: Comments regarding applicability and EPA's use of the 2009 S&L study

Response 46: For the EPA’s response to these comments, see section V.C of the final rule 

preamble of the CPP and Chapter 2 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 according to the proposed rule, "We believe that [...6 percent...] 

represents a reasonable estimate of the technical potential for CO2 emission reductions that 

would be achievable from affected coal fired steam EGUs, on average, through heat rate 

improvements as an element of the best system of emission reduction." One of the more widely 

known resources that EPA used in arriving at the six percent reduction requirement was the 2009 

Sargent & Lundy report, Coal-Fired Power Plant Heat Rate Reductions. The report does not 

support EPA's contention that a six percent reduction is a "...reasonable estimate of the technical 

potential for CO2 emission reductions." Instead, it reinforces that a heat rate improvement of that 

magnitude is not achievable. Commenters continued stating that, while initial efficiency 

improvements, regardless of the range, might be technically feasible, it is a well-known fact 
369

these efficiency gains are not sustainable. Commenters stated the degradation of operational 

efficiency is a forgone conclusion, and it simply would be uneconomical and impractical to 

expect the industry to maintain a specific efficiency level. Commenters stated that finally, 

stakeholders from all of Kentucky's utilities reinforce the conclusion that achieving a heat rate 

improvement of six percent is highly unlikely, if not impossible. Commenters stated that one 

percent is a realistic number with the absolute upper range being a three percent improvement, at 

best, because, where practicable, utilities have already made investments to maximize heat rate 

efficiency. Commenters stated that it is much more appropriate to allow each state to evaluate the 

ability to achieve emission reductions within its statewide fleet in order to calculate the statespecific goal. Commenters stated that an alternative would be to reset the heat rate improvement 

in Building Block 1 to two percent to comport with the Sargent and Lundy findings and to be 

consistent with EPA's own determination of BSER found in the 111(b) Modified and 

Reconstructed Rule. Commenters stated that should EPA see fit to readjust the percentage, the 

Cabinet again contends that simply shifting the reduction to another building block would be 

inappropriate.

Commenters stated that in addition to its analysis of variability in hourly heat input rate and 

gross generation data for the "study population," EPA also asserts that the 2009 S&L study 

supports its conclusion regarding the achievability of improvements in heat rate at coal-fired 

EGUs at no cost or low cost. Commenters commissioned S&L to evaluate the opportunities for 

heat rate improvements, through these and other techniques, at the two coal-fired EGUs at its 

CGS (Coronado Generating Station). Commenters stated that S&L's analysis and approach is 

consistent with the same effort they performed in which EPA concluded 4% was reasonable and 

contrary to EPA's interpretation of S&L's 2009 study, the results of the CGS study, which is 

included as Appendix H of these comments, indicate there are no opportunities to improve heat 

rate though implementation of "best practices." Commenters stated that S&L also performed this 

analysis for the 4 units at SGS (Springerville Generating Station), which is included as Appendix 

I of these comments and similar to the CGS analysis, 3 of the 4 units at SGS do not have any 

opportunities to improve heat rate.

Commenters stated that EPA's assessment that plants can undertake projects to improve 

efficiency by 2% across the nation is incorrect. Commenters stated that as a consumer owned 

utility, they have an obligation to provide all possible cost savings to customers and cost 

effective efficiency investments are regularly assessed and undertaken when financially prudent. 

Commenters stated that EPA has interpreted the Sargent and Lundy study incorrectly and needs 

to follow the company's advice that"... case-by-case analyses should be conducted to determine 

whether the incremental heat rate improvement through the application of multiple strategies is 

economically justified." 

Commenters stated that EPA misinterpreted the 2009 Sargent and Lundy Report and while EPA 

stated in the Preamble to the proposed rule that the Agency considered a number of efficiency 

studies, EPA relied solely on just one: a 2009 Sargent and Lundy report. Commenters stated that 

the authors of the report state in a letter that their 2009 report "...does not conclude that any 

individual coal-fired EGU or any aggregation of coal-fired EGUs can achieve 6% HRI or any 

broad target, as estimated by EPA. Commenters discussed that Sargent and Lundy states that the 

strategy and amount of heat rate improvement that can be achieved is "...site specific and must be 

evaluated on a case-by-case basis." Commenters stated that Sargent and Lundy describe the case 
370

studies in the 2009 report as "estimated at the conceptual level." Commenters stated that EPA 

has interpreted the Sargent and Lundy study incorrectly and needs to follow the company's 

advice that "...case-by-case analyses should be conducted to determine whether the incremental 

heat rate improvement through the application of multiple strategies is economically justified." 

Commenters stated that EPA's "Equipment Upgrades" analysis used for the 2% heat rate 

improvement calculation is flawed. In EPA's "Equipment Upgrades" analysis used for the 2% 

heat rate improvement potential calculation, EPA relies on a 2009 Sargent & Lundy report 

detailing four equipment upgrades. Commenters stated that the impact of implementing the four 

equipment upgrades ranges from 2.1% - 6.7% improvement. Commenters stated that from the 

Sargent & Lundy report, the minimum improvement from the steam turbine overhaul is nearly 

1%. Commenters stated that however, many utility turbine sections have already been upgraded 

including one or more turbine sections on seven TVA coal-fired units. Commenters stated that 

using EPA's assumptions for turbines that have already been upgraded, only 1.1% potential 

upgrade potential remains for these units. Commenters stated that also, these upgrades do not 

provide a sustainable heat rate improvement; efficiency degradation occurs as they operate. 

Commenters stated that in the first six months after upgrading TVA's Bull Run unit 1 High 

Pressure turbine, the efficiency dropped about 0.5% (10 BTU/kWh impact), and after five years, 

the efficiency dropped nearly 2% (40 BTU/kWh impact). Commenters stated that efficiency 

degradation through time is also experienced for other upgrades such as air preheater 

modifications/replacements. Commenters stated that EPA's methodology in the final rule should 

be revised to account for efficiency degradation through time for equipment efficiency upgrades. 

Commenters referenced the Sargent & Lundy report which also identified 14 other equipment 

upgrade categories that could potentially be implemented to improve unit efficiency. 

Commenters stated that as shown in Table 1, all of these upgrades have either already been 

implemented on TVA's coal units which will not be retired by 2020, are not feasible, or would 

produce only small efficiency gains. Commenters submitted a table showing HR Improvement 

Strategy, Sargent and Lundy Description and Applicability to TVA Units. 

Commenters stated that EPA did not properly interpret and, as a result, has misapplied 

information from the 2009 study conducted by Sargent and Lundy study on which it primarily 

relied to make this across the board 6% heat rate improvement assumption. Commenters stated 

that Sargent and Lundy rejected EPA's findings and in a letter from Raj Gaikwad, Sargent & 

Lundy to Rae Cronmiller, NRECA dated October 15, 2014 stated that Sargent & Lundy's 2009 

Report does not conclude that any individual coal-fired EGU or any aggregation of coal-fired 

EGUs can achieve 6% improvement or any broad target, as estimated by the EPA. Commenters 

stated that it is reasonable to assume that if there was economical heat rate improvement 

potential in a given coal unit, whether by equipment upgrades or by adjustments to operating 

practices, that such improvement would have previously been made.

Commenters also stated that EPA also concludes that unit-specific "equipment upgrades" result 

in HRI of two percent. [See Abatement Measures TSD at 2-34.] Commenters stated that EPA's 

conclusion is unsupported by any analysis. Commenters stated that accordingly, EPA lacks a 

sufficient and reasonable basis for concluding that equipment upgrades can achieve HRI of two 

percent, on average, across the existing coal-based fleet. Commenters stated that EPA conducted 

an analysis of heat rate data and examined anecdotal data from seven plants reporting HRI, but 

ultimately relied exclusively on the 2009 S&L report in its determination that equipment 
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upgrades could result in HRI of two percent. See Abatement Measures TSD at 2-33. 

Commenters stated that the S&L report outlined 13 different HRI measures. Commenters stated 

the Agency separated these measures into two categories, based largely on cost. See Id. at 2-33. 

Commenters stated the less costly measures were characterized as "best practices" and the higher 

cost items were characterized as "upgrades." See id. Commenters stated that EPA concluded that 

if all four "upgrade" measures (1. Economizer replacement 2. Acid dew point control 3. 

Combined variable frequency drive and fan replacement 4. Turbine overhaul (which appears to 

include rotor replacement) were deployed on an existing unit (that had not already deployed 

them) the overall HRI would be four percent. See Id. at 2-34. Commenters stated that EPA then 

reduced the expected outcome of such upgrades to two percent, to account for possible prior 

deployment of some of the "upgrade'" measures on existing units. See Id. at 2-35. Commenters 

stated that while equipment upgrades can improve heat rates and reduce emissions, a single S&L 

report is not a sufficient basis for concluding that the existing coal-based fleet can, on average, 

achieve a two percent HRI through equipment upgrades. Commenters stated that EPA examined 

reported heat rate data in the context of the "best practices" analysis, but ultimately rejected, 

without explanation, this approach for the purpose of assessing the HRI potential of equipment 

upgrades. Commenters further stated that EPA's determination that half of the possible 

equipment upgrades may have already been deployed is unsupported by any data, and the 

Agency has failed to explain how it ensured that any of the improvements that were attributed to 

O&M "best practices" should not more properly be attributed to equipment upgrades. 

Commenters stated EPA misinterpreted the 2009 Sargent and Lundy Report and while EPA 

stated in the Preamble to the rule that the Agency considered a number of efficiency studies, 

EPA relied solely on just one - a Sargent and Lundy 2009 report. Commenters stated the authors 

of the report state in a letter that their 2009 report "...does not conclude that any individual coalfired EGU or any aggregation of coal-fired EGUs can achieve 6% HRI or any broad target, as 

estimated by EPA." Commenters reported that Sargent and Lundy states that the strategy and 

amount of heat rate improvement that can be achieved is "...site specific and must be evaluated 

on a case-by-case basis." Commenters stated that Sargent and Lundy describe the case studies in 

the 2009 report as "estimated at the conceptual level," and clearly, EPA has interpreted the 

Sargent and Lundy study incorrectly and needs to follow the company's advice that "...case-bycase analyses should be conducted to determine whether the incremental heat rate improvement 

through the application of multiple strategies is economically justified."

Commenters stated that the six percent heat rate improvement EPA proposes as Building Block 1 

is unachievable for existing fossil fuel-fired EGUs and EPA does not provide adequate technical 

justification for this proposal. Commenters stated that there simply are no efficiency projects that 

EGUs can perform to achieve a six percent improvement in heat rate and if there were such 

projects, EGU owners would have completed them already. Commenters stated that the 

cooperative business model compels and incentivizes heat rate improvement projects in a 

regulated environment and the fact that EPA found past heat rate improvements at existing EGUs 

does not demonstrate that future heat rate improvements can be performed to reduce CO2 

emissions. Commenters stated that past heat rate improvement projects only illustrate the fact 

that the utility industry has a strong incentive to perform heat rate improvements and these 

improvements have already been completed. Commenters stated that the remaining available 

plant efficiency improvement for the cooperative will only achieve about one percent efficiency 

improvement and the proposed CPP will force those improvements to be made. 
372

Commenters stated that EPA relies on a 2009 Sargent & Lundy (S&L) study to supports its 

finding that best operating practices and equipment replacements can achieve a greater than six 

percent heat rate improvement (or even a six percent improvement) but that S&L never intended 

for the 2009 study to be used to predict the technical feasibility of a six percent heat rate 

improvement across the entire fleet of fossil fuel-fired EGUs. Commenters stated that in a 

October 15, 2014 letter to Rae Cronmiller at NRECA (attached), S&L clarified that the "2009 

Report does not conclude that any individual coal-fired EGU or any aggregation of coal-fired 

EGUs can achieve 6% [heat rate improvement] or any broad target, as estimated by the EPA." 

Commenters stated that S&L also notes that the only "technically appropriate method to properly 

evaluate potential [heat rate improvement] is to conduct a unit-by-unit evaluation" and 

obviously, EPA's reliance on the S&L study is misplaced and cannot form the technical basis for 

Building Block 1. Commenters stated that S&L also notes that "many of the options for [heat 

rate improvement] listed in their 2009 report have triggered New Source Review actions by EPA 

and others." EPA provides no NSR relief in the proposal. 

Commenters stated that although the 2009 S&L Report identified potential ranges of heat rate 

improvement associated with each HRI method, it did not include an evaluation of long-term 

sustainable heat rate improvements, or the potential degradation of heat rate improvements over 

time, rather in general, heat rate improvement ranges listed in the 2009 S&L Report were based 

on potential performance following implementation of the particular HRI method. Commenters 

stated that the performance of many of the HRI methods included in the report will degrade over 

time, even with best maintenance practices. Commenters stated that for example, turbine 

upgrades or replacements would be expected to provide a reduction in heat rate following 

implementation, but, as with all equipment upgrades, are susceptible to degradation over time. 

Commenters stated that routine maintenance practices, including major overhauls to replace 

packing and seals, can help maintain turbine efficiency; however, initial heat rate improvements 

achieved with the equipment upgrade will not be sustained over time.

Commenters stated that other HRI methods reviewed in the 2009 S&L Report, including, but not 

limited to, boiler feed pump maintenance, air heater leakage, fan modifications, and acid dew 

point reduction strategies are similarly subject to degradation over time. Commenters stated that 

EPA did not take into consideration normal heat rate degradation when it applied the heat rate 

improvement ranges across the coal-fired fleet and that by omitting normal degradation from its 

evaluation of fleet-wide average heat rate improvement opportunities, EPA overestimated 

efficiency improvements that can be achieved and sustained. 

Commenters stated that in an effort to determine what a reasonable one-time heat rate 

improvement for the State's coal-fired EGU fleet might be, i.e., setting aside the question of 

whether any such improvements could be sustained, the Wyoming Public Service Commission 

and the Wyoming Department of Environmental Quality consulted with the operators of 

Wyoming's coal fleet. Commenters asked these operators to ascertain what heat rate 

improvements were feasible, and more specifically, to review the applicability of available 

technologies listed by Sargent & Lundy - all of them, not just the technologies highlighted by 

EPA. Commenters viewed the technologies in that report as an exhaustive list covering the entire 

range of possibilities for EPA's 6% improvement, through both best practices (4%) and 

equipment upgrades (2%). Commenters stated that the TSD adopted a more limited focus on 

technologies of interest as best practices and equipment upgrades. TSD, pp. 2-5 to 2-11, 2-33. 
373

Commenters stated that the Sargent & Lundy report identified the potential ranges of 

improvements, expressed in Btu/kWh and broken out by 200 MW, 500 MW, and 900 MW 

parameters. Commenters referred to the list of thirteen technologies and potential improvements 

EPA singled out, with lowest to highest Btu/kWh regardless of plant size: 

Commenters realized that the listed range of values in this chart, 305 to 1265, is not the same as 

the range of 415 to 1205 which appears in the Federal Register Notice, p. 52, but cannot account 

precisely for EPA's tally and have referred directly from the specified sections of Sargent & 

Lundy.

Commenters believed, taking everything into account, that a statewide improvement of 2% is the 

best that could be achieved. Commenters stated that because the operators reviewed specific 

measures in the context of specific plants, they could make specific judgments about whether 

costs aligned with benefits. Commenters stated this information is superior to the broad ranges 

on which EPA has premised its proposed rule. 

Commenters stated that PacifiCorp concluded that an overall improvement of 2.8% for its fleet 

might be economically practicable and technically feasible over a period of years, but this 

number depends heavily on turbine upgrades to Units 3 and 4 at Jim Bridger. Commenters 

stated, otherwise, PacifiCorp identified improvements ranging from .3% to 2.5% for each unit, 

subject to offsetting reductions for environmental compliance upgrades. 

Commenters stated Black Hills contracted with Black & Veatch for a report concluding that net 

unit heat rate improvements of 1.8% were feasible for each unit of its four plants. Commenters 

stated Basin Electric estimated improvements of less than 2% were possible at Laramie River 

Station, subject to a degradation of .5 to 1.5% related to SCR installation, a potential 

modification now in dispute under EPA's regional haze regulations. Commenters stated Basin 

Electric estimates the potential for the much newer Dry Fork Station to be no more than 1%. 

Commenters provided the following summary comment with regards to EPA's use and 

interpretation of HRI data and cost data included in the 2009 S&L Report:

1. Commenters stated that heat rate improvement ranges presented in the 2009 S&L Report 

do not support the conclusion that any individual coal-fired EGU, or any aggregation of 

coal-fired EGUs, can achieve 6% heat rate improvement through implementation of best 

practices and equipment upgrades, as estimated by EPA.

2. Commenters stated that heat rate improvement ranges included in the 2009 S&L Report 

were estimated at a conceptual level, were not based on detailed site-specific analysis, 

and were based on the presumption that the HRI method or technology could be installed 

on the unit under review. Commenters stated that case studies included in the 2009 S&L 

Report show that it would not be feasible to apply all of the HRI methods examined in 

the study to any individual generating unit due to a number of factors, including, but not 

limited to, plant design, existing operation and maintenance practices, and previous 

equipment upgrades. Commenters stated that the report identifies potential HRI methods, 

but provides no basis for calculating an average heat rate improvement achievable across 

the fleet of existing coal-fired units.
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3. Commenters stated that case studies included in the 2009 S&L Report support the 

conclusion that the ability to apply each HRI strategy, and the amount of heat rate 

improvement that can be achieved by each strategy, is site-specific and must be evaluated 

on a case-by-case basis.

4. Commenters stated that the performance of many of the HRI methods included in the 

2009 S&L Report degrade over time, even with best maintenance practices and that 

depending on the strategy employed to reduce heat rate on an existing coal-fired EGU, 

initial heat rate improvements may not be sustainable and the unit's heat rate may 

increase over time. Commenters stated that by omitting normal degradation from its 

evaluation of fleet-wide average heat rate improvement opportunities, EPA overestimated 

efficiency improvements that can be achieved and sustained.

5. Commenters stated that unit dispatch and load profile were not taken into consideration 

in EPA's evaluation of heat rate improvement opportunities. Commenters stated that load 

profile is an important variable, as boilers are designed to achieve their highest efficiency 

at full load and their efficiency decreases with decreasing loads and with frequent load 

changes. Commenters stated that building blocks #2, #3 and #4 of the proposed 111(d) 

rule will likely result in coal-fired units cycling more frequently and running more 

frequently at lower loads and although EPA acknowledged that "[o]perating an EGU as a 

baseload unit is more efficient than operating an EGU as a load following unit to respond 

to fluctuations in customer electricity demand," decreased dispatch and load profile 

changes were no accounted for in EPA's heat rate improvement evaluation or economic 

analysis.

6. Commenters stated that cost ranges presented in the 2009 S&L Report represent order-ofmagnitude costs and were provided for comparative purposes only. Commenters stated 

that costs presented in the report were not indicative of the costs that may be expected to 

install the HRI methods at any specific facility, as HRI costs can vary significantly based 

on unit type, fuel type, plant design, previous equipment upgrades, retrofit difficulty, and 

other site-specific factors. Commenters stated that cost data from the 2009 S&L Report 

were misapplied when EPA converted the cost ranges to $/kW values and combined the 

costs for all HRI methods as though they were all applied on a single EGU.

7. Commenters stated that the approach used in the GHG Abatement Measures TSD to 

evaluate the economic impact of the HRI methods (i.e., applying an assumed total HRI 

cost of $100/kW to achieve an average fleetwide heat rate improvement of 6%) does not 

accurately evaluate the economic impact of potential HRI methods at any given facility, 

and fails to take into consideration any site-specific feasibility, effectiveness, and cost 

issues associated with the various HRI methods. Commenters stated that the wide range 

of heat rate improvement and HRI costs included in the 2009 S&L Report support the 

conclusion that the cost-effectiveness of the available HRI methods must be evaluated on 

a case-by-case basis. 

Commenters stated that EPA relies on a 2009 Sargent & Lundy study to show a proposed two 

percent efficiency improvement for equipment upgrades is achievable. Commenters stated that 

based on a literature-survey-and-vendor-data analysis, EPA uses national averages to conclude 
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that existing coal-fired EGUs can achieve "an aggregate heat rate improvement of approximately 

four percent (incremental to the improvement achievable for adoption of best practices)." 

Commenters stated that EPA goes on to explain that it recognizes that some of the efficiency 

projects identified in the Sargent and Lundy study have already been implemented and, 

therefore, concluded that a two percent efficiency improvement due to equipment upgrades at 

Subpart Da EGUs is reasonable. Commenters stated that however, as previously stated, APS will 

not be able to achieve a four percent efficiency improvement based solely on operating and 

maintenance practices, and therefore the overall six percent efficiency gains must be achieved 

through equipment upgrades. Commenters stated that opportunities to achieve this level of 

efficiency gain based on equipment upgrades at APS simply do not exist. 

Commenters further stated that the Sargent and Lundy based its results on a survey of power 

plants to determine heat rate improvement projects that had already been completed and while 

the study could be used to identify potential heat rate improvement projects, it also can be used 

to demonstrate that many of the heat rate improvement projects have already been performed. 

Commenters further stated that the data used in the Sargent and Lundy study are over six years 

old and many of the suggested upgrades had already been performed prior to the 2012, which is 

the baseline year used in the building block 1 calculation. Commenters further stated that EPA 

recognizes many of the projects have already been conducted, as EPA provides this as 

justification for only requiring two percent efficiency improvement from equipment upgrades.

Commenters further stated that this recognition by EPA demonstrates that national averages 

cannot be used to set a fixed efficiency improvement target and applying national averages 

directly to individual units does not work. Commenters further stated that each unit must be 

evaluated on a case-by-case basis to determine what additional efficiency improvements can be 

made to the unit. Commenters further stated that a specific unit's heat rate is primarily due to 

factors outside of the source's control and is tied to such factors as plant location, design, age, 

and size, coal type, cooling system type, grid dispatch, time of year the unit is dispatched, 

ambient temperature, auxiliary load requirements, pollution controls, and other factors that EPA 

has not holistically considered.

Commenters further stated that EPA did not conduct a case-by-case analysis to determine what 

future projects are possible for all coal-fired power plants and in fact, the two specific plant types 

Sargent and Lundy studied in order to quantify its heat rate improvements - a 1970s vintage 250 

MW boiler with an electrostatic precipitator and a late-1970s vintage 850 MW boiler with a 

baghouse and scrubber - do not currently exist in the U.S. operating coal-fired plant fleet.

Commenters summarizes options to improve heat rate or thermal efficiency and presented a 

state-of-art coal-fired power plant (Figure 3-1, UARG Report) that serves as the backdrop to 

define seven categories of plant design and operation identified from which heat rate 

improvements can be derived: 

• Fuel type and fuel processing, considering both the composition of the fuel and 

options to process the fuel to alter composition

• Process controls, which instruct plant components how to operate on a minute-byminute basis, with payoff both at steady-state and during load-changes,
376

• Boiler heat absorption and steam conditions, addressing the specifics of the boiler 

and the state of the steam generated,

• Options for low temperature heat recovery, assuring the maximum amount of low 

level heat is recovered

• Auxiliary power consumption and thermal losses, whereby minimizing the 

internal consumption of power or loss of usable heat benefits improves heat rate,

• Steam path for energy extraction, defined by the steam turbine and the related 

components, and 

• Cooling system, which influences heat rejection to the ambient air and plant heat 

rate.

Commenters concluded that the payoff from any given heat rate improvement method is highly 

site-specific. Commenters stated that in preparing background material for this document, 

UARG members were asked to share the frequency of heat rate improving actions they deployed, 

and the payoff. Commenters stated that the results show the payoff is highly variable, and can 

either be greater or less than that cited in EPA's reference analysis prepared in 2009 by Sargent 

& Lundy.

Commenters further stated that the UARG report diverges from EPA's assessment of heat rate 

improving technologies using the Sargent & Lundy Report. Commenters stated the Sargent & 

Lundy report itself is not challenged - but EPA's interpretation of results as communicated 

through a key Technical Support Documents is challenged. Commenters stated that EPA 

inappropriately (a) assumed numerous heat rate improving techniques are broadly applicable to 

the national generating fleet, (b) assumed deploying multiple heat rate- improving techniques 

provide cumulative benefits, and (c) did not consider that the payoff obtained immediately after 

the project for many of these means often degrades with time. Commenters stated that as a result, 

EPA's estimates of the number of heat rate-improving techniques that can be feasibly applied, 

and the long-term payoff from application of those techniques, are incorrect. Commenters stated 

that in fact, payoff from any heat rate improvement action is wholly site-specific in terms of 

results delivered and cost, and there is no basis for drawing conclusions about "average" industry 

performance. 

Commenters stated that the basis for the EPA's HRI assumption that most coal-fired EGUs do 

not already apply recommended operation and maintenance programs or have not upgraded to 

more efficient equipment is not clear in the proposed rule. Commenters stated that the EPA 

referenced a Sargent & Lundy (S&L) paper that lists potential methods of improving the heat 

rate at existing coal-fired EGUs as one of their bases for Block 1 BSER CO2 reductions, 

however, the EPA acknowledges in its technical support document for Block 1 that, "...details of 

current actual unit configurations are unknown, and some units may have applied at least some 

of the upgrades..."(GHG Abatement Measures Technical Support Document, Section 2.5.10, 

page 2-35). Commenters stated that because of this admission, it was not rational for the EPA to 

conclude that a 6% heat rate improvement was possible at existing coal-fired EGUs and also, 

given this acknowledgement, the TCEQ surveyed existing coal-fired EGUs in Texas to 
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determine the extent of methods currently utilized to improve heat rate at coal-fired EGUs to 

ascertain the validity of the EPA's assumption. Commenters stated that TCEQ the majority of 

coal-fired EGUs in Texas currently already utilize many of the methods identified in the S&L 

paper (percentage of units in Texas at the five locations within their plants were identified in the 

S&L paper) and that most of the coal-fired EGUs in Texas utilize other specific measures 

identified in the S&L paper. Commenters stated that EPA inappropriately used the S&L study to 

assume that the types of improvements estimated by S&L either were not utilized or that they are 

equally applicable and achievable at each and every coal-fired EGU across the nation and this 

assumption is therefore based on invalid data, is inherently flawed, and does not support a 

rational basis for the emission reductions required by Block 1. 

Commenters stated that the study determined that a heat rate improvement of 424, 154 and 6 

Btu/kWh, respectively, was possible for each case study included in the 2009 Sargent & Lundy 

(S&L) study. Commenters stated that none of the case studies involved a typical modern West 

Virginia base-load EGU, with requisite emission control equipment and associated equipment 

upgrades and that based on the average of the study's ranges of potential heat rate improvements 

from equipment upgrades, EPA supposedly determined that half of the equipment upgrade 

opportunities outlined in the study remains for existing units. Commenters stated that EPA then 

proposed that the technical potential for heat rate improvements which could be achieved from 

equipment upgrades are on the average of two percent. Commenters stated that the agency's 

appraisal of technical potential for heat rate improvements is based upon outdated information 

from a backward-looking study from 2009 that does not reflect the characteristics of EGUs with 

remaining useful life after installation of the emissions control equipment necessary to meet 

more recent EPA mandates. Commenters stated that therefore, the two percent heat rate 

improvement via equipment upgrade in the proposed rule is arbitrary and capricious. 

Commenters stated that with respect to available equipment upgrades, most EGUs in West 

Virginia have already achieved the majority of heat rate improvements outlined by the 2009 

Sargent & Lundy study concurrent with the installation of emission control devices (and 

associated equipment upgrades) to comply with the ARP, CAIR, CSAPR, and the MATS. 

Commenters stated that significant improvements in heat rate from turbine overhauls have also 

been realized, as all turbines at West Virginia utility-owned EGUs are subject to strict periodic 

maintenance to assure efficiency and reliability. Commenters referred to the S&L study which 

included three case studies and associated projected heat rate improvements:

• 250 MW pulverized coal power plant with electrostatic precipitator (ESP), 

resulting in 424 Btu/kWh HRI

• 850 MW pulverized coal power plant with flue gas desulfurization (FGD) and 

baghouse, resulting in 154 Btu/kWh HRI 

• 550 MW coal-fired power plant with ESP, evaluated replacing centrifugal fans 

with axial fans, resulting in 6 Btu/kWh HRI

Commenters stated that none of the case studies involved a typical modern West Virginia baseload EGU, with requisite emission control equipment and associated equipment upgrades. 

Commenters asserted that the 2009 S&L study is straightforward but is at this point outdated 
378

because it predates the impact of EPA's newer regulations on EGU operation which is true in 

West Virginia because most EGUs not scheduled for permanent shutdown have already achieved 

the majority of heat rate improvements outlined by S&L via the installation of emission control 

devices (and associated equipment upgrades) to comply with the ARP, CAIR, CSAPR, and the 

MATS. Commenters listed significant sections of the S&L study and it's applicability to West 

Virginia (individually summarized under 3.1.2) 

Commenters briefly described the 2009 S&L report and stated that EPA's capital analysis 

examines four of those projects, specifically economizer replacements, acid dew point control 

projects, combined variable frequency drive fans, and turbine overhauls but that EPA, however, 

made a simplifying assumption that undermines the validity of the analysis by assuming that half 

of these projects have not already been completed at existing generator. Commenters stated that 

assumption, in truth, is not "conservative," because it is nothing more than a simple guess, 

indicating that EPA does not have any basis to estimate, liberally or conservatively, how many 

coal units may already have undertaken these projects. Commenters stated that electric utilities, 

however, have likely installed most, if not all, of the projects EPA cites, particularly if those 

equipment installations are as cost-effective as EPA claims. Commenters stated that the Sargent 

& Lundy report on which EPA relies was a 2009 study that relied on 2008 data, four years prior 

to the baseline EPA assumes in its building block formula.

Commenters stated that in any event, the 2009 Sargent & Lundy study was not designed for 

national rulemaking purposes generally, nor does it support the specific assumptions that EPA 

has made in the Proposed Rule. Commenters stated that for example, the introduction of the 

report explains that its cost figures are intended to be accurate only on an "order of magnitude" 

level, and those cost figures are provided only for "comparison purposes" when evaluating the 

advantages and disadvantages of one project against another. Commenters stated that the report 

specifically notes that those cost estimates "should not be used as a basis for project budgeting or 

financing purposes." The report also notes that its calculations are based on the hypothetical 

"design" heat rate of coal units, which units can achieve (if at all) only during full load operation, 

not the actual heat rate of units, which the reports admits "are usually significantly higher than 

the design heat rate."

Commenters stated that HRI in a range of 4 to 12 % is viable across the coal-fired EGU fleet, 

and within that range equipment upgrades can yield 2 to 4 % HRI across the fleet. Commenters 

stated that in determining this latter 2 to 4% HRI target attributable to equipment upgrades, EPA 

relies on a 2009 report by the engineering firm Sargent & Lundy and that in a new report 

prepared for NRECA, Sargent & Lundy states that its 2009 study did not conclude that any 

individual coal-fired EGU, or any aggregation of such EGUs, can achieve the 6% HRI, as would 

be required by the Proposed Rule, or that 2 to 4% HRI can be achieved through equipment 

upgrades as this proposal presumes. Commenters stated that according the S&L personnel who 

authored the 2009 report, that report was based on a literature survey, data provided by original 

equipment manufacturers, and S&L's in-house database and that S&L further states in its report 

for NRECA that the HRI ranges described in the 2009 report were estimated at a conceptual 

level only and were not based on a detailed site-specific analysis. Commenters stated that in fact, 

the case studies included in the 2009 report reveal that it is not feasible to apply all of the HRI 

alternatives that had been examined to every individual generating unit. Commenters stated that 
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these are critical technical details the EPA failed to consider when it evaluated the 2009 report in 

connection with this rulemaking and that its failure here is a fatal flaw.

Commenters stated that EGU operators have strong incentives to run their power plants as 

efficiently as possible. Commenters stated that efficient operation reduces the cost of fuel, 

reduces emissions of conventional pollutants, and improves the overall economics of the power 

plant, and moreover, many utilities and companies provide specific incentives to EGU operators 

that are tied to achieving and maintaining performance improvements on a continuous basis. 

Commenters stated that therefore, operators in both regulated and deregulated electricity markets 

already have strong incentives to operate their units as efficiently as possible.

Commenters stated that in light of these strong economic incentives, most EGUs will be unable 

to achieve the heat rate improvements projected by the Sargent & Lundy study that EPA cites in 

support of building block one and although there may be a handful of EGUs in the current fleet 

that have not implemented all of the best practices and equipment upgrades identified by EPA, 

most EGU operators have been aware of the types of improvements Sargent & Lundy identified 

for years, and have either already implemented those improvements or have considered and 

rejected those improvements as being too costly or impractical. Commenters stated that indeed, 

given that the Sargent & Lundy study was performed in 2009, it is likely that most of the coalfired EGUs covered by the Proposed Rule had already implemented some or all of the 

improvements in the study by 2012, making further improvements beyond that baseline 

unrealistic. 

Commenters emphasized a fundamental finding in S&L's critique of EPA's use of its 2009 study 

- it is not possible to conclude that a 2 to 4% HRI through equipment upgrades is obtainable for 

any individual EGU or any aggregation of EGUs for a variety of reasons, such as individual 

generating units themselves vary in plant design, previous equipment upgrades, and operational 

approaches; individual HRI technologies and strategies do not always combine in ways that 

equal the sum of the parts because many technologies affect and are dependent on interrelated 

variables of plant operation; and the performance of some of the HRI strategies surveyed in the 

2009 report will degrade over time, in spite of best maintenance practices.

Commenters stated that S&L has publicly stated in correspondence with National Rural Electric 

Cooperative Association (NRECA) and the Utility Air Regulatory Group (UARG) that EPA 

mischaracterized their 2009 report, entitled "Coal-Fired Power Plant Heat Rate Reductions," and 

that the report does not in any way support a conclusion that any individual coal-fired unit or any 

group of coalfired units can achieve 6% heat rate improvement. Commenters then summarized 

the S&L findings. Commenters then stated that AEP completed a fleet assessment based upon 

the options suggested in the 2009 S&L report to determine, at a high level, the applicability and 

potential for further improvement on the fleet. Commenters stated that many AEP units have 

already implemented many of the improvement options as part of targeted performance 

improvement efforts, or simply as "business as usual" maintenance and due diligence and as a 

result, AEP supports S&L's conclusions that further reductions in heat rate are not technically 

achievable or feasible. Commenters presented a table that summarizes AEP's review of the 

applicability of the heat rate improvement strategies identified by the S&L report. 
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Commenters stated that EPA has incorrectly interpreted the information in the 2009 Sargent & 

Lundy study as supporting the availability of a fleet-wide six percent heat rate improvement at 

existing coal-fired power plants. Commenters stated that in contrast to EPA's assertion, a six 

percent heat rate improvement is unrealistic and unachievable for most coal-fired plants and, to 

the extent that some heat rate improvements may be available, the costs of implementing these 

upgrades at affected units would generally be prohibitive and could trigger onerous New Source 

Review permitting requirements. 

Commenters stated that while EPA arbitrarily adjusts the potential improvements from four 

percent to two percent without knowing the details of current unit configurations, the heat rate 

improvement potential from any one of these four upgrades could be zero if a unit has already 

implemented them. Commenters stated that EPA, dismisses that likelihood without reason or 

justification and ignores S&L Report's 850 MW well-controlled EGU case study that suggests an 

improvement in potential heat reduction of approximately 1.2 percent, which is lower than EPA's 

arbitrarily assumed two percent for all units. Commenters stated that numerous smaller units will 

retire due to the MATS rule and therefore it is likely that the majority of coal-fired EGUs 

remaining after 2016 will be large, well-controlled units that more closely resemble the S&L 

Report's 850 MW case study unit. 

Commenters stated that using the S&L report for establishment of "upgrades" to equipment, the 

USEPA assigned the highest value to equipment upgrades and created four measures for 

improvement. Commenters stated that by assuming that all EGUs would benefit from a worst 

case equipment upgrade, the USEPA erred, given that even the S&L report stated these might 

apply in some cases. 

Commenters stated that EPA inappropriately relies on the 2009 Sargent & Lundy report.

Commenters stated that the Sargent & Lundy report, upon which much of the EPA's HRI 

assumptions are based, identified a series of HRI measures and their potential effectiveness and 

offers guidelines to be used to evaluate individual facilities, on a case-by-case basis and applies 

its findings to two case studies to calculate potential improvements. Commenters stated that 

EPA, however, erroneously assumes that these potential improvements and case study results are 

applicable and achievable to all coal fired EGUs in the U.S. Commenters listed Sargent & 

Lundy's observation that many of the assumptions EPA utilized in its proposed rule take 

conclusions from their study out of context:

• The results in the 2009 Report were mostly based on publicly available data, data 

from original equipment manufacturers, and Sargent & Lundy's power plant 

experience. Furthermore, the case studies showed that not all of the examined 

alternatives were feasible to apply to an individual generating unit due to a 

number of factors, including plant design, previous equipment upgrades, and each 

plant's operational restrictions.

• Various limitations exist for applying each heat rate improvement strategy, and 

these limitations depend on the unit type, fuel type, and many other site-specific 

conditions. Therefore, the ability to apply each strategy and the amount of heat 
381

rate reduction that can be achieved by each strategy is site-specific and must be 

evaluated on a case-by-case basis.

• It appears as though the EPA assumed that heat rate improvements cited in their 

2009 Report were additive and applicable to all coal-fired units. Heat rate 

improvement ranges described in the 2009 Report case studies were estimated at a 

conceptual level, and were not based on detailed site-specific analyses. 

Verification of actual heat rate improvements was not made determine whether 

any of the strategies were implemented and what actual heat rate improvements 

were realized based on site-specific design.

• Combinations of strategies to achieve heat rate improvements do not always 

provide heat rate improvement reductions equal to the sum of each individual 

strategy's heat rate improvement because many of the technologies affect, or are 

dependent upon, plant operating variables that are inter-related. Therefore, caseby-case analyses should be conducted to determine whether the incremental heat 

rate improvement through the application of multiple strategies is economically 

justified.

• The performance of some of the evaluated heat rate improvement strategies 

degrades over time, even with best maintenance practices. Therefore, depending 

on the strategy employed or the technology installed to reduce heat rate at an 

existing coal-fired EGU, the unit heat rate initially obtained may increase over 

time.

Commenters stated that EPA also assumes that an additional 2% heat rate improvement is 

available, on average, through equipment upgrades and that EPA's assumptions are based on a 

2009 Sargent & Lundy (S&L) study that evaluated a series of potential heat rate improvements 

opportunities, and estimated potential ranges of heat rate reduction. Commenters stated that S&L 

then applied their findings to two case studies to estimate potential improvements. Commenters 

stated that the approach that S&L used to determine potential heat rate improvements in the 

study was reasonable and practical. Commenters stated that however, the S&L study was not 

intended to address the many variables that impact the measurability, feasibility and 

sustainability of the improvement opportunities that were identified. Commenters stated that 

since the study does not contain any evidence that the recommendations from the case studies 

were actually implemented and heat rate improvements measured, there is no empirical data 

demonstrating that the estimated improvements were actually achieved or could be maintained.

Commenters stated that furthermore, EPA inappropriately used the study to assume that the types 

of improvements estimated by S&L are equally applicable and achievable at each and every 

coal-fired power plant in the country, but this is simply not the case. Commenters stated that 

many of the heat rate improvement strategies identified in the S&L report are generally not 

applicable for many coal-fired EGUs.

Commenters stated that in addition, EPA failed to consider fully several important limitations to 

the report's findings that are critical for evaluating the potential efficiency gain achievable by any 

potential heat rate improvement project and include the following:
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• Commenters stated that the improvements identified by S&L are not uniform and 

what may work for one unit, may not for another.

• Commenters stated that the heat rate benefit of multiple improvement projects is 

not necessarily cumulative. This means that improvements in one area can be 

masked by operations or conditions in another, thus diminishing any significant 

overall heat rate improvement.

• Commenters stated that the outside influences beyond the control of the unit 

operators and outside the optimized equipment design performance can reduce or 

even eliminate the heat rate gains given that these plants are dispatched based 

upon electricity demand, which is driven by external forces (e.g., customers, 

regional transmission operators).

• Commenters stated that the improvements must be cost effective and measurable 

to justify their implementation.

• Commenters stated that space constraints may exist on a particular unit that 

prohibits the addition of equipment or re-routing of ductwork/piping to implement 

a heat rate improvement project.

• Commenters stated that benefit derived from many of the suggested heat rate 

improvement technologies is finite, and will diminish over time due to the age and 

operation of the unit.

• Commenters stated that for some heat rate improvement projects, the potential 

benefits will only be apparent at full load operations, but offer no measurable 

improvements for cyclic or minimum load operations.

• Commenters stated that conversely, some base load units would show no benefit 

to heat rate if the improvement was obtained only at lower loading of the unit. 

Commenters stated that regarding the 2% "equipment upgrade opportunity," EPA relies on the 

S&L Report as its basis, however, it is clear that the S&L Report was not intended to suggest that 

a 2% generic heat rate improvement was either "achievable" or "adequately demonstrated." 

Commenters stated that the preamble recognizes that the S& L Report only "looked generically" 

at improvements "that can be made at specific types of EGUs " and the S& L Report is simply a 

listing of potential equipment changes that, if not already employed, could be considered on a 

case-by-case basis to possibly improve heat rate. Commenters stated that as the S& L Report 

shows, each measure could result in a wide range in the amount of potential heat rate 

improvement, ranging from no improvement at all to some estimated improvement. Commenters 

stated that the preamble states that the range of improvements is from 415 to 1205 Btu/KWh, or 

about a 4% to 12% heat rate improvement. Commenters noted that the higher improvement 

number is simply based on adding the best case assumption for each individual improvement. 

Commenters stated that the S&L Report makes no assertion of what fraction of the national coal 

unit fleet would actually be able to achieve specific improvement levels, however, the preamble 

jumps to an unsubstantiated conclusion that "implementation of the full subset of appropriate 
383

opportunities at a single EGU could be expected to result in an aggregate heat rate improvement 

of approximately four percent." Commenters stated that again without substantiation, the 

preamble then estimates for state goal purposes that half of the fleet would have the full (4%) 

"equipment upgrade opportunity"-and selects a 2% improvement as a goal basis. 

Commenters stated that EPA mistakenly concludes that a 2009 study conducted by Sargent & 

Lundy supports the 6% across the board heat rate improvement. Commenters stated that Sargent 

& Lundy explicitly rejected EPA's findings and stated that "Sargent & Lundy's 2009 Report does 

not conclude that any individual coal-fired EGU or any aggregation of coal-fired EGUs can 

achieve 6% [heat rate improvement] or any broad target, as estimated by the EPA." Commenters 

stated that EPA's analysis neglects to account for numerous factors that impact EGUs' process 

efficiency. Commenters stated that NERC identified these factors as: (1) subcritical versus 

supercritical boiler designs; (2) fluidized bed combustion, integrated gasification combinedcycle, and pulverized coal; (3) unit size and age; and (4) coal quality variations in moisture and 

ash. As stated earlier, SIPC installed a fluidized bed boiler in 2003, and it was labeled as 'Clean 

Coal Technology'; however, the efficiency of this technology for CO2 control is very low, 

because of the inherent design of the boiler and how it controls SO2 and NOX. 

Commenters stated that the Sargent and Lundy study on heat rate improvements was meant to 

"provide valuable information for comparative purposes when evaluating the advantages and 

disadvantages of various concepts," not to establish a roadmap for regulatory requirements 

applied to all coal-fired EGUs. Commenters stated that a 2014 study by the Nicholas Institute for 

Environmental Policy Solutions notes, "Sargent and Lundy's report only estimates potential 

improvements and does not list unit by unit efficiency gains and costs. To date, there has been no 

comprehensive analysis of the actual opportunities that exist for efficiency improvements." 

Commenters stated that furthermore, a 2014 clarification letter sent by engineers at Sargent and 

Lundy to the National Rural Electric Cooperative Association ("NRECA") says "Sargent & 

Lundy's 2009 report does not conclude that any individual coal-fired EGU or any aggregation of 

coal-fired EGUs can achieve 6% or any broad target, as estimated by the EPA." Commenters 

stated that in short, EPA's numbers are not only unrealistic, they also lack academic support. 

Commenters stated that EPA's basic approach to developing building block 1 is flawed and in 

evaluating HRI, EPA first analyzed heat rate trends over time for EGUs and then separately 

identified actions that could improve heat rates based on a report by Sargent and Lundy. 

Commenters stated that however, EPA did not directly evaluate to what extent the Sargent and 

Lundy actions can actually be implemented for any given EGU - in fact, EPA acknowledged that 

there is no real connection between the HRI actions and an actual implementation potential in 

determining the 6% HRI. Commenters stated that EPA stated that, based on its informal 

discussions with Sargent and Lundy and other power sector engineering firms:

"The EPA has found no comprehensive data set on the extent to which specific HRI methods 

have already been applied at individual EGUs. The EPA believes that many EGU owners 

consider such information to be confidential."

Commenters stated that the inferences drawn by EPA from the 2009 S&L study regarding 

aggregate heat rate improvement are inappropriate. Commenters stated that the numbers 

presented in the study did not reflect any analysis of improvements actually achieved or 

determined to be achievable at any particular EGU. Commenters cited the S&L study indicating 
384

that "Heat rate improvements described in the 2009 Report case studies were estimated at a 

conceptual level, and were not based on any site-specific detailed analysis...." 

Commenters stated that an industry group consultant has evaluated a variety of heat rate 

improvement methods cited in the Sargent & Lundy 2009 study and concluded that EPA has 

exaggerated their short-term and long-term benefits. Commenters stated that many of the payoffs 

are temporal; for example, steam turbine blades wear with time, revised and reconfigured heat 

exchangers accumulate deposits, and new condensers retrofitted to provide clean and 

uncompromised surfaces for reliability may not deliver the same heat reduction due to material 

properties and as a result, the immediate impact of a heat rate improvement measure on a unit's 

CO2 emission rate may overstate the benefits of that measure over its expected lifetime. 

Commenters stated that for many measures, a given estimate of heat rate improvement is merely 

a snapshot that changes with time and moreover, while EPA assumes that heat rate-improving 

actions are additive, many are not. Commenters stated that the Agency also fails to recognize 

that many of the actions are routinely deployed as good maintenance practice, and their 

associated benefits are already accounted for in a unit's historical emissions performance, 

meaning that remaining opportunities for additional heat rate improvements are limited and 

highly site-specific. 

Commenters stated that the Sargent-Lundy study referenced to justify the 6% plant efficiency 

improvement was misinterpreted by the CPP. Commenters stated that heat rate efficiency is often 

confused with boiler efficiency and the EPA is using incorrect methodology to estimate heat rate 

improvements. Commenters stated that Sargent-Lundy since the publication of the proposed CPP 

has attempted to clarify its position on heat rate improvements for the industry and they 

encourage the EPA to consider the additional information provided by Sargent-Lundy to 

reevaluate building block 1. 

Commenters stated that EPA's reliance on the 2009 Sargent & Lundy report for this six percent 

potential is misguided and inappropriate, as many other commenters will address. Commenters 

stated that Sargent & Lundy, in fact, takes issue with EPA's use and characterization of its 2009 

report, in an October 2014 study titled "Coal Fired Power Plant Heat Rate Reduction - NRECA." 

Commenters stated that specifically, the 2009 Sargent & Lundy report does not conclude that 

any individual coal-fired EGU can achieve six percent heat rate improvement or any broad 

target. Commenters stated that rather, the amount of heat rate reduction that a unit can achieve is 

site-specific and must be evaluated on a case-by-case basis, taking into account a number of 

factors, including plant design, previous equipment upgrades, and each unit's operational 

restrictions. Commenters stated that many FCG members have already performed the most 

beneficial heat rate improvement projects that this report references and for many FCG members, 

it is not technically feasible to improve their units' heat rate anywhere near an additional six 

percent. Commenters stated that The North American Electric Reliability Corporation (NERC) 

has also concluded that improving heat rate by six percent may not be achievable.

Commenters stated that EPA incorrectly utilizes the data in prior heat rate improvement reports, 

particularly the Sargent and Lundy report cited in the proposal, by viewing the utilization of the 

upgrade options as additive. Commenters stated that many of the recommendations overlap or 

would be negated by the implementation of additional heat rate improvement projects and 

economics aside, it would not be physically possible to implement all of the Sargent and Lundy 
385

upgrade options at a single unit to achieve the additional efficiencies to meet the required 6 

percent level. 

Commenters stated concerns over the rule's heavy reliance on the Sargent and Lundy report of 

2009. Commenters stated that first the report was 5 years old at the time of the proposed 

regulation's issuance and it will be 8-10 years old by the time state plans are finalized and 

approved therefore it can hardly be accurate with respect to the changes in the electricity industry 

in five years let alone in 10 years.

Commenters stated that EPA failed to support its claim that a 2% improvement in heat rate is 

achievable through equipment upgrades. Commenters stated that the Proposal and support 

documentation reference a 2009 Sargent & Lundy (S&L) study on heat rate improvements that 

evaluated a number of potential heat rate improvements opportunities and estimated the potential 

ranges of heat rate reduction associated with each individually and that S&L then applied the 

findings to two case studies to estimate potential improvements. Commenters stated that since 

the study does not contain any evidence that the recommendations from the case studies were 

actually implemented, there is no empirical data available to demonstrate that the estimated 

improvements were actually achieved or could be maintained.

Commenters stated that the Proposal assumes that the types of improvements evaluated by S&L 

are equally applicable and achievable at each coal-fired unit in the industry, but that assumption 

is incorrect and that there are many factors to consider in determining whether the projects 

evaluated by S&L present a realistic opportunity for heat rate improvements at an individual 

facility: 

• Improvements are not uniform and what may work for one unit, may not for 

another;

• The heat rate benefit of multiple improvement projects is not necessarily 

cumulative because improvements in one area can be masked by operations or 

conditions in another, thus diminishing any significant overall heat rate 

improvement;

• Outside influences beyond the control of the unit operators and outside the 

optimized equipment design performance can alter or erase heat rate 

improvements as these plants are dispatched based upon electricity demand, 

which is driven by external forces (e.g. customers, regional transmission 

operators, etc.);

• Improvements must be cost effective and measurable to justify their 

implementation;

• Space constraints may exist on a particular unit that prohibit the addition of 

equipment or re-routing of ductwork/piping to implement a heat rate improvement 

project;
386

• The benefit derived from many of the suggested heat rate improvement 

technologies is finite, and will diminish over time due to the age and operation of 

the unit;

• For some heat rate improvement projects the potential benefits will only be 

apparent at full load operations, but offer no measurable improvements for cyclic 

or minimum load operations that will likely be required under EPA's Proposal;

• Some units that remain base load would show no benefit to heat rate if the 

improvement was obtained only at lower loading of the unit;

• The feasibility and benefits of any potential heat rate improvement must be 

evaluated more in context with future operations that may not afford the same 

magnitude of improvement potential. 

Commenters stated that S&L itself has also disputed the conclusions that EPA reached using its

study. S&L recently submitted a letter to the National Rural Electric Cooperative Association to 

confirm that EPA's conclusions cannot be supported by its 2009 study. Commenters stated that 

according to S&L:

• Sargent & Lundy's 2009 Report does not conclude that any individual coal-fired 

EGU or any aggregation of coal-fired EGUs can achieve 6% HRI [heat rate 

improvement] or any broad target, as estimated by the EPA.

• Various limitations exist for applying each heat rate improvement strategy, and 

these limitations depend on the unit type, fuel type, and many other site-specific 

conditions. Therefore, the ability to apply each strategy and the amount of heat 

rate reduction that can be achieved by each strategy is site-specific and must be 

evaluated on a case-by-case basis.

• Combinations of strategies to achieve heat rate improvements do not always 

provide heat rate improvement reductions equal to the sum of each individual 

strategy's heat rate improvement because many of the technologies affect, or are 

dependent upon, plant operating variables that are inter-related.

• [A]ny [heat rate improvements] achieved by undertaking the relevant options 

described in S&L's 2009 Report could, in some cases, be negated by [heat rate] 

losses associated with load-cycling.

• Based on the case studies performed by S&L, it appears that most of the utilities 

are employing best operational and maintenance practices. In light of this 

observation, it appears that significant further reduction in heat rate, such as that 

assumed by the EPA, may not be feasible.

Commenters referred to a letter from Raj Gaikwad, Ph.D., Vice President, Advanced Fossil 

Technologies, Sargent & Lundy to Mr. Rae Cronmiller, Sr. Principal Environmental Counsel, 

National Rural Electric Cooperative Association (Oct. 15, 2014). Commenters stated that in light 
387

of these statements from S&L, the author of the report upon which EPA relies so heavily, EPA

should reconsider its conclusions regarding the level of heat rate improvement that is achievable 

at existing coal-fired power plants. 

Commenters stated EPA cites other evidence to support its heat rate improvement assumptions in 

Chapter 2 of its GHG Abatement Measures Technical Support Document, but that evidence also 

fails to provide sufficient support for EPA's building block 1 assumptions. 

Commenters stated that EPA's conclusion that a 2 percent fleet-wide HRI could be achieved by 

equipment upgrades is based on the Sargent & Lundy report. Commenters stated that EPA 

identified four types of measures that (together) could result in a 4 percent HRI and EPA 

assumed that half of the 4 percent reduction had already been achieved, reducing the estimate for 

future HRI to 2 percent. Commenters stated that the 50 percent downward adjustment to reflect 

measures already taken is arbitrary and lacks any supporting analysis by EPA. 

Commenters stated that regarding the 2 percent "equipment upgrade opportunity," EPA relies on 

an S&L report as its basis, however, as indicated in a letter from S&L to LCRA, it is clear that 

the S&L report is not consistent with EPA's conclusions. Commenters stated that report was not 

intended to suggest that a 2 percent generic heat rate improvement was either "achievable" or 

"adequately demonstrated," and while EPA's preamble recognizes that the S&L report only 

"looked generically" at improvements "that could be made at specific types of EGUs," EPA fails 

to recognize this limitation. Commenters stated that the S&L report is simply a listing of 

potential equipment changes that, if not already employed, could be considered on a case by case 

basis to possibly improve heat rate. Commenters stated that the S&L report makes no assertion 

of what fraction of the national coal unit fleet would actually be able to achieve specific 

improvement levels and moreover, the report does not claim the improvement from the potential 

projects are additive. Commenters stated that stand-alone heat rate efficiencies which might be 

available in a boiler or turbine can potentially affect the efficiencies available for other projects. 

Commenters stated that however, the preamble jumps to an unsubstantiated conclusion that 

"implementation of the full subset of appropriate opportunities at a single EGU could be 

expected to result in an aggregate heat rate improvement of approximately four percent." 

Commenters stated that again without substantiation, the preamble then, for state goal purposes, 

estimates that half of the fleet would have the full (4 percent) "equipment upgrade opportunity" -

and selects a 2 percent improvement as a goal basis, which appears to be arbitrary. 

Commenters stated that EPA cannot justify using the hypothetical and generalized assumptions 

in the Sargent & Lundy report to make real-world projections of the potential for heat rate 

improvements at existing coal-based plants and most of the items identified by Sargent & Lundy 

offer little or no significant potential for heat rate improvements at Basin Electric's facilities. 

Commenters stated that similarly, there is no basis for EPA to assume that the generic options 

discussed by Sargent & Lundy are actually and typically available and feasible at other EGUs. 

Commenters stated that Sargent & Lundy has submitted comments to EPA that explain how EPA 

has fundamentally misapplied a 2009 study by that firm and further explain that unit-specific 

analyses - which EPA has not conducted - are necessary to determine any potential heat rate 

improvements.
388

Commenters stated that EPA purports to rely on a study by Sargent & Lundy ("S&L") from 

2009, however, as Sargent & Lundy has confirmed in comments filed with EPA, EPA has 

skewed and mischaracterized the results, leaving EPA's total heat rate improvement of 6% 

unsupported by the S&L Study. Commenters stated that the report does not demonstrate that the 

heat rate improvements assumed in EPA building block 1 are achievable and as S&L has 

explained, "information in the 2009 S&L Report was incorrectly applied in [EPA's] GHG 

Abatement Measures TSD to determine potential heat rate reductions and total HRI capital costs" 

and the 2009 report cannot be extrapolated to support EPA's target. Commenters stated that 

indeed, S&L has confirmed that its 2009 Study "does not conclude that any individual coal-fired 

EGU or any aggregation of coal-fired EGUs can achieve 6% [heat rate improvement] or any 

broad target, as estimated by the EPA." S&L confirmed that "[v]arious limitations exist for 

applying each heat rate improvement strategy, and these limitations depend on the unit type, fuel 

type, whether the improvement has already occurred, and many other site-specific conditions. 

Commenters stated that therefore, the ability to apply each strategy and the amount of heat rate 

reduction that can be achieved by each strategy is site-specific and must be evaluated on a caseby-case basis." Commenters stated that contrary to EPA's use of the study, S&L explains that 

"[t]he 2009 Report case studies were estimated at a conceptual level, and were not based on 

detailed site-specific analyses." EPA has failed to conduct the site-specific analysis that S&L 

confirms is required and thus has not adequately demonstrated its building block 1.

Commenters stated that while EPA believes that a 4% improvement in heat rate may be possible 

with employment of "best practices," S&L states that "it appears that most of the utilities are 

employing best operational and maintenance practices. In light of this observation, it appears that 

significant further reduction in heat rate, such as that assumed by the EPA, may not be feasible."

Commenters stated that this is the case for Luminant's units.

Commenters stated that when judged against real world conditions, the S&L Study simply 

cannot be extrapolated to the Texas fleet, much less the entire U.S. generation fleet. Commenters 

stated that EPA concedes that the "details of current actual unit configurations are unknown" to 

it. Commenters stated that EPA failed to take into consideration "the potential degradation of 

heat rate improvements over time," and this is a necessary consideration because, as S&L 

recognized, "the performance of many of the [heat rate improvement] methods included in the 

[S&L Report] will degrade over time, even with best maintenance practices." Commenters stated 

that moreover, EPA's block 1 segmented analysis is fundamentally flawed and ill-conceived and 

the heat rate impacts of operational practices and equipment changes cannot be easily 

distinguished and are not cumulative in many cases, as EPA assumes. Commenters stated that 

EPA erroneously adds a 2% heat rate improvement based on the S&L Study for equipment 

upgrades to an additional 4% improvement based on "best practices." Commenters stated that 

yet, in the S&L study and supporting case studies, "best practices" such as combustion 

optimization were considered along with equipment upgrades. Commenters stated that S&L's 

case study of an 850 MW unit evaluated all options and it was reduced air leakage and 

combustion optimization ("best practices") -not equipment upgrades - that accounted for the 

majority of the 1.2% improvement estimated. Commenters stated that given each site requires 

site-specific analysis, and EPA acknowledges this point, it is unreasonable for EPA to misuse the 

results as it has, much less for EPA to rely upon the S&L Study at all in support of its building 

block 1 target.
389

Commenters stated that while EPA contends that "884 distinct EGUs" were included in its "study 

population," it was only able to identify two cases in which it could "identify equipment 

upgrades responsible for 2-3% overall heat rate improvement using the applicable estimates from 

the Sargent & Lundy 2009 study." Commenters stated that despite relying solely on the S&L 

Study "as the basis for [its] assessment of heat rate improvement potentials from equipment and 

system upgrades," the most EPA could conclude was "upgrades . . . could provide a 4% heat rate 

improvement if all were applied on an EGU that has not already made these upgrades." 

Commenters stated that EEI points out several flaws in the EPA's conclusion that heat rate can 

be improved by two percent through equipment upgrades. Commenters stated that this evaluation 

relied largely on a Sargent & Lundy report to demonstrate that investment in upgrades could 

result in a heat rate improvement of two percent and included Economizer replacement, Acid 

dew point control, Combined VFD (variable frequency drive) and fan replacement, and Turbine 

overhaul.

Commenters stated that as EEI points out, there was no attempt to determine which units had 

already performed these or similar upgrades on existing units, and therefore could not benefit 

from such an investment and moreover, there is little to no evidence presented that would 

support a two percent available improvement is available for the entire coal fleet in the country. 

Commenters stated that further, the applicability of this assumed two percent improvement to a 

state generating fleet or to any particular utility is very dependent on the benefit that prior 

investments may have been produced.

Commenters stated that DTE has always considered the impacts on unit efficiency and heat rate 

in their capital improvement process and several of the projects cited in building block 1 have 

already been implemented at their plants. Commenters stated that it is very unlikely that the 

further implementation of such "upgrades" would produce an improvement in the existing coal 

fleet heat rate of two percent. 

Commenters stated that contrary to EPA's assumptions, many of the potential heat rate 

improvements identified in the Sargent & Lundy report are non-additive, temporal, and highly 

site-specific and as Sargent & Lundy explained in a recent letter to the Natural Rural Electric 

Cooperative Association (NRECA): Combinations of strategies to achieve heat rate 

improvements do not always provide heat rate improvement reductions equal to the sum of each 

individual strategy's heat rate improvement because many of the technologies affect, or are 

dependent upon, plant operating variables that are inter-related. Therefore, case-by-case analyses 

should be conducted to determine whether the incremental heat rate improvement through the 

application of multiple strategies is economically justified.

Commenters stated that in addition, the Sargent & Lundy study was completed in 2009, three 

years before the 2012 baseline year on which EPA has based its proposed state goals, thus, the 

improvements cited in the study-to the extent they are feasible or cost-effective at all- could have 

been implemented already by power plants because power plant owners have an incentive to 

make their units as efficient as possible. Commenters stated that in other words, some of these 

improvements could already be reflected in the 2012 baseline, which means that few additional 

heat rate improvements will be achievable in practice.
390

Commenters stated that based on these serious methodological shortcomings, EPA erred in 

concluding the Sargent & Lundy study supports a two-percent heat rate improvement as a part of 

Building Block 1. 

Commenters stated that EPA relies on an incorrect interpretation of a 2009 Sargent & Lundy 

engineering analysis of the potential for heat rate improvements at existing coal units.

Commenters stated that citing the Sargent & Lundy study, EPA concludes that a two-percent 

heat rate improvement can be achieved by all existing coal units. Commenters stated that the 

Sargent & Lundy analysis lists a series of actions that can be taken by plant owners or operators 

to improve their units' heat rate by a certain amount and at a certain cost, and in order for EPA to 

conclude a two-percent improvement is possible, an analysis of the extent to which these heat 

rate improvements apply to every unit in the entire existing coal fleet would be needed. 

Commenters stated that Sargent & Lundy's study does not provide this type of analysis, in fact, 

nowhere in the study do the authors attempt to conclude what types of improvements could be 

undertaken at specific units in the coal fleet, or that two percent would be representative of such 

an improvement, rather, the Sargent & Lundy report uses a literature survey and vendor data to 

present a "laundry list" of potential or hypothetical improvements that might be achievable, as 

opposed to actual case-by-case analysis. 

Commenters stated that while EPA stated in the Preamble to the rule that the Agency considered 

a number of efficiency studies, EPA relied solely on just one- a Sargent and Lundy 2009 report. 

Commenters stated that the authors of the report state in a letter that their 2009 report"... does not 

conclude that any individual coal-fired EGU or any aggregation of coal-fired EGUs can achieve 

6% HRI or any broad target, as estimated by EPA. Commenters stated that Sargent and Lundy 

states that the strategy and amount of heat rate improvement that can be achieved is"... site 

specific and must be evaluated on a case-by-case basis." Commenters stated that Sargent and 

Lundy describe the case studies in the 2009 report as "estimated at the conceptual level." 

Commenters stated that clearly, EPA has interpreted the Sargent and Lundy study incorrectly and 

needs to follow the company's advice that"... case-by-case analyses should be conducted to 

determine whether the incremental heat rate improvement through the application of multiple 

strategies is economically justified." 

Commenters stated that Sargent & Lundy has recently addressed EPA's misuse of the S&L 

Study. Sargent & Lundy noted that "the only technically appropriate method to properly evaluate 

potential heat rate improvements is to conduct a unit-by-unit evaluation" Sargent & Lundy 

further clarified the conclusions of its 2009 report:

• No conclusion was made that any individual EGU or aggregation of EGUs could 

achieve a 6 percent heat rate improvement or any broad target;

• Case studies showed that not all of the heat rate improvement could be applied to 

individual units;

• Implementing heat rate improvements are limited due to unit type, fuel type, and 

many other site-specific conditions;

• Heat rate improvements cannot be assumed as additive;
391

• Verification of actual heat rate improvements at individual units were not made;

• Plant operating variables impact the economics of and heat rate reductions from 

projects;

• Some heat rate improvements degrade over time, even with best maintenance 

practices;

• Heat rate is impacted by a unit's load factor;

• Environmental controls will decrease a unit's heat rate; and

• Many projects listed by the report have triggered New Source Review.

Commenters stated that additionally, while EPA purports to identify a variety of heat rate 

improvement measures it classifies as "equipment upgrades," EPA did not account for the 

obvious fact that many plants have already undertaken "equipment upgrades" and those upgrades 

cannot be duplicated for an added benefit. Commenters stated that for example, of the heat rate 

improvement measures proposed in a Sargent & Lundy Study relied upon by the EPA, none of 

the listed projects are even potentially physically available for the units at Lowman and 

furthermore, these so-called projects could not provide sustained improvement to heat rate. 

Commenters stated that coal-fired plants and their efficiency improvements degrade over time 

and as such, the level of heat rate improvement that may initially be achieved by any certain 

project will only be temporary. Commenters stated that this is because any "improvements" are 

essentially only making up for lost efficiency and are better understood as efficiency 

"maintenance".

Commenters stated that the Ohio Utilities do not think technical information exists to show how 

the six percent (6%) heat rate improvement is achievable. Commenters stated that U.S. EPA has 

relied on the Sargent & Lundy report and incorrectly applied cumulative improvements in a 

manner inconsistent with how the study was conducted. Commenters stated that not all of the 

projects can be implemented at once and the cumulative reductions cannot be achieved. 

Commenters stated that all considered, the 6% improvement target is a gross overestimation 

considering what can be achieved. It further ignores impacts of other building blocks. 

Commenters referred to a letter sent to the National Rural Electric Cooperative Association 

(NRECA) on October 15, 2014 by Sargent & Lundy that submits conclusions of the study that 

the EPA used. 

• Sargent & Lundy's 2009 Report does not conclude that any individual coal-fired EGU or 

any aggregation of coal-fired EGUs can achieve 6% heat rate improvement (HRI) or any 

broad target, as estimated by the EPA.

• Based on case studies performed by S&L, it appears that most of the utilities are 

employing best operational and maintenance practices. In light of this observation, it 

appears that significant further reduction in heat rate, such as that assumed by the EPA, 

may not be feasible."
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• Sargent & Lundy concludes that the only technically appropriate method to properly 

evaluate potential HRI is to conduct a unit-by-unit evaluation.

Commenters also attached a report by Sargent & Lundy titled, "Coal Fired Power Plant Heat 

Reduction-NRECA", Attachment B and stated that the purpose of this report is to conduct a 

review of potential heat rate improvements that can be applied to existing coal-fired power plants 

and to identify potential limitations in applying these technologies. Commenters stated that in 

this report S&L concludes that the EPA misinterpreted the 2009 S&L report and indicated many 

flaws in the EPA's assumptions including examples from Cooperative EGUs, which show a 6% 

HRI is not possible at most EGUs. 

Commenters stated that Building Block 1 is not generally achievable on a national basis. 

Commenters stated that EPA relies on a 2009 study by Sargent & Lundy ("S&L") to show that 

heat rate improvements can be used as a means of reducing CO2 emissions from coal-fired 

plants, and claims that "EPA believes that implementation of all identified best practices and 

equipment upgrades at a facility could provide total heat rate improvements in a range of 

approximately 4 to 12 percent." Commenters stated that EPA's reliance on the S&L study fails to 

fully address the many limitations of using any analysis that is not unit-specific and contrary to 

EPA's assertions, the S&L Study did not conclude that any individual coal-fired EGU could 

achieve a 6% reduction in heat rate or any other specific target. Commenters stated the case 

studies used as the basis for that report shows that not all of the examined alternatives for

improving heat rate performance were feasible to apply to any individual unit, and that all sitespecific considerations must be addressed to determine whether any specific improvement will 

actually work at the unit in question and, if so, what incremental result would be achieved. 

Commenters stated combinations of strategies to achieve heat rate improvements are not additive 

and depend on interrelated plant operating variables. Commenters stated case-by-case analyses 

are required to determine the viability and projected outcome of multiple strategies. Commenters 

stated moreover, the performance of some strategies will degrade over time, resulting in 

diminished efficiency improvements. Commenters stated heat rate generally increases when 

plants operate at lower loads, reducing the benefit of any installed improvement. EPA's plan to 

generally decrease the capacity factor of coal-fired EGUs will degrade the benefit of such 

improvements and, in some cases may negate benefits entirely. Commenters stated in other 

words, no guarantee exists that a measure that improves heat rate at one facility will be 

successful - or as successful - when implemented at another facility, or that any successful effect 

of a particular measure will extend beyond the immediate time period after the measure was 

implemented. Commenters stated EPA's analysis of potential heat rate improvements is arbitrary, 

because it fails to consider units on a case-by-case basis and that type of analysis remains the 

purview of the states in the CAA section 111(d) process, once EPA promulgates emissions 

guidelines that the state uses to make its individual source decisions about the proper 

performance standard for the unit in question. 

Commenters stated that a principal component of EPA's BB1 proposal is that a 6 percent HRI 

that EPA estimates will be achievable as a coal generation fleet average. Commenters stated that 

PAPUC has examined the EPA's Technical Support Document, GHG Abatement Measures that 

provides the analytical support for EPA's recommended 6 % HRI factor. Commenters stated that 

the PAPUC finds the analysis to be technically thorough but offers some comments and 

observations.
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Commenters stated that EPA's analysis relies principally on a 2009 Sargent & Lundy (S&L) 

Study that examined the efficacy of a variety of HRI methods applied across the entire U.S. coal 

generation fleet. Commenters stated that the S&L Study derived an average cost for HRI in 

$/kW. Commenters stated that EPA's analysis then reviewed HRI data and applied an assumed 

average cost of $100/kW, a capital charge rate of 14.3% and a 2020 annual capacity factor of 

78% to derive a coal fleet average 2020 net heat rate of 10,450 Btu/kwh and a HRI factor of 6 

percent.

Commenters noted that EPA's analysis did not rely on site specific information to accurately 

estimate what percentage of the coal generation fleet has adopted any of the various HRI 

methods. Commenters stated that EPA's analysis did not examine the potential for heat rate 

reductions either in PA specifically or the PJM region generally. Commenters stated that also, 

many PA coal-fired generation owners have already made substantial HRI investments prior to 

2012 and further reductions may not be possible. Commenters stated that while the PAPUC 

appreciates that this specific information may not be available, there are certain considerations 

regarding the PJM (and PA-specific) generation fleet that should be considered. 

Commenters stated that in developing the 6 percent HRI target, the EPA heavily relied on the 

gross HRI methods described in the 2009 Sargent & Lundy (S&L) report "Coal-Fired Power 

Plant Heat Rate Reductions," alongside a statistical analysis of reported gross generation and 

heat rate data from the years 2002-2012.

Commenters stated that EPA, however, has made incorrect assumptions and factual errors in its 

development of the 6 percent HRI goal for Building Block 1. Commenters stated that the EPA 

calculated the proposed average 6 percent HRI potential using two fundamentally different and 

equally flawed methods:

• A 4 percent HRI based on the implementation of low to no-cost "best practices" 

that were mentioned in the S&L report. Instead of using actual reports of HRI 

experience or even the estimated benefit ranges from the S&L report, the 4 

percent HRI was merely calculated from a statistical analysis of gross heat rate 

data from 2002-2012 and the erroneous assumption that reducing heat rate 

variability in the data will produce an average heat rate improvement

• A 2 percent HRI resulting from high cost equipment upgrades listed in the S&L 

report that the EPA has assumed have both additive benefits and are still available 

to most units to implement. 

Commenters stated that nowhere in the S&L report does it even suggest that heat rate 

improvements from the various methods discussed in the report are or can be considered to be 

additive. Commenters stated that the EPA has also assumed that the majority of these measures 

have not yet been employed by coal-fired EGUs, that no limitations or barriers exist that would 

prevent their adoption, that the actual HRI will not vary by unit, and the HRI gains will not 

degrade over time. 

Commenters stated EPA relied almost exclusively on the 2009 S&L report. Commenters stated 

that while "best practices" and "equipment upgrades" can improve heat rates and reduce emission 
394

rates, the use of a single report is not a sufficient basis for concluding that the nationwide coalfired EGU fleet can, on average, achieve a 6 percent HRI. Commenters stated that it should be 

noted that the EPA examined reported gross heat rate data in the context of the "best practices" 

analysis, but ultimately rejected without explanation this approach for the purpose of assessing 

the HRI potential of "equipment upgrades." Commenters stated that the S&L report is a good 

guide as to what potential heat rate improvement methods may be available, but it is not 

authoritative or exhaustive. In its interpretation of the S&L report, however, the EPA has failed 

to recognize that the report was specific to full-load operation, that the HRI methods mentioned 

were not necessarily cumulative, and that unit specifics may limit or prevent the use of the 

suggested HRI opportunities. Commenters stated that the S&L report also did not address the

impact of flexible operations such as cycling, load following, and extended low load periods on 

coal-fired EGU heat rates or the potential change in benefit of the identified HRI methods due to 

flexible operation. Commenters stated that the S&L report was published in 2009 based on data 

and costs available in 2008 and many of the key heat rate improvement opportunities addressed 

in the report have already been implemented at coal-fired EGUs alongside the installation of 

pollution controls such as selective catalytic reduction and flue gas desulfurization technologies 

and fall within the 2012 baseline used in the development of the state goals, and are no longer 

available to contribute to the 6 percent goal. Commenters stated any estimates of implementing 

HRI on existing coal-fired EGUs must therefore be based on an analysis of the remaining HRI 

potential at individual units. Commenters stated that finally, the realistic HRI achievable for any 

given coal-fired EGU is unique to its original design limitations, age, condition, additions of 

pollution controls, and the degree it employs flexible operations. Therefore, commenters stated, 

unit specific research and data must be used to assess HRI because there is no such thing as an 

average coal-fired EGU, and the EPA's approach that resulted in the identification of a national 

average HRI is without merit. 

Commenters stated that EPA relies on a 2009 Sargent & Lundy (S&L) study to support its 

finding that best operating practices and equipment replacements can achieve a 6% or greater 

heat rate improvement. S&L never intended for the 2009 study to be used to predict technical 

feasibility of a 6% heat rate improvement across the entire fleet of fossil fuel-fired EGUs. 

Commenters stated that in a October 15, 2014 letter to Rae Cronmiller at NRECA (attached), 

S&L clarified that the "2009 Report does not conclude that any individual coal-fired EGU or any 

aggregation of coal-fired EGUs can achieve 6% [heat rate improvement] or any broad target, as 

estimated by the EPA." Commenters stated that S&L notes that the only "technically appropriate 

method to properly evaluate potential [heat rate improvement] is to conduct a unit-by-unit 

evaluation." Commenters stated that obviously, EPA's reliance on the S&L study is misplaced 

and cannot form the technical basis for Building Block 1. Commenters stated that S&L notes that 

"many of the options for [heat rate improvement] listed in their 2009 report have triggered New 

Source Review actions by EPA and others." Commenters stated that EPA provides no NSR relief 

in the proposal making such options unlikely to occur. 

Commenters stated that U.S. EPA also cites the results of a HRI study provided by U.S. EPA 

Region 7 for seven coal-fired units with details on capital upgrades and maintenance activities 

and measured HRIs. [GHG Abatement Measure TSD, Page 2-32] Commenters stated that U.S. 

EPA states these activities led to anywhere from a 0.25 to 3.5% HRI at the seven plants and 

examination of this data reveals that the majority of demonstrated, measured HRIs at the seven 

coal-fired power plants are characterized directly by Region 7 as "returning unit performance to 
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original design performance; " thus, these measures are maintenance activities and cannot be 

adequately characterized as permanent HRIs. Commenters stated that the effects of these 

activities degrade over time. Commenters stated that Sargent & Lundy acknowledge in their 

October 15, 2014 letter that "the performance of some of the evaluated heat rate improvement 

strategies degrade over time, even with the best maintenance practices. Therefore, depending on 

the strategy employed or the technology installed to reduce heat rate at an existing coal-fired 

EGU the unit heat rate initially obtained may increase over time." (provided in Appendix C of 

comment) 

Commenters stated that Ohio EPA understands via stakeholder outreach that the regular 

maintenance during a planned boiler/generator outage is done to restore, as much as possible, the 

unit to its original design performance. Commenters stated that the assumption that these 

activities are not already occurring universally across the existing coal-fired fleet is simply not 

appropriate and furthermore, the Region 7 study reveals that capital improvements were limited 

to turbine efficiency upgrades and variable frequency drives. Commenters stated that the largest 

HRI resulting from these capital expenditures was 1.83%. Ohio EPA understands that the effects 

of variable frequency drives are realized primarily when the unit is cycled, and have very little 

impact on heat rate for base-load serving units. Commenters concluded that U.S. EPA is not 

giving the results of the available measured HRI studies enough weight when setting a 

nationwide goal, nor does Ohio EPA believe that U.S. EPA considered whether such measures 

and practices have already been undertaken or are a part of routine maintenance activities at 

individual units. 

Commenters stated that in reviewing the available heat rate materials provided by U.S. EPA in 

support of the proposed rule, Ohio EPA could not find an instance of HRI projects demonstrating 

measured net HRIs of 6% or better. Commenters stated that indeed, the results are considerably 

less so when those activities considered maintenance or best practice are eliminated due to their 

temporary nature and the likelihood that these activities and practices are already being 

conducted. Commenters stated that even Sargent & Lundy acknowledge based on their case 

studies "it appears that most of the utilities are employing best operational and maintenance 

practices" and "it appears that significant further reduction in heat rate, such as that assumed by 

the EPA, may not be feasible." 

Commenters stated that with respect to U.S. EPA using one single study, the Sargent & Lundy 

Study (S&L Study), to determine the type and degree of HRIs that are possible to be achieved 

nationwide. Commenters stated that this is not sound science and after reviewing the 

aforementioned study, Ohio EPA has determined that the purpose was to examine potential HRI 

opportunities and potential heat rate reductions over a wide range of sources. Commenters stated 

that Ohio EPA finds that the methodology and results of the study very general and cannot be 

applied to every EGU, but what the study does not do is present an analysis of the application of 

the recommended improvement opportunities, nor does the study present measured heat rate 

reductions after the application of suggested/proposed improvement methods. Commenters 

stated that there is no empirical data demonstrating the real-world application of such measures; 

such an undertaking was simply not the purpose of the study. Commenters stated that use of the 

S&L Study as a foundation for demonstrated HRIs is an oversimplification of the complexities 

and variability in coal plant design and function. Commenters stated that in many cases, the 

potential projects referenced for HRIs are not functionally applicable to specific units. 
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Commenters stated that for example, replacing economizers for better performance could cause 

additional problems such as: fouling issues can arise in finned tube designs depending on type of 

coal used; corrosion, ash deposition and increased use of preheaters are needed for reduced exit 

temperatures which increase heat-rate; and lower temperatures sent to SCRs can sacrifice SCR 

efficiency. 

Commenters believed that the use of such a study to propose uniform application of heat rate 

reductions nationwide is not an appropriate approach and this is particularly true when the 

totality of the individual building blocks represent, according to U.S. EPA, the BSER. 

Commenters believed that the BSER can only be a demonstrated methodology based on 

measured data and analyzed on a unit-by-unit basis. Commenters stated that Ohio EPA 

understands that many, if not most, of the measures proposed in the S&L Study could be 

classified as maintenance activities with no long-term impact on heat rates and also understands 

that the majority of utilities operating coal-fired EGUs in the State of Ohio conduct regular 

maintenance activities similar to those proposed in the S&L Study, and maintain strict bestpractice policies. Commenters stated that in addition, after MATS triggered shutdowns of older 

units, Ohio's fleet will consist of upgraded and efficient units for which most potential upgrades 

have already been made and furthermore, U.S. EPA does not recognize that HRIs are likely to 

not be cumulative, and certainly not correlated on a one-to-one basis with the CO2 rate intensity, 

as is presented in the Goal Setting TSD. Commenters stated that finally, the cost estimates are 

presented in the S&L Study with the following caveat, "The costs should not be used as a basis 

for project budgeting or financing purposes" rather S&L recommends "site-specific evaluations 

and cost analyses based on actual market conditions for any and all required equipment, material 

and labor at the time of the project" should be performed. Commenters stated that however, U.S. 

EPA used these costs as part of their basis of cost compliance noting that the "most detailed 

estimates of the average costs required to achieve the full range of heat rate improvements come 

from the 2009 Sargent & Lundy study." 

Commenters stated that costs were based on 2008 equipment purchases when under this 

proposed rule many sources would be implementing these improvements during the 2020 to 

2030 compliance period. Commenters believed that this represents a further misuse of the S&L 

Study and the data contained therein. 

Commenters stated that the S&L Study alone was used to inform the ability for sources to 

achieve HRIs through equipment upgrades. Commenters stated that U.S. EPA used the estimated 

ranges of potential HRI achievable through a variety of equipment upgrades identified in the 

S&L Study. Commenters stated that they were screened into a subset to identify what U.S. EPA 

considers to be a reasonable subset of equipment upgrades that would generally be beyond the 

scope of investments they would expect to be made for purposes of achieving the best-practices 

HRIs and based on the average of the study's ranges of potential HRIs from implementation of 

this full subset of HRIs, it is expected any single EGU could achieve an aggregate HRI of 4% 

from equipment upgrades alone. Commenters stated that however, U.S. EPA recognizes that this 

may overstate the opportunity across all EGUs because some EGUs may have already 

implemented some of these upgrades. Commenters stated that U.S. EPA is therefore proposing 

on average across the fleet of affected EGUs, the "technical potential" for a 2% HRI 

improvement opportunity due to equipment upgrades. Commenters stated that U.S. EPA is also 

considering increasing this figure up to four percent.
397

Commenters disagreed and stated that U.S. EPA did not perform any analysis to determine if 

there is a true "technical potential" of 2% HRI from equipment upgrades that is cost-effective for 

each individual EGU. Commenters stated that U.S. EPA is assuming "technical potential" at each 

individual unit based on using an assumed average from one inappropriately applied study and 

even U.S. EPA acknowledges in the proposal for modified and reconstructed sources that 

"upgrades could provide a 4% HRI "if all were applied on an EGU that has not already made 

those upgrades." Commenters stated that further, under the modified and reconstructed proposal 

U.S. EPA contemplates if there are circumstances where inclusion of the 2% reduction is not 

appropriate, for example if it's unnecessary or not reasonable due to recent upgrades. 

Commenters stated that under the modified and reconstructed proposal U.S. EPA contemplates 

recent upgrades may make a 2% reduction from HRIs unreasonable yet that same consideration 

is not afforded under this proposal. Commenters stated that under the modified and reconstructed 

proposal U.S. EPA contemplates whether a case-by-case basis evaluation to determine the rate 

should apply. Commenters whole heartedly believed if U.S. EPA intends to implement the 

Section 111(d) proposal in a manner in which it has been proposed that the state should be 

evaluating units on a case-by-case basis and the only way to determine true "technical potential" 

for HRIs is a unit-by-unit analysis based upon consideration of historical upgrades.

Commenters stated that Sargent & Lundy, in a letter dated October 15, 2014, clarified the 

conclusions in their study with respect to U.S. EPA assumptions under this proposal. 

Commenters stated that the Sargent &Lundy letter reiterates and reinforces many of the 

conclusions drawn by Ohio EPA; specifically, Sargent & Lundy clarified the report "does not 

conclude that any individual coal-fired EGU or an aggregation of coal-fired EGUs can achieve 

6% HRI or any broad target, as estimate by EPA." Commenters stated that they acknowledge the 

report is mostly based on publicly available data, their experience, and that the case studies 

showed "not all of the examined alternatives were feasible...due to a number of factors, including 

plant design, previous equipment upgrades, and each plant's operational restrictions." 

Commenters stated that Sargent & Lundy clarify there are limitations for HRIs and they depend 

on "site-specific conditions" such as fuel type and unit type and "must be evaluated on a case-bycase basis."

Commenters stated that Sargent & Lundy also make the point in their October 15, 2014 letter 

that the improvement ranges described in the report "were estimated at a conceptual level", 

"were not based on detailed site-specific analysis," and "verification of actual heat-rate 

improvements was not made to determine whether any of the strategies were implemented and 

what actual heat rate improvements were realized."

Commenters stated that furthermore, Sargent & Lundy emphasized that "combinations of 

strategies to achieve heat rate improvements do not always provide heat rate improvement 

reductions equal to the sum of each individual strategy's heat rate improvement because many of 

the technologies affect, or are depend upon, plan operating variables that are inter-related. 

Therefore, case-by-case analyses should be conducted to determine whether the incremental heat 

rate improvement through the application of multiple strategies is economically justified."

Commenters stated that the very fact that the authors of the study U.S. EPA based the majority of 

its HRI goal-setting methodology upon refute U.S. EPA's assumptions and reliance on said study 

is powerful and irrefutable evidence that U.S. EPA's methodology is flawed and unsuitable for 

proposal as part of a BSER. 
398

Commenters stated that heat rate improvement estimates provided in the 2009 S&L Report were 

applied incorrectly in the GHG Abatement Measures TSD when the HRI methods were 

combined as though they were applied to a single EGU to establish a combined fleet-wide 

minimum/maximum heat rate improvement range of 415-1,205 Btu/kWh. Commenters stated 

that by combining HRI methods in the 2009 S&L Report, EPA overestimated the fleet-wide heat 

rate improvement potential. 

Commenters stated that heat rate improvement opportunities included in the 2009 S&L Report 

cannot be combined as though they were applied to a single EGU. Commenters stated that the 

report analyzed each method independently for three boiler sizes (200 MW, 500 MW and 900 

MW) and applied a range of heat rate improvement potentials and capital costs to each size 

category. Commenters stated that the report also includes discussion of the applicability, 

effectiveness, and some of the limitations associated with each method. Commenters stated that 

additional limitations would also be identified when unit-specific HRI audits are performed on 

individual EGUs. Commenters stated that case studies included in the report demonstrate that it 

would not be feasible to apply all of the examined alternatives from the study to an individual 

generating unit due to a number of factors, including, but not limited to, plant design, previous 

equipment upgrades, and existing operation and maintenance practices. Commenters stated that 

the ability to apply each HRI method, and the amount of heat rate reduction that can be achieved, 

is site-specific and must be evaluated on a case-by-case basis.

Commenters stated that by combining all HRI methods as though they were all applied to a 

single EGU, the GHG Abatement Measures TSD overestimates both the minimum and 

maximum potential heat rate improvement that may be achieved on a fleet-wide basis. 

Commenters stated that for example, in its Min-Max evaluation, EPA presumably included a 

minimum 30 Btu/kWh improvement with the installation of intelligent sootblower (ISB) 

technology, however, S&L's report states that boiler efficiency improvements obtained by 

installing ISP systems "on older boilers" have ranged from 0.3 to 0.9 percentage points, and that 

"specific performance improvement depends on the type of fuel used and the age of the furnace." 

Commenters stated that furthermore, the heat rate improvement ranges included in the 2009 S&L 

Report were, by necessity, based on the assumption that the unit under consideration could 

benefit from such a system. Commenters stated that minimum heat rate improvements listed in 

the report would not be realized on units that have already implemented the HRI method or on 

units on which the HRI method is not technically feasible, nevertheless, EPA applied a minimum 

heat rate improvement of 30 Btu/kWh for ISB projects in its Min-Max evaluation.

Commenters stated that similarly, the 2009 S&L Report included minimum heat rate 

improvements for other HRI methods including: 50 Btu/kWh for economizer upgrades; 10 

Btu/kWh for air heater leakage; 50 Btu/kWh for acid dew point reductions; 30 Btu/kWh for 

condenser cleaning and maintenance; 25 Btu/kWh for boiler feed pump overhaul; 10 Btu/kWh 

for combined variable frequency drives (VFD) and fan modifications; and 100 Btu/kWh for 

turbine overhauls. Commenters stated that all of these "minimums" assume that the HRI method 

is technically feasible and that the method is not currently utilized by the unit. Commenters 

stated that combining all of the HRI methods to establish a minimum expected fleet-wide heat 

rate improvement is not a valid use of the data provided in the 2009 S&L Report.
399

Commenters stated that EPA acknowledged that its 4% to 12% average improvement was based 

on the assumption that all units were able to apply all of the combined HRI methods, and that "a 

significant fraction of the coal fleet has already applied some or many of the available HRI 

methods." Commenters stated that EPA further acknowledged that it "does not have sufficient 

site specific information to accurately estimate what percentage of the fleet has adopted various 

HRI methods, nor how effectively, and is not aware of any other investigator having sufficient 

information." Commenters stated that nevertheless, EPA applied all HRI methods as though they 

were all applied on a single EGU to support it conclusion that fleet-wide heat rate improvements 

between 415-1205 Btu/kW (or 4% to 12%) may be achievable. Commenters stated that this 

approach overestimates the heat rate improvement potential that may be achievable on a fleetwide basis.

In summary, commenters stated:

1. Heat rate improvement ranges presented in the 2009 S&L Report do not support the 

conclusion that any individual coal-fired EGU, or any aggregation of coal-fired EGUs, 

can achieve 6% heat rate improvement through implementation of best practices and 

equipment upgrades, as estimated by EPA.

2. Heat rate improvement ranges included in the 2009 S&L Report were estimated at a 

conceptual level, were not based on detailed site-specific analysis, and were based on the 

presumption that the HRI method or technology could be installed on the unit under 

review. Case studies included in the 2009 S&L Report show that it would not be feasible 

to apply all of the HRI methods examined in the study to any individual generating unit 

due to a number of factors, including, but not limited to, plant design, existing operation 

and maintenance practices, and previous equipment upgrades. The report identifies 

potential HRI methods, but provides no basis for calculating an average heat rate 

improvement achievable across the fleet of existing coal-fired units.

3. Case studies included in the 2009 S&L Report support the conclusion that the ability to 

apply each HRI strategy, and the amount of heat rate improvement that can be achieved 

by each strategy, is site-specific and must be evaluated on a case-by-case basis.

Commenters stated that the generic S&L study upon which EPA relies heavily was never 

intended for the type of analysis that EPA now uses to support its building block 1 assumptions. 

Commenters stated that S&L recently submitted a letter to the National Rural Electric 

Cooperative Association to confirm that EPA's conclusions cannot be supported by its 2009 

study. Commenters cited S&L's letter and stated that they agree with S&L's statements and asks 

EPA to reconsider its heavy reliance on the 2009 S&L Report.

Commenters stated that in their experience, S&L is correct -the actual heat rate improvements 

associated with the activities and projects EPA recommends are likely to be highly unit-specific 

and while some units may experience an improvement, others will not. Commenters stated that 

fact is further confirmed by the wide range of efficiency improvements indicated in the report, 

which EPA itself recognized in its analysis and the efficiency improvements are also unlikely to 

be cumulative, as S&L has now confirmed. Commenters stated that in particular, many of the 

efforts EPA has identified seek to accomplish the same goal of maximizing the productive use of 
400

the heat generated by the boiler, such as economizer modifications, improved air heater 

performance, and low temperature heat recovery, however, once one of these projects is 

performed, less excess heat remains available for later projects to recover, reducing the potential 

opportunities for further improvements. Commenters stated that for all of these reasons, the 

actions EPA expects utilities to take in attempting to improve heat rate are not likely to result in 

significant improvements and as a result, EPA's suggestion that the actions will pay for 

themselves in reduced fuel costs is also likely to be false.

Commenters stated that EPA also neglected to evaluate whether coal units in the country have 

already implemented all or most of the activities listed in the S&L report, instead, EPA appears 

to assume that half of the projects have been completed and half of them have not, without 

recognizing that its assumption is likely inaccurate at both the national and state levels. 

Commenters stated that at the national level, EPA's 50 percent assumption does not make senseafter all, if cost-effective measures are available to reduce fuel costs, utilities already have a 

sufficient incentive (and in many cases a legal obligation) to consider and employ them where 

appropriate and prudent. Commenters stated that the study recently conducted by NERC 

confirms this understanding- NERC specifically noted the following with respect to EPA's 

nationwide heat rate improvement assumptions "NERC is concerned that the assumed 

improvements may not be realized across the entire generation fleet since many plant efficiencies 

have already been realized and economic heat rate improvements have been achieved. Multiple 

incentives are in place to operate units at peak efficiency, and periodic turbine overhauls are 

already a best practice. Site-specific engineering analyses would be required to determine any 

remaining opportunities for economic heat rate improvement measures." 

Commenters stated that based on a review of the 2009 Report, as well as a review of EPA's Goal 

Computation Technical Support Document, it appears as though EPA misapplied information 

presented in the 2009 Report when it calculated heat rate improvements of 415 to 1205 Btu/kWh 

and 4 to 12 percent. Commenters stated that it appears that EPA assumed that heat rate 

improvements cited in the 2009 Report were additive and applicable to all coal-fired units, when 

the 2009 Report does not state it would be feasible to implement all of the examined alternatives 

to achieve the sum total of their heat rate improvements. Commenters stated that furthermore, the 

2009 Report does not state any range of overall heat rate improvements that could be expected 

from implementing any combination of the examined alternatives. Commenters stated that heat 

rate improvements described in the 2009 Report case studies were estimated at a conceptual 

level, and were not based on any site-specific detailed analysis and in addition, verification of 

actual heat rate improvements was not made to determine whether any of the modifications were 

implemented and what actual heat rate improvements were realized based on detailed design. 

Commenters stated that furthermore, the case studies showed that it would not be feasible to 

apply all of the examined alternatives from the study to an individual generating unit due to a 

number of factors, including plant design, previous equipment upgrades, and operational 

approaches. 

Commenters stated that EPA proposes to find that overall heat rate improvements of 6 percent 

(or 4 percent under the alternative goals on which EPA solicits comment) for a state's existing 

coal-fired EGUs are achievable by applying a combination of equipment upgrades and "best 

practices." Commenters stated that the Agency relies primarily on a 2009 report by Sargent & 

Lundy comparing various heat rate improvement measures that are generally available, as well as 
401

EPA's own limited analysis of historical data on reported generation and heat rate from existing 

coal-fired EGUs. Commenters stated that specifically, as one component of the target, EPA 

determined that a state's coal-fired EGUs could improve their overall heat rate by 2 percent using 

four "equipment upgrades": (1) economizer replacement; (2) acid dew point control; (3) 

combined variable frequency drives and fan; and (4) turbine overhaul. Commenters stated that 

EPA simply added together the average estimated Btu/kWh improvements for each from the 

2009 Sargent & Lundy report, then divided the result in half to "conservatively" account for the 

fact that "some units may have applied at least some of the upgrades." Commenters stated that as 

the other component of the target, EPA assumed that the remaining heat rate improvement 

measures described by Sargent & Lundy - which the Agency classified as "best practices" - could 

improve unit heat rate by 4 percent by reducing heat rate variability at individual units. 

Commenters stated that EPA did not tie the 4 percent figure to any technical assessment of the 

potential heat rate improvements available from implementing these "best practices," but relied 

solely on a mathematical assessment of how altering heat rate data from individual EGUs would 

alter their average heat rate.

Commenters stated that EPA misinterprets the findings of the Sargent & Lundy (S&L) 2009 

report by wrongly assuming that heat rate improvement projects are additive and that there is 

sufficient "head room" at plants to make significant improvements. Commenters stated that in 

estimating there is opportunity for 4-6% additional heat rate improvement from EGU, EPA 

grossly misunderstands the application of such measures and the state of the industry as to the 

level of efficiency upgrades already made and what additional improvements are technically and 

economically feasible. 

Commenters stated that South Carolina's 6% heat rate improvement goal assumes improvements 

could be realized from older, un-scrubbed coal units that have already been, or are scheduled for, 

retirement in South Carolina. Commenters stated that remaining coal units undergo regular heat 

rate recovery maintenance which allows for heat rate recovery but not necessarily heat rate 

improvement as the maintenance is staged to prevent taking units offline for significant periods 

of time. Commenters stated that with these newer units, heat rate improvements could only be 

achieved if maintenance projects referenced in the Sargent Lundy report were implemented in 

tandem, resulting in units being potentially offline for as long as a year. Commenters stated that 

the EPA should provide further guidance regarding the treatment of heat rate recovery 

improvements. 

Commenters stated that they believe that EPA inappropriately used the 2009 S&L Report to 

assume that the types of improvements estimated by S&L are equally applicable and achievable 

at each and every coal-fired power plant in the country. Commenters stated that notably, S&L 

itself has recently evaluated the Proposed Rule's reliance on (and characterization of the 2009 

S&L Report) and fundamentally rebuked EPA's mischaracterization of its earlier analysis. See 

Sargent & Lundy Letter to National Rural Electric Cooperative Association, dated October 15, 

2014. (See Attachment B). 

Commenters stated that EPA's finding of an additional 2% improvement based on equipment 

modifications is also flawed. In particular, EPA relies heavily upon the Sargent & Lundy study, 

which describes various retrofits that theoretically can improve heat rate, as applied at two case 

studies. Commenters stated that however, the study does not describe any hard data at these 
402

EGUs that suggest that its estimated improvements could he attained at a large portion of the 

existing fleet. Commenters stated that despite this limitation, EPA wrongly attempts to stretch 

the study's conclusions to fit the CPP and that instead, the types of equipment upgrades available 

to a particular EGU are far from uniform. Commenters stated that a given upgrade may produce 

significant heat rate improvements in one facility, but may not produce any improvements in 

another, or may not even be able to be installed at some facilities. 

Commenters stated that for example, the Sargent & Lundy report recommended increasing the 

economizer heat transfer surface, predicted to reduce heat rate by an average of 50-100 Btu/kWh. 

Commenters stated that however, such an implementation is often not feasible for the EGUs that 

have installed Selective Catalytic Reductions Technologies (SCRs), particularly because such 

facilities have specially altered ductwork to facilitate SCR function that compromises the 

effectiveness of economizers and reduces the amount of heat rate improvements that are 

achievable with such an upgrade. Commenters stated that therefore, EPA has inadequately taken 

into account the specific amount of heat rate improvements available to individual facilities 

through equipment upgrades. Commenters stated that its failure to do so has led to a significant 

overstatement of feasible heat rate improvements, requiring recalculation within BSER building 

block 1. 

Commenters stated that generally speaking, the following are areas of a unit where heat rate 

reductions may be possible: boiler island, turbine island, flue gas system, air pollution control 

equipment, and water treatment system. Commenters stated that revisions or upgrades to these 

areas are very costly.

Commenters stated that as a basis for setting the building block 1 level, EPA relies on a 2009 

Sargent & Lundy ("S&L") study for EPA's belief that "implementation of all identified best 

practices and equipment upgrades at each facility could provide a total heat rate improvement in 

the range of approximately 4 to 12 percent." 79 Fed. Reg.at 34859/3(emphasis added). 

Commenters stated that NPPD's review of the study found nothing to indicate that the 

hypothesized heat rate improvements could or should be implemented on a cumulative basis, 

either on an individual source or on a projected industry wide basis and in that regard, Sargent & 

Lundy recently confirmed that it did not view heat rate savings to be cumulative and that "we 

[S&L] believe the EPA misinterpreted the study results." Commenters stated that Raj Gaikwad, 

head of Sargent & Lundy's environmental services, gave a presentation concerning potential heat 

rate savings, which provided that there is "difficulty in generalization," that "every facility is 

different," and that the "same solution cannot be applied." to all generating units. Commenters 

pointed also to Nicholas Institute, Regulating Carbon Dioxide under Section 111(d) of the Clean 

Air Act: Options, Limits and Impacts at 12 (January 2013) (quoting Dr. Gaikwad: "[t]he 

potential for improvements in heat rate is source-specific because that potential depends upon 

factors that differ from unit to unit; combustion type, fuel type, elevation, maintenance and 

retrofit history, and air control technology, to name a few."); Id. at 13 ("Bilirgen and Gaikwad 

emphasized the difficulty in generalizing the potential for heat rate improvements in units across 

the nation absent calculations on a granular, unit-by-unit level."). Commenters stated that the 

2009 Sargent & Lundy study used estimated capital and installation costs as of 2008, subject to a 

caution "that the costs presented herein are not indicative of those that may be expected for a 

specific facility due to variables such as equipment, material, and labor market conditions and 
403

site specifications." Sargent & Lundy, Coal-Fired Power Plant Heat Rate Reductions at 1-3 (Jan. 

22, 2009).

Commenters stated that as heat rate improvement projects can be very costly, reliance on 2008 

cost estimates for non-specific plants does not comport with Section 111(a)(1)'s requirement that 

the current costs of achieving emission limitations must be taken into account. Commenters 

stated that the EPA's apparent misunderstanding or confusion concerning the inadequacy of the 

Sargent & Lundy report to serve as a basis to project industry-wide costs and heat rate 

improvements underscores that the EPA has not shown that its building block 1 is achievable, 

cost effective or adequately demonstrated as required by Section 111(d).

Commenters stated that EPA's Technical Support Document ("TSD"), GHG Abatement 

Measures (June 10, 2014), purports to provide evidence that its proposed heat rate improvement 

BSER is sound and reasoned. GHG Abatement Measures TSD at 2-5. Commenters stated that 

EPA says in the TSD it reviewed a number of studies involving literature reviews and technical 

papers identifying potential efficiency improvement techniques for existing coal-fired EGUs, 

however, EPA admits they all can be traced back to a single source: "Typically, these studies 

share as a common basis the estimated potential efficiency improvement percentages and costs 

from the engineering study originally completed by Sargent and Lundy in 2009 titled 'Coal-Fired 

Power Plant Heat Rate Reductions.'" Id. at 2-6. Commenters stated that thus, for all practical 

purposes, the only support EPA has for building block 1 is the 2009 S&L Study. Commenters 

stated that indeed, the TSD acknowledges the same point: "The EPA also reviewed the 

engineering studies available in the literature and selected the Sargent & Lundy 2009 study as 

the basis for their assessment of heat rate improvement potentials from equipment and system 

upgrades." GHG Abatement Measures TSD at 2-33 (emphasis added). Commenters stated that 

sole reliance on the 2009 S&L study leaves open the question: does the study actually support 

and provide substantial evidence for EPA's building block 1's heat rate improvement targets? 

Commenters stated that the answer is "No." Commenters stated that Sargent & Lundy reviewed 

EPA's use of the 2009 study, and stated these concerns:

1. EPA misapplied the heat rate improvement ("HRI") estimates;

2. EPA failed to consider equipment degradation and load profile when it applied the HRI 

data, thus overestimating the HRI potential on a fleet-wide basis;

3. EPA misapplied the cost data provided;

4. EPA's methodology to evaluate the economic impact of the HRI methods overlooked the 

wide range of real differences in both HRI potential and HRI cost, resulting in an 

inaccurate representation of the cost-effectiveness of the HRI methods.

Commenters stated that S&L 2014 analysis at 3. S&L concludes that the heat rate improvement 

ranges presented in the 2009 S&L Report do not support the conclusion that any individual coalfired EGU, or any aggregation of coalfired EGUs, can achieve 6% heat rate improvement 

through implementation of best practices and equipment upgrades, as estimated by EPA.

Commenters stated that S&L 2014 analysis at 12 reveals that clearly, EPA's faulty reliance on 

the S&L study does not provide a credible basis to establish that building block 1 has been 
404

"adequately demonstrated" as required by Section 111(a)(1) and for this reason alone, EPA 

should withdraw its proposed building block 1. 

Commenters stated that to determine that additional 2% HRI could be achieved by all individual 

coal-fired EGUs, EPA relied on the Sargent & Lundy study. Commenters stated that this study 

was based on a literature study, data provided by original equipment manufacturers, and the inhouse database of Sargent & Lundy. Commenters stated that in reality, the report estimates HRI 

ranges at a conceptual level only and were not based on detailed site-specific analysis. 

Commenters stated that conversely, several cases in the study actually demonstrate that it is not 

feasible to apply all of the HRI alternatives to every individual EGU; therefore, making the 

projected HRI improbable or even impossible. Commenters stated that the cited case studies 

demonstrated that HRI alternatives were not available for every individual EGU because 1) 

individual generating units vary in plant design, previous equipment upgrades and operational 

approaches; 2) individual HRI technologies and strategies do not always combine in ways that 

equal the sum of the parts because many technologies are dependent on interrelated variables of 

plant operation; and 3) HRI depends on EGU load levels because a facility's average heat rate is 

lower when it is base-loaded than when it is load-cycled. 

Commenters stated that while they do not own coal generation, part of their purchased power 

electric generation mix is generated from coal. Commenters, therefore, were concerned that the 

application of a six percent HRI could affect reliability in its service area. Commenters stated 

that as a basis for Building Block 1, EPA relies on a 2009 study by the engineering firm Sargent 

& Lundy (S&L) and states: "[b]ased on this [Sargent & Lundy] study, the EPA believes that 

implementation of all identified best practices and equipment upgrades at each facility could 

provide a total HIR in the range of approximately four to twelve percent." Commenters stated 

that however, nothing in this study indicates that the hypothesized HRI discussed therein should 

be used on a cumulative basis, as EPA assumes. Commenters stated that in that regard, S&L has 

recently sent a letter to the NRECA confirming that they did not did not view the heat rate 

savings to be cumulative and that EPA misinterpreted their Study insofar that "EPA assumed that 

HRI cited in their 2009 Report were additive and applicable to all coal-fired units." Commenters 

stated that in this letter S&L states further that HRI must be determined on a case-by-case basis 

due to the fact that the ability to achieve HRI depends upon the unit type, fuel type and many 

other site-specific conditions. Commenters stated that for example, they point out that for plants 

operating at lower loads the benefit of an HRI is reduced and the letter also states that the 

application of multiple strategies may not be economically justified.

Commenters stated that the Nicholas Institute workshop report published in January of 2013 

quotes the head of environmental services for S&L, as saying "the potential for improvements in 

heat rate is source specific because that potential depends upon factors that differ from unit to 

unit; combustion type, fuel type, elevation, maintenance and retrofit history, and air controlled 

technology, to name a few." Commenters stated that this report also states that he further 

emphasized "the difficulty in generalizing the potential for HRI in units across the nation absent 

calculations on a granular, unit by unit level." Commenters stated that the EPA's apparent 

misunderstanding or confusion concerning the S&L report underscores the fact that the EPA has 

not shown that Building Block 1 is achievable, cost effective or "adequately demonstrated" as 

required by Section 111(d).
405

Commenters stated that for these reasons, and since it is recognized that each EGU is unique 

with regard to the level of HRI, EPA should withdraw the HRI requirements for Building Block 

1. Any change to EPA's approach to Building Block 1 must be re-proposed for public comment. 

Commenters stated that on November 24th, Sargent & Lundy provided comment that criticized 

USEPA's interpretation of the 2009 study. Commenters quoted S&L stating in their comments, 

"The report was not intended to serve as the basis for determining the heat rate improvement 

potential at any individual unit, an average potential fleet-wide heat rate improvement, nor for 

determining the average fleet-wide costs of implementing the HRI methods." Commenters stated 

that therefore the USEPA misapplied the S&L study in determining the heat rate improvements 

according to the S&L comments from November 24, 2014. 

Commenters stated that Building block #1 incorrectly assumes that upgrade and operational 

improvements are widely available and that implementation of BB 2, 3 & 4 will not lower 

efficiency. Commenters stated that competitive markets such as MISO have already forced coalfired generators such as CWLP to adopt state-of-the-art technologies available and enhance 

operations and maintenance to improve thermal efficiencies in order to compete effectively. 

Commenters stated that indeed, as noted above, CWLP had an Energy Assessment performed in 

2007 to assess how to achieve heat rate improvements to Dallman units 31, 32 and 33. 

Commenters stated that while yet another energy assessment of their four (4) Dallman units may 

identify a fractional percentage improvement capability, achieving 6% heat rate improvement is 

unrealistic. Commenters stated that in fact, based on EPA's expectation that coal plants will, by 

2020, operate in the dispatch queue after CCNG plants, a more rational assessment is that coal 

plant operational efficiency will decrease as plants designed to operate most efficiently at high 

capacity factors are instead relegated to an inefficient role of load following.

Commenters stated that while the USEPA apparently relied upon a Sargent & Lundy (S&L) 

study in developing the 6% improvement rate, the USEPA's interpretation of the study 

apparently failed to consider the realities of the energy markets, which enable for-profit utilities 

to profit by achieving maximum efficiencies. Commenters stated that testimony of industry 

representatives from NRG Energy and Dynegy, whose fleets represent 76.3% of coal capacity in 

Illinois at the ICC's policy session addressing building blocks #1 (and #2) affirm that 6% heat 

rate improvement is unrealistic and unachievable. See, 

http://www.icc.illinois.gov/publicutility/Environmental_Regulation.aspx. Commenters stated 

that the USEPA's GHG Rule therefore fails to recognize how security constrained economic 

dispatch works in organized wholesale markets. Commenters stated that Section 111(d) should 

not be used by the USEPA to disrupt existing wholesale markets that protect the grid and provide 

energy security to this country. Commenters stated that while the USEPA's regulatory authority 

is broad, "it must be exercised with caution and is not entitled to boundless discretion." See, 

Utility Air Regulatory Group v. EPA, 573 U.S. (2014).

Commenters stated that on November 24th, Sargent & Lundy provided comment that criticized 

USEPA's interpretation of the 2009 study. Commenters stated that S&L stated in their 

comments, "The report was not intended to serve as the basis for determining the heat rate 

improvement potential at any individual unit, an average potential fleet-wide heat rate 

improvement, nor for determining the average fleet-wide costs of implementing the HRI 

methods." Commenters stated that therefore the USEPA misapplied the S&L study in 
406

determining the heat rate improvements according to the S&L comments from November 24, 

2014. 

Commenters provided the following comments in regards to their 2009 report on heat rate 

improvement: "The purpose of the 2009 S&L Report was to identify potential HRI opportunities 

at existing coal-fired EGUs, provide estimates of the potential heat rate reductions that may be 

achieved if such methods were implemented on an individual unit, and provide order-ofmagnitude costs to implement the changes. Commenters stated the report was not intended to 

serve as the basis for determining the heat rate improvement potential at any individual unit, an 

average potential fleet-wide heat rate improvement, nor for determining the average fleet-wide 

costs of implementing the HRI methods. Commenters stated that heat rate and cost data provided 

in the 2009 S&L Report, if applied properly, supports the conclusion that a detailed site-specific 

analysis is required to identify potential HRI opportunities, and to assess the performance, costs, 

and cost-effectiveness of the available HRI methods." 

Commenters stated that the Sargent & Lundy Study does not show that a 6% heat rate 

improvement is adequately demonstrated. Commenters stated that EPA's assertions that a 6% 

heat rate improvement and emission rate reduction is adequately demonstrated for coal-fired 

power plants is based primarily on a study conducted in 2009 by the consulting firm Sargent & 

Lundy, LLC. Commenters stated that EPA's reliance on this study is flawed for several reasons. 

Commenters stated that first and most obviously, the Sargent & Lundy Study was completed in 

2009, three years before the 2012 baseline year on which EPA has based state goals, thus, in all 

likelihood, the improvements cited in the study- to the extent they are feasible or cost-effective at 

all - are likely to have been implemented already by many power plants. Commenters stated that 

in other words, many (if not most) of these improvements are likely already reflected in the 2012 

baseline, which means that few additional reductions below 2012 levels will be achievable in 

practice. Commenters stated that second, as Sargent & Lundy explained in a recent letter to the 

Natural Rural Electric Cooperative Association (NRECA):

"Combinations of strategies to achieve heat rate improvements do not always provide heat rate 

improvement reductions equal to the sum of each individual strategy's heat rate improvement 

because many of the technologies affect, or are dependent upon, plant operating variables that 

are inter-related. Therefore, case-by-case analyses should be conducted to determine whether the 

incremental heat rate improvement through the application of multiple strategies is economically 

justified."

Commenters stated that in addition, Sargent & Lundy's letter explains that "[t]he performance of 

some of the evaluated heat rate improvement strategies degrades over time, even with best 

maintenance practices," meaning that "unit heat rate initially obtained may increase over time." 

Commenters stated that such an increase would erode the initial emission reduction potential of 

the measures discussed in the Sargent & Lundy Study, leading to much lower emission 

reductions than EPA has assumed. Commenters stated that furthermore, Sargent & Lundy 

conclude that the addition of greater amounts of NGCC and zero-carbon generation could cause 

many coal-fired power plants to shift to a "load-cycling operating profile," which would cause 

those units' heat rates to increase and potentially negate all of the heat rate improvements 

discussed in the study.
407

Commenters stated that S&L's engineering evaluation included a review of potential heat rate 

improvements for each of the four units at SGS, taking into account improvement projects 

undertaken to date as well as unit-specific design, operation and control characteristics. 

Commenters stated that using the EPA's categorization of "best practice" versus "equipment 

upgrades", the following table summarizes the results of S&L's case study for SGS. Commenters 

stated that the table also compares S&L's case study results with the EPA's assessment. 

Commenters provided a data table entitled "Table 4: Available Heat Rate Improvements for 

Springerville Generating Station" showing the Heat Rate Improvement Potential for Unit 1, Unit 

2, Unit 3, and Unit 4.

Commenters stated that as shown, EPA's analysis grossly inflates the potential for heat rate 

improvements at SGS. Commenters stated that one of the reasons for this discrepancy is the 

flawed assumption in the EPA's bin model that the variation of heat input in each bin was vastly 

caused by lack of the best practice; other factors can cause variation of heat input values. 

Commenters stated that in the preamble to the proposed rule, EPA stated that it "believes that 

implementation of all identified best practices and equipment improvements at a facility could 

provide total heat rate improvements in a range of approximately 4 to 12 percent." (79 FR 

34859). Commenters stated that based on information provided in the 2009 Report, "EPA 

estimated that for a range of heat rate improvements from 415 to 1205 BTUs per kWh, 

corresponding to percentage heat rate improvements of 4 to 12 percent for a typical coal-fired 

EGU, the required capital costs would range from $40 to $150 per kW." (79 FR 34861) 

Commenters stated that however, based on a review of the 2009 Report, as well as a review of 

EPA's Goal Computation Technical Support Document, it is apparent that EPA misapplied 

information presented in the 2009 Report when it calculated heat rate improvements of 415 to 

1205 Btu/kWh and 4 to 12 percent.

Commenters stated that it appears that EPA assumed that heat rate improvements cited in the 

2009 Report were additive and applicable to all coal-fired units, when the 2009 Report makes it 

clear that it would not be feasible to implement all of the examined alternatives to achieve the 

sum total of their heat rate improvements. Commenters stated that furthermore, the 2009 Report 

does not state any range of overall heat rate improvements that could be expected from 

implementing any combination of the examined alternatives. Commenters stated that in fact, the 

case studies provided in the report estimated potential heat rate improvements of 4% and 1.2% 

for the 250 MW and 850 MW units, respectively. Commenters stated that contrary to the 

approach used by EPA, heat rate improvement opportunities, and the associated costs, must be 

evaluated on a case-by-case basis taking into consideration unit-specific design, operations, and 

controls.

Commenters stated that the purpose of this engineering study is to review the potential heat rate 

improvement strategies identified in S&L's 2009 report and assess their feasibility to improve 

heat rate for Tucson Electric Power's (TEP) Springerville Generating Station (SGS) Units 1, 2, 3, 

& 4.

Commenters stated that in both the 2009 Report and the EPA's proposed regulation for 

greenhouse gas (GHG) emissions for existing stationary sources, the areas of a power plant 

where efficiency improvement and heat rate reduction may be possible are the Boiler Island, 
408

Turbine Island, Flue Gas System, Air Pollution Control Equipment, and Water Treatment 

System.

Commenters stated that this study identifies systems and equipment at SGS Units 1 through 4 

where net plant heat rate improvement may be realized. Commenters stated that further, this 

study provides estimates of the change to the net plant heat rate as well as the corresponding 

order-of-magnitude costs for implementation, where applicable. Commenters stated that this 

study also identifies potential heat rate penalties due to future emission controls. Commenters 

stated that additionally, S&L reviewed changes made to equipment or systems in the past and 

evaluated impacts to net plant heat rate. Commenters stated that to conduct this evaluation, S&L 

reviewed equipment data manuals, system description manuals, plant data, test reports, and 

additional information obtained from TEP for the SGS units. 

Commenters stated that in the preamble to the proposed rule, EPA stated that it "believes that 

implementation of all identified best practices and equipment upgrades at a facility could provide 

total heat rate improvements in a range of approximately 4 to 12 percent." (79 FR 34859). 

Commenters stated that based on information provided in the 2009 Report, "EPA estimated that 

for a range of heat rate improvements from 415 to 1205 Btus per kWh, corresponding to 

percentage heat rate improvements of 4 to 12 percent for a typical coal-fired EGU, the required 

capital costs would range from $40 to $150 per kW." (79 FR 34861) Commenters stated that 

however, based on a review of the 2009 Report, as well as a review of EPA's Goal Computation 

Technical Support Document, it appears as though EPA misapplied information presented in the 

2009 Report when it calculated heat rate improvements of 415 to 1205 Btu/kWh and 4 to 12 

percent.

Commenters stated that it appears that EPA assumed that heat rate improvements cited in the 

2009 Report were additive and applicable to all coal-fired units, when the 2009 Report does not 

state it would be feasible to implement all of the examined alternatives to achieve the sum total 

of their heat rate improvements. Commenters stated that furthermore, the 2009 Report does not 

state any range of overall heat rate improvements that could be expected from implementing any 

combination of the examined alternatives.

Commenters stated that heat rate improvements described in the 2009 Report case studies were 

estimated at a conceptual level, and were not based on any site-specific detailed analysis. 

Commenters stated that in addition, verification of actual heat rate improvements was not made 

to determine whether any of the modifications were implemented and what actual heat rate 

improvements were realized based on detailed design. Commenters stated that furthermore, the 

case studies showed that it would not be feasible to apply all of the examined alternatives from 

the study to an individual generating unit due to a number of factors, including plant design, 

previous equipment upgrades, and operational approaches.

Commenters stated that Sargent & Lundy LLC's 2009 Report does not support EPA's claim that 

a 6 percent heat rate improvement is achievable on all existing coal-fired units. Commenters 

stated that according to Raj Gaikwad, Ph.D, Vice President, Advanced Fossil Fuel Technologies, 

Sargent & Lundy, "the Report does not conclude that any individual coal-fired EGU or any 

aggregation of coal-fired EGUs can achieve 6% HRI". Commenters stated that Dr. Gaikwad goes 

on to state that, "Based on the case studies performed by S&L, it appears that most of the utilities 
409

are employing best operational and maintenance practices and in light of this observation, it 

appears that significant further reduction in heat rate, such as that assumed by the EPA, may not

be feasible."

Commenters stated that the inferences drawn by EPA from the 2009 Sargent & Lundy study 

regarding aggregate heat rate improvement are inappropriate, for at least two reasons. 

Commenters stated that first, the numbers presented in the study did not reflect any analysis of 

improvements actually achieved or determined to be achievable at any particular EGU:

"Heat rate improvements described in the 2009 Report case studies were estimated at a 

conceptual level, and were not based on any site-specific detailed analysis. In addition, 

verification of actual heat rate improvements was not made to determine whether any of the 

modifications were implemented and what actual heat rate improvements were realized based on 

detailed design. Unit Heat Rate Improvement Study at Coronado Generating Station (SL012487), November 13, 2014. Sargent & Lundy."

Commenters stated that second, EPA initially assumes that the heat rate improvements which 

may be achievable at a hypothetical EGU at which those improvements have not already been 

made are informative as to the achievable improvements in heat rate for the fleet of twelve coalfired EGU's in Arizona. Commenters stated that EPA recognizes and acknowledges that this 

assumption has no basis "because the EPA expects that a significant fraction of the coal fleet has 

already applied some or many of the available [heat rate improvement] methods." (See, docket 

item EPA-HQ-OAR-2013-0602-17180, "GHG Abatement Measures," at p. 2-36.) 

Commenters stated that pursuant to 42 U.S.C. 7414(a), EPA has broad authority to gather 

information for the purpose of carrying out its responsibilities under the Clean Air Act, and 

frequently exercises that authority for purposes of collecting information from entities potentially 

subject to a new regulation. (See, for example, "Supporting Statement for EPA Information 

Collection Request No. 2411.01," March 23, 2011, available at 

http://www.reginfo.gov/public/do/DownloadDocument?documentID=227374&version=2

providing EPA's estimated cost burden of 66,000 hours and $29 million to be imposed on 

regulated entities for responding to the information request and citing as justification EPA's 

conclusion "that obtaining updated information will be crucial to informing its decisions for 

petroleum refineries.") Commenters stated that however, recognizing that exercising this 

information - gathering authority in this instance would be inconvenient and might interfere with 

its agenda - driven timeline for establishing emissions guidelines, EPA simply throws up its 

hands regarding the lack of pertinent, readily available data: 

The EPA has found no comprehensive data set on the extent to which specific [heat rate 

improvement] methods have already been applied at individual EGUs. The EPA believes that 

many EGU owners consider such information to be confidential. (See, docket item EPA-HQOAR-2013-0602-17180, "GHG Abatement Measures," at p. 2-36.) 

Commenters stated that reflecting an apparent assumption that it is not necessary to gather and 

analyze the data which would allow an assessment of the achievable heat rate improvements at

the specific EGU's which would be subject to the standards of performance which EPA is 

proposing should be established, EPA proceeds to establish emission guidelines for Arizona and 
410

other states, believing that this fatal flaw can fixed by cutting in half the entirely unrepresentative 

estimate it generated based on inadequate, generic data:

[W]e recognize that this total may overstate the average equipment upgrade opportunity across 

all EGUs because some EGUs may have already implemented some of these upgrades. 

Commenters stated that they therefore, propose to use as a data input for purposes of developing 

state goals an estimate that, on average across the fleet of affected EGUs, only half of the full 

equipment upgrade opportunity just described remains-i.e., that for the fleet of affected EGUs as 

a whole, the technical potential for heat rate improvements from equipment upgrades 

incremental to the best-practices opportunity is on average two percent rather than four percent. 

79 Fed. Reg. at p. 34,860.

Comment 47: Comments addressing equipment degradation 

Response 47: For the EPA’s response to these comments, see section V.C of the final rule 

preamble of the CPP and Chapter 2 of the GHG Mitigation Measures TSD supporting the final 

CPP. As stated there, we acknowledge that some heat rate improvement measures—like most 

power plant components—require maintenance in order to sustain their efficacy over time. 

Accordingly, EGU owners and operators will need to diligently apply best practices in order to 

mitigate this degradation, and may need to more frequently replace components. 

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

Commenters stated that even if it is assumed that it is possible to achieve a measurable heat rate 

reduction immediately after implementing various HRI strategies outlined in this report, it will 

be much more difficult to sustain that percentage improvement over a long term timeframe, 

because each piece of major equipment degrades with continued operation and this normal 

degradation in performance increases plant heat rate. Commenters stated that to account for this 

degradation in performance/efficiency improvement, units would need to design for a higher heat 

rate reduction that will average out to be consistent with the state's requirements and therefore, it 

is critical to account for normal degradation when developing a long range plan. 

Commenters stated that some HRI technologies are more susceptible to degradation over time, 

and some technologies will not significantly degrade over time. Commenters stated that with 

most HRI methods, upon completion of the maintenance activities, the unit will show 

improvement in heat rate initially and will degrade between maintenance outages; the average of 

these two values may be considered to be the sustainable heat rate improvement. Commenters 

stated that completing these maintenance activities on a consistent basis is required in achieving 

the average sustainable heat rate improvement. Commenters stated that other BP options like 

implementing VFDs on ID and FD fans are not expected to degrade significantly over time; 

therefore, the immediate heat rate reduction is often very close to the sustainable heat rate 

improvement. 

Commenters stated that many other HRI methods, such as turbine upgrade (not to be confused 

with overhaul maintenance), may provide a significant reduction in heat rate immediately after 
411

implementation, but are more susceptible to degradation because, over time, pieces warp and 

erode, providing less and less heat rate reduction. Commenters stated that a rigorous 

maintenance schedule including a major overhaul (replace packing and seals) every 7-10 years 

will help maintain sustainable turbine efficiency, however, it will never be able to achieve the 

same efficiency as when it was initially installed. Commenters stated that over the course of 

multiple years, the equipment will provide less and less annual heat rate improvement and 

therefore, performance degradation should be accounted for when considering certain HRI 

technologies, such as turbine upgrades or air heater seal replacements, as part of a long-term 

sustainable heat rate improvement strategy. Commenters stated that while OEMs may provide an 

initial guarantee for equipment improvements, the future performance must be considered when 

determining the sustainable heat rate reduction over the lifetime of the equipment. 

Commenters stated that performance degradation is complex and the amount of degradation over 

time will affect the degree of heat rate improvement sustained over that period. Commenters 

stated that an important factor in any heat rate improvement that is implemented is the ability of 

the plant to sustain those improvements over time with practices and technology that aid the 

owner/operator to minimize degradation.

Commenters stated that EPA erroneously assumes that the initial payoff from any heat rate 

improvement project remains constant over time. Commenters stated that in reality, the 

improvement in heat rate resulting from any particular measure typically degrades over time, 

meaning that the long-term payoffs of these measures are significantly smaller than the 

immediate reduction observed after implementation. Commenters stated that upgraded 

components begin to incur wear as soon as they return to operation and will need to be replaced 

or refurbished themselves eventually in order to maintain the improved heat rate. Commenters 

stated that for example, while a steam turbine upgrade may improve a unit's heat rate below its 

design level, gradual degradation of the turbine blades will reduce the magnitude of that 

improvement over time from the "new" state without periodic overhauls. Commenters stated that 

any standard of performance that is based on efficiency improvements at affected EGUs must 

account for this degradation and cannot simply reflect the immediate, short-term payoffs from 

efficiency improvements.

Commenters stated that there are problems with EPA's methodology for calculating heat rate 

improvements from equipment upgrades that IUG believes need to rectified in the proposed rule. 

Commenters stated that EPA's 2 percent target for gains from equipment upgrades does not 

assume degradation, which results in year-over-year reductions in efficiency. Commenters stated 

that as soon as new equipment is installed, its ability to improve the operational performance of 

the unit starts to decline, yet, EPA assumes improvements from equipment upgrades will remain 

constant into perpetuity. Commenters stated that if an EGU owner wanted to address the 

degradation in equipment, additional costs, above those assumed by EPA in the proposed rule, 

would be incurred by the owner to attempt to maintain heat rate improvements. Commenters 

stated that EPA assumes the gains from equipment upgrades are additive, when some of the 

recommended retrofits obviate other possible improvements (e.g. installing a new turbine vs. 

retrofitting the seals on an older turbine). 

Commenters stated that heat rates at coal-fired EGUs gradually increase over time due to natural 

degradation and that this degradation cannot be offset by routine maintenance, as EPA asserts. 
412

Commenters stated that average heat rate of coal-fired EGUs in the United States increased by 

1.7 percent from 2002 to 2012, despite the performance of routine maintenance. Commenters 

stated that deterioration of steam turbine blades due to deposition, erosion, and corrosion, along 

with buildup of blade deposits, are significant factors in loss of efficiency at coal-fired EGUs. 

Commenters stated that these issues can result in an efficiency reduction of up to 15 percent of 

generating capacity and although improvements in turbine design and coating have made 

turbines more durable, it is unreasonable to assume that there will be no deterioration in coalfired EGU turbines over the 10-year performance period.

Commenters stated that they have found that heat rate improvement are not permanent and can 

deteriorate over time with operation and aging of the unit. Commenters stated that lower capacity 

factors or increased cycling increase heat rates and increase heat rate variability. Commenters 

stated that the demands on the units caused by dispatch changes to support additional renewable 

energy, for example, deteriorate the heat rate even further. Commenters stated that in the 

integrated electric system, units are dispatched to respond to load. Commenters stated that unit 

owners and operators, therefore, cannot control capacity factor to address concerns about heat 

rate. Commenters stated that they do not expect that a 6 percent remaining coal fleet HRI is 

reasonably achievable. 

Commenters stated that the heat rate at coal-fired generating units gradually increases over time 

due to natural degradation of key steam and generation components. Commenters stated that 

EPA assumes in its Proposed Rule that routine maintenance will offset natural degradation. 

Commenters stated this assumption is unsubstantiated and that the heat rate of coal-fired power 

plants naturally deteriorates over time and is not fully offset by routine maintenance and cannot 

be addressed economically with new equipment. Commenters stated that for example, the 

average heat rate of coal units in the U.S. increased by two percent from 2002 to 2012 despite the 

coal power plants performing routine maintenance. Commenters stated that deterioration of 

steam turbine blades due to deposition, erosion and corrosion is a significant factor in steam coal 

power plant's' loss of efficiency, amounting to a reduction of fifteen percent of generating 

capacity in some cases. Commenters stated though improvements in turbine design and coating 

have made turbines more durable, it is unreasonable to assume that there will be no deterioration 

in the turbines of steam coal plants over the ten year performance period. Commenters stated that 

accordingly, the heat rate improvement that EPA assumes existing coal power plants can achieve 

cannot be sustained due to natural degradation despite routine maintenance. 

Commenters stated that EPA attempts to support the achievability of Building Block 1 by relying 

on its analysis of heat rate improvement projects at 16 individual EGUs (GHG Abatement 

Measures TSD at p. 2-32; see also "GHG Abatement Measures Units with Heat Rate Changes," 

Doc. No. EPA-HQ-OAR-2013-0602-0236) Commenters stated that one of those 16 units 

analyzed by EPA is Dynegy's Newton Unit 1, and EPA's reliance on Newton 1 to support the 

achievability of Building Block 1 is seriously misplaced. Commenters stated that Newton Unit 1 

implemented three heat rate improving actions in the 11-year period prior to 2012: (1) replacing 

the steam turbine HP-IP sections in 2006; (2) removal of deposits in the condenser in 2009, and 

(3) feedwater heater optimization in 2009. Commenters stated that Newton CEMS data suggests 

gross heat rate decreases from 2002 through 2006, but returns to 2004 heat rate levels in 2007. 

While Newton 1 achieved a net heat rate reduction of more than 4-5% over a several year period 

from 2005 through 2011, net heat rate increased in three of the four years from 2009 through 
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2012 - when two heat rate actions were implemented. Commenters stated that this suggests that 

heat rate improvement actions are subject to degradation and can be negated by changes in 

operating condition. 

Commenters stated that EPA admits that the heat rate at many units slowly degrades over time, 

regardless of the measures employed: "Over 40% of units have a positive slope [to the annual 

heat rate trend line]. Commenters stated that this would imply that equipment maintenance and 

upgrades at a significant fraction of the study population have not been sufficient even to 

maintain the status quo " and as Cichanowicz and Hein found, "[t]he thermal efficiency of 

generating power from fossil fuel plants degrades with time, both due to component wear and 

changes in plant operation. Component wear is inevitable." Commenters stated that EPA, 

however, fails to take into account this natural degradation in heat rate, and instead assumes that 

"other factors are held equal." 

Commenters stated that most all equipment in the steam cycle of coal-fired EGU's degrades in 

performance from operation over time and that adopting operating and maintenance best 

practices can delay but not arrest the natural deterioration that occurs in steam turbines, air 

heaters, air heater baskets, condensers, pumps, valve seals, and cooling tower fill. Commenters 

stated that as this equipment operates tolerances open up, air and steam leaks occur, and heat 

transfer surfaces are fouled, and efficiency decreases as back pressure increases and that is why 

there may be opportunity to obtain HRIs from some existing sources. Commenters stated that 

while some areas of a plant can be restored with routine maintenance and cleaning, BSER 

requires reductions that are continuous and permanent and by their very nature, HRIs can neither 

be continuous, nor permanent as constantly changing operating conditions will impact heat rate 

and influence the measurable benefits of HRIs.

Commenters stated that EPA ignores that the heat rate improvements degrade over time, and 

subsequent efforts to regain that lost improvement do not always achieve the same level of 

improvement as the previous effort. Commenters stated that for example, a common technique to 

improve heat rate is the turbine overhaul. Commenters stated that over time, the benefits of the 

turbine overhaul erodes until the next turbine overhaul and there is no guarantee that the next 

overhaul will achieve the same degree of improvement as the previous overhaul. Commenters 

stated that this puts the generators in a precarious compliance situation because they cannot be 

assured they would comply with the heat rate improvement requirements continuously over the 

lifetime of the unit.

Commenters stated that EPA's assumption that any heat rate improvement is sustainable is 

flawed because many heat rate improvement projects experience natural degradation soon after 

installation. Commenters stated that simply replacing or improving a piece of equipment is not a 

panacea and, although one piece of equipment may be repaired or replaced so as to recover the 

lost heat rate associated with that equipment or even improve heat rate, another piece of 

equipment on the unit may fail or degrade in a manner such that no heat rate benefits are 

observed at a unit. 

Commenters stated that EPA has not considered that the projects cited in the Sargent & Lundy 

study do not account for the fact that equipment wears over time resulting in degraded efficiency 

improvements. Commenters stated that any estimate of a heat rate improvement is only for a 
414

given point in time, and the effectiveness of the equipment upgrades tends to degrade over time 

as the equipment wears. Commenters stated that many of the efficiency improvement projects in 

the Sargent & Lundy study result in diminishing efficiencies; for example, the best year may not 

be representative of the entire unit's outage cycle and the unit may operate most efficiently the 

year after the outage and degrade until the next outage. 

Commenters stated that NRECA member experience demonstrates that the emission reductions 

obtainable from heat-rate improvement projects tend to be temporary, and that emissions per 

megawatt-hour tend to rise as time passes following completion of such a project, even with 

continued maintenance of the unit. Commenters further stated that performance of some of the 

evaluated heat rate improvement strategies degrade over time, even with best maintenance 

practices and therefore, depending on the strategy employed or the technology installed to reduce 

heat rate at an existing coal-fired EGU, the unit heat rate initially obtained may increase over 

time.

Commenters stated that EPA does not account for heat rate improvement degradation over time 

and that upgraded equipment starts to degrade as soon as it is placed into service and the 

emission improvements will therefore be dynamic by decreasing in time through the compliance 

period. 

Commenters stated that heat rate improvements are not a permanent change to the performance 

of the source and that all combustion equipment degrades in performance over time simply due 

to the nature of combustion. Commenters stated that is why there may be opportunity to obtain 

reductions from some of the existing sources. Commenters stated that BSER requires that the 

reductions be permanent, continuous, and quantifiable; however the requirement is unrealistic as 

performance degrades over time. Commenters stated that BSER would require compensation for 

the reductions through additional means but at an unpredictable rate or time. 

Commenters stated that the impact of heat rate projects degrades over time, even with best 

maintenance practices employed and pulverized coal mill grinding zones, burners, boiler surface 

cleanliness, air heater performance, turbine valves, diaphragms, turbine packing and blading all 

degrade with normal use. Commenters stated that normally scheduled maintenance outages 

return equipment back to manufacturers design and efficiency expectations and simply put, a 

coal-fired utility cannot hold an average of six percent heat rate improvement by means of CO2 

emissions computation.

Commenters stated that even if the assumed 6% heat rate improvement is capable of being 

achieved, there is no consideration of degradation in unit performance over time. Commenters 

stated that it is normal to experience some degree of performance degradation with coal-fired 

units after improvements have been made and if this were not the case there would be no need 

for unit modifications to improve the unit's performance over time. Commenters stated that any 

heat rate improvements that may be achievable for the coal-fired plants will be offset or modified 

by changes in dispatch that impacts those units. Commenters stated that this essentially creates a 

re-occurring cycle of improvements and degradation that the EPA has not factored into the rule 

but is a reality for coal-fired units.
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Commenters stated that while equipment upgrades can result in plant-level efficiency 

improvements, there is a degradation factor, making it difficult to maintain efficiency levels over 

time. 

Commenters stated that EPA ignores the fact that heat rate degrades over time. 

Commenters stated that the CPP did not take into consideration that heat rate improvement 

projects are not permanent and plant performance deteriorates immediately following the 

completion of the improvement project.

Commenters stated that regardless, even assuming for the sake of argument that AESPR could 

somehow make the large investments, that PREPA would accept those investments, and that the 

ratepayers would pay for the extra costs resulting from those investments, it still would be 

unreasonable to assume a flat heat rate improvement would be achieved at AESPR, and they

urge EPA to reconsider that false assumption. Commenters stated that all components at a power 

plant are going to degrade over time - with power plant heat rate degrading along with it. Even 

when heat rate sees some improvement, such as after a turbine overhaul, from the moment the 

new equipment is put in place, the improvement will begin to degrade. Commenters stated that 

therefore, to set a flat heat rate improvement goal based on maximum heat rate improvements is 

simply physically impossible to achieve or maintain. Commenters stated that for example, at 

AESPR, the independent engineers who evaluated the plant design for the lenders who financed 

the plant expected that the plant heat rate would degrade more than 0.3% each year - with only a 

portion of that (80%) expected to be recaptured during each major maintenance outage (every 7 

years). 

Commenters stated that some maintenance measures, such as reducing corrosion and fouling of 

heat transfer surfaces, are performed on a cyclical basis - meaning that between routine 

maintenance cycles heat rate degrades. 

Commenters stated that combinations of strategies to achieve heat rate improvements do not 

always provide heat rate improvement reductions equal to the sum of each individual strategy's 

heat rate improvement because many of the technologies affect, or are dependent upon plant 

operating variables that are inter-related. Commenters stated that the performance of some of the 

evaluated heat rate improvement strategies degrades over time, even with best maintenance 

practices and therefore, depending on the strategy employed or the technology installed to reduce 

heat rate at an existing coal-fired EGU, the unit heat rate initially obtained may increase over 

time. 

Commenters stated that the EPA did not take into consideration that HRI projects are not 

permanent in nature and plant performance begins to deteriorate immediately following the 

completion of the improvement project. Commenters stated that this should be taken into 

consideration when the EPA establishes their fossil fuel plant efficiency goals and state emission 

rates.

Commenters asked why didn't EPA study heat rate improvements previously undertaken to 

assess degradation.
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Commenters asked why the EPA did not provide any follow up assessment of degradation of 

these HRI.

Commenters stated that efficiency improvements generally degrade over time and asked why 

BB1 is based on the immediate payoffs of heat rate improvements, instead of accounting for 

gradual degradation. 

Commenters stated that although the 2009 S&L Report identified potential ranges of heat rate 

improvement associated with each HRI method, it did not include an evaluation of long-term 

sustainable heat rate improvements, or the potential degradation of heat rate improvements over 

time. Commenters stated that in general, heat rate improvement ranges listed in the 2009 S&L 

Report were based on potential performance following implementation of the particular HRI 

method. Commenters stated that however, the performance of many of the HRI methods 

included in the report will degrade over time, even with best maintenance practices; for example, 

turbine upgrades or replacements would be expected to provide a reduction in heat rate following 

implementation, but, as with all equipment upgrades, are susceptible to degradation over time. 

Commenters stated that routine maintenance practices, including major overhauls to replace 

packing and seals, can help maintain turbine efficiency; however, initial heat rate improvements 

achieved with the equipment upgrade will not be sustained over time. 

Commenters stated that other HRI methods reviewed in the 2009 S&L Report, including, but not 

limited to, boiler feed pump maintenance, air heater leakage, fan modifications, and acid dew 

point reduction strategies are similarly subject to degradation over time. Commenters stated that 

EPA did not take into consideration normal heat rate degradation when it applied the heat rate 

improvement ranges across the coal-fired fleet and by omitting normal degradation from its 

evaluation of fleet-wide average heat rate improvement opportunities, EPA overestimated 

efficiency improvements that can be achieved and sustained. 

Commenters stated that heat rate improvements do not remain constant, but degrade over time, 

ultimately increasing the rate and mass of CO2 emissions and EPA has falsely assumed heat rate 

improvements will remain constant. 

Commenters stated that almost all forms of heat rate improvement will degrade over time, 

requiring ongoing maintenance efforts, such as a turbine overhaul, to return the unit to near 

design conditions. Commenters stated that the heat rate improvement proposed by the EPA is an 

average improvement of 6 percent, and presumably includes all forms of heat rate improvements 

across the operating range and across the coal-fired fleet.

Commenters stated that opportunities to incorporate heat rate improvements resulting in a total 

of 6 percent or greater heat rate improvement at one load point are rare and are even less likely to 

carry that level of improvement across the load curve. Commenters stated that a significant 

driver of average heat rate is the capacity factor of a unit, and it is unlikely that an average heat 

rate improvement of 6 percent could be achieved and sustained on coal units that may be 

dispatched at reduced load points in the future in order to meet an emission reduction goal, or 

because of increased utilization of NGCC units (Building Block 2) or increased renewable 

generation (Building Block 3).
417

Commenters stated that any equipment-based heat rate improvements will experience 

degradation, requiring periodic overhauls to return efficiency to near original rates and also, 

emission control systems that have been installed or are expected to be installed will increase 

heat rates by approximately 1.5 to 1.75 percent.

Commenters stated that regarding heat rate improvements from equipment upgrades, it is well 

recognized that unit efficiency declines over time and equipment efficiency degrades overtime as 

wear takes place. Commenters stated that this includes all balance of plant equipment (fans, 

pulverizes, boiler feed pumps, boiler feed pump turbines, condenser circulating water pumps, 

etc.) which negatively affect unit heat rate. Commenters stated that during equipment outages, 

efforts can be made to return the unit to designed heat rate values, however, any recovered 

efficiencies eventually degrade and heat rate improvements are not permanent. Commenters 

stated that the assertion of permanent 6% heat rate improvements fails to recognize such 

degradation. 

Commenters stated that given the time frame associated with the rule, it is important to note that 

heat rate improvements degrade in effectiveness over time and it is unlikely that facilities can 

maintain a fixed heat rate improvement for a 10 year period. Commenters stated that Indiana 

requests that U.S. EPA consider revising the way that Building Block 1 is calculated over time to 

take into account the unavoidable degradation in heat rates even after all improvements are 

implemented. 

Commenters stated that in addition, neither the S&L report nor the preamble discussion 

addresses degradation in net heat rate resulting from the application of newly retrofitted 

emissions controls to comply with federal and state requirements such as the MATS rule. 

Commenters stated that moreover, EPA fails to recognize that the effectiveness of most heat rate 

improvement projects degrade over time and new improvement yield the first year will decrease 

over time as equipment and components age. 

Commenters stated that EPA's assumption of an achievable HRI of 6% unrealistically assumes 

that coal-fired EGUs will be able to maintain a 6% HRI over the course of the ten-year 

performance period. Commenters stated that this assumption is unfounded as HRI achieved 

through equipment upgrades actually decline over time due to many factors, such as natural 

degradation, installation of emission control technologies, and the coal-fired cycling. 

Commenters stated that therefore, due to EPA's faulty assumption that 6% HRI is consistent once 

achieved, coal-fired EGUs would in fact have to achieve a HRI greater than 6% and continue to 

implement additional HRI over time. 

Commenters stated that EPA incorrectly assumes that coal-fired power plants will maintain a 

heat rate improvement of 6%. Commenters stated that a problem with EPA's use of a 6% heat 

rate improvement as part of its standard-setting process is that EPA incorrectly assumes that 

coal-fired power plants will maintain that level of heat rate improvement over the course of the 

10-plus year performance period. Commenters stated that the heat rate improvements that coalfired power plants can achieve through the installation of new turbines, rotors, economizers, 

fans, and other such equipment necessarily will decline over time. Commenters stated that such 

declines are due to natural degradation of new equipment, installation of new pollution control 
418

technologies that impose parasitic loads, and changes in the way that the power plant operates in 

response to market evolution and changing customer demands. 

Commenters stated that EPA incorrectly assumes that coal-fired power plants will maintain a 

heat rate improvement of 6%. Commenters stated that EPA assumes in its Proposed Rule that 

routine maintenance will offset natural degradation. Commenters stated that this assumption is 

unsubstantiated. Commenters stated that the heat rate of coal power plants naturally deteriorates 

over time and is not fully offset by routine maintenance and cannot be addressed economically 

with new equipment. 

Commenters stated that heat rate degradation is a normal occurrence in steam plants that results 

from normal aging of plant equipment and systems and can be exacerbated by changes in 

operational duty cycles such as increased start-ups, shut-downs, operation at other than steady 

state load and run time at lower-than-rated capacity. Commenters stated that degradation also 

occurs when new systems that draw large amounts of auxiliary power, such as environmental 

controls, are added to a plant. Commenters stated that changes in coal supply to meet 

environmental requirements can also degrade heat rate due to changes in fuel quality and most of 

these types of degradation are not economically recoverable. 

Commenters stated that EPA erroneously assumes that heat rate improvements will remain 

constant over the 10-year interim period. Commenters stated that the performance of new 

equipment installed to improve heat rate will deteriorate over time due to normal wear and tear 

on the equipment. Commenters stated that EIA reports that the average heat rate of U.S. coalfired units degraded by two percent between 2002 and 2012 while routine maintenance was 

completed on the units. Commenters stated that EPA and S&L have recognized the value of 

turbine upgrades in improving heat rate performance, however, these improvements will degrade 

over time due to deposition, erosion and corrosion of the new blades. Commenters stated that 

EPRI states, "It has been demonstrated by experiment and field experience that up to 15 percent 

of MW generating capacity loss can be caused by buildup of blade deposits and several percent 

of turbine efficiency can be lost due to a deterioration of blade surface finish and deposits."

Commenters stated EPA's goal setting methodology overestimates the potential emission 

reductions by ignoring the very real aspect of heat rate degradation over time. 

Commenters stated that moreover, many projects implemented to improve heat rate depend on 

clean and tight tolerance parts, which are subject to wear and corrosion. Commenters stated that 

this equipment must be periodically taken out of service for maintenance to clean and restore 

tolerances. Commenters stated that even when this maintenance is performed, the "as-new" 

efficiencies or heat rate improvements cannot be maintained. Commenters stated that normal 

wear, fouling, and other efficiency degrading processes are effectively irreversible. Commenters 

stated that EPA ignores this reality, and therefore its assumption that heat rate gains accumulate 

and last indefinitely is simply incorrect. 

Commenters stated that the EPA identifies several "no-cost and low-cost options" from the S&L 

report that it classifies as "best practices," but that there are several key questions the EPA did 

not answer including why EPA did not consider degradation as a variability factor.
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Comment 48: Comments regarding unit-specific data on best practices and equipment upgrades 

(or lack thereof)

Response 48: For the EPA’s response to these comments, see section V.C of the final rule 

preamble of the CPP and Chapter 2 of the GHG Mitigation Measures TSD supporting the final 

CPP. Among other things explained therein, with respect to concerns about individual EGUs or 

groups of EGUs, the final CPP provides states the flexibility to develop plans with emission 

standards that more precisely take into account the potential heat rate improvement of individual 

EGUs—should states desire to consider potential heat rate improvement at all. Furthermore, if an 

affected EGU cannot meet the particular emission standard solely because it has below-average 

potential to reduce emissions through heat rate improvements, then in instances where the EGU’s 

state plan allows emissions trading, the EGU can acquire credits or allowances from affected 

EGUs that have above-average potential.

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

Commenters stated that despite the broad deployment of GE technology and services in the coal 

sector, they do not know the full extent of the current penetration of heat rate improvement 

projects.GE lacks complete information on the extent of best practices and upgrades 

implemented within the fleet. Commenters stated that best practices reside with owners and 

operators, and are not necessarily externally available and although over 75% of GE's large fossil 

fleet has undertaken heat rate improvements, and that commenters lack sufficient information as 

to retrofits performed on other Original Equipment Manufacturers, as well as plants that have 

decided not to invest in upgrades.

Commenters stated that San Miguel has reviewed the S&L list of improvements and provided a 

table comparing the S&L improvement list to what has been implemented at San Miguel and 

stated that the list of available improvements yet to be installed at San Miguel leaves little room 

for improvements. Commenters provided a table of improvements that are available according to 

the S&L report versus what has already been implemented at San Miguel for the Boiler Island, 

Turbine Island, Flue Gas System, Air Pollution Control System, Equipment, Water Treatment 

System. 

Commenters stated that S&L provided the changes to the units' heat rate based on the plant 

improvements that have been implemented at TEP as well as the potential improvements that can 

be implemented. Commenters referred to several tables:

Summary of Heat Rate Changes for Unit 1 (Achieved to Date and Potential) (Table 3-1). 

Commenters stated that Unit 1 has achieved an improved heat rate by an estimated 1.8% to date 

and that there is also an opportunity to further improve the heat rate by an estimated 2.73% by 

converting the bottom ash handling system to a conveyor type, reducing the air pre-heater 

leakage, and performing a turbine overhaul. 

Summary of heat rate changes for Unit 2 achieved to date and its potential for further 

improvements (Table 3-2). Commenters stated that following the recent repairs to the air heat to 

reduce air pre-heater leakage; the overhaul of the HP, IP, and LP sections of the turbine; and the 

conversion of the bottom ash handling system, Unit 2 has achieved a heat rate improvement of 
420

6.03%. Commenters stated that TEP currently practices good maintenance practices so no further 

potential improvements were identified for Unit 2.

Commenters stated that Table 3-3 and Table 3-4 summarize the heat rate changes for Units 3 and 

4, respectively. Commenters stated that the commercial operating dates for these two units were 

very recent, 2006 and 2009 respectively, limiting any opportunities for heat rate improvements. 

Commenters stated that TEP should continue to implement best maintenance and operating 

practices on all four Units to reduce significant degradation on their heat rates. 

Commenters stated the changes to the units' heat rates based on the modifications implemented 

at CGS as well as the potential improvements that can be implemented are summarized in 

different tables. Commenters presented Table 4-1 Summary of Heat Rate Changes for Unit 1 

(Achieved to Date and Potential). Commenters stated that Unit 1 has improved heat rate by an 

estimated 4.8%, however the total heat rate improvement including impacts of switching to PRB 

coal is approximately 3.0%. Commenters stated that for Unit 2, the improvement in heat rate is 

estimated to be 3.9%, however the total improvement including switching to PRB coal is 

approximately 2.1%. Commenters stated that Unit 2 has less of an improvement to heat rate due 

to the SCR that had to be installed for regulatory compliance with the Consent Decree. 

Commenters stated that the potential improvement in heat rate is estimated to be 1.0% for each 

unit based on the potential for turbine upgrades. Commenters stated that the units at CGS have 

implemented some of the heat rate improvement technologies prior to 2012. SRP should 

continue to implement good maintenance practices to prevent significant degradation of the 

units' heat rates. 

Commenters stated that in addition to the numerous steps voluntarily undertaken by Heartland to 

promote renewable energy and energy efficiency measures, both of the coal-fired power plants 

from which Heartland procures energy have taken measures to maximize their efficiency levels. 

Commenters stated that these measures improve the heat rates at these plants and referred to the 

Proposed Rule and TSD. Commenters stated that however, EPA adopted a top-down, statistical 

approach to Building Block 1 that does not consider the unique aspects of individual generating 

facilities; for example, EPA's analysis did not consider technical achievements and 

improvements that result in reduced GHG emissions, including whether a facility was retrofitted 

with low-NOx burners, selective catalytic reduction devices, scrubbers, or new burner and 

furnace management systems. Commenters stated that similarly, EPA did not consider changes 

to a facility's fuel supply, such as switching to coal supplies with a higher energy density that 

emit less carbon. Commenters stated that overall, EPA's methodology failed to compare 

individual generating units or do any sort of subcategorization. Commenters stated that 

additionally, it is unclear whether EPA considered newer units that were built with the latest and 

most efficient technology and therefore could not feasibly improve heat rates and as a result of 

these shortcomings in EPA's statistical approach, the specific pollution control and efficiency 

improvements at the coal-fired power plants from which Heartland procures energy will not be 

properly credited to the plants' respective home states' specific carbon emission reduction goals.

Commenters stated that Whelan Energy Center Unit 2 ("WEC2"), of which Heartland owns an 

80 MW share, was built with the highest achievable efficiencies available at the time of 

construction (2006 to 2011).
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Commenters stated that WEC2, located in Nebraska, is owned by five public power utilities, 

including Heartland, which formed the Public Power Generation Agency ("PPGA"), an interlocal agency established in Nebraska for the sole purpose of constructing and operating WEC2. 

Commenters stated that WEC2 burns low-sulfur coal from the Powder River Basin. It boasts 

dual rail access for delivery of coal and the use of groundwater for cooling. Commenters stated 

that the plant also meets all of the latest pollution control standards with an air quality control 

system that includes an electrostatic precipitator to remove fly ash, a scrubber to remove sulfur 

dioxide, selective catalytic reduction to reduce nitrous oxides ("NOx"), and a baghouse for 

additional particulate removal, as well as mercury removal controls.

Commenters stated that at this time, Heartland is not aware of any new technologies in the areas 

of boiler and/or turbine efficiency that would be available to improve upon the current WEC2 

design. Commenters stated that furthermore, in the areas of turbine cycle and boiler cycle 

efficiencies, any improvements that could be made in the future will not be practical to 

implement due to the inability to change steam pressures and temperatures without a wholesale 

reconstruction of the facility. Commenters stated that in addition to steam cycle efficiencies, 

PPGA chose to install low NOx burners at additional cost to reduce excess air level needs, thus 

improving boiler efficiency. From an environmental perspective, WEC2 was designed with best 

available technologies at the time of construction.

Commenters stated that the coal-fired Laramie River Station ("LRS") has also made numerous 

efficiency upgrades in the past 5 to 6 years (and thus largely pre-dating the Proposed Rule's 2012 

baseline cut-off) through periodic turbine overhauls. Commenters stated that specifically, LRS 

made the following upgrades/updates to plant facilities to improve boiler efficiency:

a. High pressure/intermediate pressure turbine upgrades, which provide higher operating 

efficiencies.

b. Combustion optimizer software, which reduces NOx while attempting to control 

carbon monoxide emissions.

c. Air heater basket replacement, which creates less differential pressure to reduce fan 

power consumption.

d. Hydrojet cleaning system, which cleans boiler walls to reduce boiler exit gas 

temperature to improve boiler efficiency, and helps to lower superheater attemperation 

spray flow (which reduces boiler efficiency).

e. Intelligent Sootblowing Controls, which clean dirty areas of the boiler without 

inefficient overblowing.

f. Steam temperature control system enhancement, which is an advanced control system 

that provides more precise steam temperature control to improve turbine cycle heat rates, 

and reduces attemperation spray flow to improve cycle efficiency.

g. Pulverizer throat redesign, which improves pulverizer fineness to reduce unburned 

carbon losses.
422

Commenters stated that as described above, these measures were not taken into account by EPA 

when developing Building Block 1. Commenters stated that in any event, because Building 

Block 1 was developed using an industry-wide approach, the Heartland EGU plants' home states 

of Nebraska and Wyoming will not receive any additional benefit from these efficiency measures 

from a compliance perspective. Commenters stated that this concern is further compounded by 

the threat that these plants may be subject to future emission reductions or unit closures, which 

could result in stranded costs for the plants' owners and customers for the costs of the pollution 

control technology and efficiency measures. Commenters stated that accordingly, Heartland 

respectfully requests that EPA recalculate its Building Block 1 to account for technical aspects of 

individual facilities and to pass along the compliance benefits of those carbon-reducing 

technologies to those facilities' home states. 

Commenters stated that Wisconsin electric utilities are regulated by the Public Service 

Commission of Wisconsin (PSCW). Commenters stated that through PSCW's oversight, 

Wisconsin utilities are already incented, and to a large degree required, to maintain and improve 

heat rates when prudent for the electric ratepayer and as a result, Wisconsin's coal-fired EGUs 

are already very efficient.

Commenters stated that Wisconsin conducted an assessment of the HRI actions included in the 

Sargent and Lundy report to see which ones were already implemented at individual coal-fired 

EGUs in Wisconsin. Commenters stated that this assessment showed that many of the Sargent 

and Lundy HRI actions have already been implemented; in addition, this analysis showed that 

some of these HRI actions are not applicable to Wisconsin's coal-fired EGUs.

Commenters stated that the qualitative results of the analysis are shown in a table (Table 1. HRI 

Actions Implemented at Coal-fired EGUs Prior to 2012 by Wisconsin Utilities). Commenters 

stated that the entry for an EGU indicates that some level of HRI has already been completed. 

Commenters stated that the EGUs in Table 1 accounted for more than 90% of the coal-fired

electricity generation in 2012 for Wisconsin. Commenters stated that this assessment excludes 

coal-fired EGUs that will be retired or converted to natural gas prior to 2020; this exclusion is 

appropriate in calculating the HRI for units operating in 2020. Commenters stated that to 

estimate the actual range of HRI potential of these EGUs, two cases were considered. 

Commenters stated that in the first case, the maximum HRI value was applied to units that had 

undertaken no HRI actions and the minimum HRI value was applied to units that had partially 

implemented HRI actions. Commenters stated that this method resulted in a total HRI of 0.5% 

(from the gross heat rate) for the EGUs in Table 1.

Commenters stated that the second case is intended to illustrate an upper bound of potential for 

implementing these HRI actions at Wisconsin units and in this case, the maximum HRI value 

was applied to EGUs that had not indicated implementation of the HRI action, the average value 

for each HRI action was applied to EGUs that had partially implemented actions, and the 

minimum HRI value was applied to EGUs that appeared to already implement the HRI action (to 

allow that some level of improvement for intelligent sootblowing and turbine maintenance HRI 

actions could still be achieved at these units). Commenters stated that this second, upper bounds 

case yields a total fleet-wide HRI of 2.3% from the gross heat rate.
423

Commenters stated that these analyses show that the HRI potential for Wisconsin EGUs is well 

below the 6% presumed by EPA and in fact, the 2.3% indicated by this analysis may still be a 

value that is beyond the capability of the Wisconsin EGU fleet. Commenters stated that it is 

more likely that an actual achievable HRI value lies closer to 0.5% for Wisconsin coal-fired 

EGUs, however, it is acknowledged that, given the assumptions made, further analysis is needed 

to refine these numbers. Commenters stated that it should be noted that gross heat rate values 

were used because of the higher confidence in these values. Commenters stated that if the net 

heat rate were used, as EPA did, the actual HRI potential for Wisconsin EGUs would be even 

lower. 

Commenters stated that Great River Energy's Coal Creek Station exemplifies Dr. Gaikwad's 

findings on best operational and maintenance practices. Commenters stated that because of a 

multitude of projects completed at Coal Creek Station since 2004, it has reduced the plant's 

average heat rate by 8 percent, an accomplishment of which it is very proud. Commenters stated 

that installation of DryFiningTM technology, through a cooperative demonstration program with 

the U.S. Department of Energy, accounts for approximately four percentage points of the 

reduction. Commenters stated that given the significant improvements achieved to date, they do 

not believe that further reductions are possible or appropriate. Commenters stated that if the State 

of North Dakota were to conduct a case-by-case analysis of historic maintenance practices and 

heat rate performance in light of Dr. Gaikwad's assessment, commenters believe they would find 

that no further reductions are appropriate at Coal Creek Station in setting the state's carbon goals 

or for inclusion in its state implementation plan. 

Commenters stated that on page 34860 of the preamble, EPA asks if its proposed 6 percent heat 

rate improvement is achievable at existing coal-fired power plants. Commenters stated that South 

Dakota has consulted with the operator of its one coal-fired power plant and identified three 

reasons it is not achievable. 

Commenters stated that South Dakota has one coal-fired power plant, the Big Stone Plant and the 

owner of the facility, Montana-Dakota Utilities Company, NorthWestern Energy, and Otter Tail 

Power Company, affirms that it has already implemented the majority of technology upgrades 

and best practices to achieve heat rate improvements identified in the Sargent and Lundy Study. 

Commenters stated that EPA estimates a 4 percent improvement, on average, is achievable due 

to operating and maintenance best practices such as turning off unneeded pumps at reduced 

loads, installing digital control systems, more frequent tuning of existing control systems, early 

like-kind replacement of worn components, etc. Commenters stated that because the Big Stone 

Plant has already completed these items that are applicable to the plant, the additional 4 percent 

improvement that EPA is proposing has already been achieved, and therefore it is not possible to 

gain additional heat rate improvements. 

Commenters stated that EPA estimates a 2 percent improvement, on average, is achievable due 

to various upgrades to the system such as economizer replacement, air preheater improvements, 

turbine overhaul, etc., but again, if power plants have already implemented these upgrades, some 

of which the Big Stone Plant attested it has completed, the additional 2 percent EPA is proposing 

is no longer achievable.
424

Commenters stated that to verify whether heat rate improvements were realized by the Big Stone 

Plant, South Dakota obtained carbon dioxide and net generation data from EPA's eGRlD data 

sets at http://www.epa.gov/cleanenergy/energy-resources/egrid/. Commenters stated that South 

Dakota looked back 10 years to be consistent with the Prevention of Significant Deterioration 

program. Commenters stated that EPA's data sets did not contain data for calendar years 2003, 

2006, and 2008. Commenters stated therefore, the heat rate improvements were compared to 

calendar year 2004 and are shown in a table. Commenters stated that this comparison shows the 

Big Stone Plant has already achieved more than the 6 percent reduction assumed for the building 

block 1 goal and as stated above, has already achieved the improvements EPA desires to achieve 

through the proposed rule. 

Comment 49: Comments regarding misattribution of improvements from "best practices" to 

"equipment upgrades" and vice versa

Response 49: For the EPA’s response to these comments, see section V.C of the final rule 

preamble of the CPP and Chapter 2 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 the nine lowest options were considered to be part of what the EPA calls 

"best practices" while the remaining four high-cost options are considered to be "upgrades". 

Commenters stated that according to the EPA "best practices include no-cost or low-cost 

methods such as the installation or more frequent tuning of control systems and the in-kind 

replacement of worn existing components and that upgrades often involve higher costs and 

greater downtime, such as, extensive overhaul or upgrade of major equipment (turbine or boiler) 

or replacing existing components with improved versions." Commenters stated that although 

many of the "best practices" options provided in the list are strictly dependent on employing 

optimized operating and maintenance practices (e.g., turning off unneeded pumps, installation of 

digital controls systems, earlier in-kind replacement of worn components, etc.), some of the 

options include large project capital and/or physical changes. Commenters stated that however, 

the heat rate improvement achieved after repairs during outages may not be sustainable. 

Commenters stated that the term "best practices" implies procedural changes rather than 

equipment changes and that therefore, S&L believes the following technologies would be better 

considered as equipment upgrades rather than best practices: NN, ISB, Installation of EMS on 

ESP, SCR system optimization, FGD system optimization (including additional flow correction 

devices), and Advanced cooling tower packing.

Commenters stated that EPA's attempt to account for coal-fired EGU specifics and whether HRI 

"equipment upgrades" have already been performed by "conservatively estimating" a potential 

HRI improvement of 2 percent instead of 4 percent supports the argument that the EPA's 

approach is arbitrary and unreasonable. Commenters stated that EPA's determination that only 

half of the possible equipment upgrades may have already been deployed is unsupported by any 

data, and the EPA has failed to explain how it ensured that any of the HRI improvements that 

were attributed to O&M "best practices" in its statistical bin analysis should not more properly 
425

be attributed to these "equipment upgrades" or vice versa. Commenters noted that turbine 

overhauls are already routinely done on most EGUs to prevent maintenance issues and gain back 

some of the efficiency lost over time due to equipment degradation and therefore, significant 

HRI from steam turbine upgrades (the most expensive measure) are probably more appropriately 

deemed as a best practice, since they are routine. Commenters stated that once either an overhaul 

and/or upgrade is performed, the benefits will once again immediately begin to degrade until the 

next overhaul. Commenters stated that the remaining HRI potential through "equipment 

upgrades" is likely even much lower, given that many of these measures have been already 

applied on EGUs and the EPA cannot require affected EGUs to duplicate emission reductions 

they have achieved using measures they have already taken. 

Commenters also stated that many of the "best practices" that EPA identifies in the TSD are not 

operating practices at all, but instead involve replacing or upgrading physical components of the 

EGU or related power plant equipment. See GHG Abatement Measures TSD at 2-33, Tbl. 2-13 

(listing "No-Cost and Low-Cost Options" EPA equates with "best practices"). These actions have 

no discernible connection to variability in a unit's heat rate. Although EPA quantifies the 

potential benefits of these measures in terms of reduced heat rate variability, the Agency presents 

no evidence that the "best practices" measures actually have the effect of reducing heat rate 

variability (as opposed to improving a unit's average heat rate while maintaining a similar range 

of variation in individual observations).

Comment 50: Comments stating that improvements are not cumulative across the board and 

their potential for HRI cannot simply be added together.

Response 50: See Chapter 2 of the GHG Mitigation Measures TSD supporting the final CPP for

EPA’s response to this comment. We agree that the benefits of HRI measures are not always 

additive.

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

Commenters stated that EPA's 6 percent figure is based in part on a mischaracterization of a 

2009 Sargent & Lundy report (the "2009 Report") and that according to Sargent & Lundy, the 

2009 Report does not conclude that any individual coal-fired EGU or any aggregation of coalfired EGUs can achieve a 6 percent heat rate improvement, as proclaimed by EPA. Commenters 

stated that the agency's erroneous conclusion that 6 percent heat rate improvements are 

achievable across-the-board at coal-fired power plants was apparently based on its incorrect 

assumption that heat rate improvements achievable through the implementation of individual 

strategies can always be added together, but in reality, the improvements are cumulative for only 

certain types of strategies, such as those derived from minimizing auxiliary power, fuel drying, 

and improving heat rejection. Commenters stated that other actions that increase heat removal 

from the boiler - economizer modifications, improved air heater performance and low 

temperature heat recovery- may not provide cumulative benefits.

Commenters stated that EPA identified four potential upgrade methods included in the S&L 

Report to justify that its two percent net heat rate improvement is feasible if all methods were 
426

applied on an EGU that had not already made such upgrades: (1) economizer replacement, (2) 

acid dew point control, (3) combined variable frequency drive ("VFD") fan, and (4) turbine 

overhaul.

Commenters stated that contrary to EPA's interpretation of the S&L Report, however, each 

equipment upgrade's expected heat rate improvement cannot simply be added together to reach 

an assumed total improvement that efficiency projects are not additive and some projects may, in 

fact, counteract the potential benefits of other projects performed at a unit. Commenters stated 

that EPA has made overly aggressive assumptions regarding the potential for heat rate 

improvements associated with its economizer replacements, acid dew point control projects, and 

VFD motors.

Commenters stated that in theory, economizer replacements complemented by acid dew point 

control measures may have the potential to improve heat rate at certain units. Economizer 

replacements can do so through increased heat absorption in the boiler, thereby reducing overall 

exit gas temperature and acid dew point control can help mitigate subsequent corrosion by 

reducing sulfuric acid mist condensation that harms air heaters and downstream ductwork as a 

result of either of these upgrades. Commenters stated that lower exit gas temperatures result in 

improved heat rate from these measures, but because the driver is reduction in exit gas 

temperature, EPA is wrong to couple those two distinct upgrades as additive when achieving the 

same terminal exit temperature.

Commenters found that many of the available actions outlined in the Proposed Rule to improve 

heat rate do not provide cumulative benefits and thus cannot be added together to estimate the 

total potential efficiency gains at fossil fuel-fired EGUs; in particular, measures that increase 

heat transfer from the boiler do not provide additive efficiency benefits because heat that is 

recovered by an individual project cannot be recovered a second time by another project. 

Commenters stated that EPA's assessment of available heat rate improvements through 

"equipment upgrades" is arbitrary. Commenters stated that EPA set this component of the target 

by identifying the four most costly heat rate improvement methods listed in the 2009 Sargent & 

Lundy report based on average estimated $/kW costs, then simply adding together the average 

estimated Btu/kWh improvements for each. Id. at 2-33. Commenters stated that based on this 

calculation, EPA concluded that the four specified equipment upgrades could provide a 4 percent

heat rate improvement if all were applied on an EGU that has not already made them, but 

"conservatively" reduced the target to 2 percent because "some units may have applied at least 

some of the upgrades." Id. at 2-34, 2-35; 79 Fed. Reg. at 34,860 ("We therefore propose to use as 

a data input for purposes of developing state goals an estimate that, on average across the fleet of 

affected EGUs, only half of the full equipment upgrade opportunity just described remains."). 

Commenters stated that not only does this methodology include turbine and other upgrades that 

are beyond the scope of section 111, it erroneously assumes that the heat rate improvements from 

these upgrades are cumulative and that they provide consistent long-term benefits. Commenters 

stated that in reality, the combined payoff from these four upgrades will be less than the sum of 

each measure's payoff would be when applied alone to an EGU, and these heat rate benefits will 

begin to degrade immediately once the unit returns to service. Commenters stated that also, 

EPA's reliance on the average Btu/kWh improvement of each measure is flawed because the 

potential payoff of each upgrade is highly unit-specific and is skewed towards lower values. See 
427

NCC Report at 71 ("The benefits and cost are highly variable and depend on the specifics of any 

one site."). Commenters stated that for example, the NCC Report notes that large gains from 

turbine overhauls are possible only for "units that are severely degraded," and potential benefits 

from variable frequency drives depend heavily on existing equipment. Id. at 62, 65-66. 

Commenters moreover stated that one of the measures EPA identifies - acid dew point control -

is not broadly available and has not even been proven for most of the generating fleet. 

Cichanowicz Statistical Critique at 10 (discussing achievability of 2 percent heat rate 

improvement through "equipment upgrades"). 

Commenters stated that the combinations of several heat rate improvement projects by 

percentage are not additive in nature for coal fired units and that the combination of several 

projects by percentage by the rules of mathematics cannot be distributive and additive. 

Commenters stated that for example, a two percent heat rate improvement project cannot be 

added to another heat rate improvement project of three percent to result in a sum total of five 

percent for the unit and the net effect of both projects will likely be less than the sum total. 

Commenters stated that industry testing of unit performance has proved this many times and 

usually is guaranteed by the vender at one specified high load and this is not to say that heat rate 

improvement projects do not work, but rather, heat rate improvement projects' highest benefits 

are seen at full load or its highest efficiency point.

Commenters stated that regarding the claim of 4% heat rate improvement from items in the "No 

Cost or Low Cost" Options, the 2014 UARG Heat Rate Assessment Report cited typical gains in 

efficiency for most of the options listed in Table 2-13 of the 2014 GHG TSD. Commenters stated 

that each option individually offers 0.1 - 0.35% improvement. Commenters stated that the same 

report noted for many options the benefits in heat rate improvement do not add linearly; as 

"payoff" of one can detract from the "payoff" of another, such as intelligent sootblowing; neural 

net software, and ESP modifications. 

Commenters stated that EPA's assessment of available heat rate improvements through 

"equipment upgrades" is arbitrary. Commenters stated that the Agency set this component of the 

target by identifying the four most costly heat rate improvement methods listed in the Sargent & 

Lundy report, based on average estimated $/kW costs, then simply adding together the average 

estimated Btu/kWh improvements for each. Based on this calculation, EPA concluded that the 

four specified equipment upgrades could provide a 4 percent heat rate improvement if all were 

applied on an EGU that has not already made them, but "conservatively" reduced the target to 2 

percent because "some units may have applied at least some of the upgrades." Commenters 

stated that this methodology erroneously assumes that the heat rate improvements from these 

upgrades are cumulative and that they provide consistent long-term benefits. Commenters stated 

that in reality, the combined payoff from these four upgrades will be less than the sum of each 

measure's payoff would be when applied alone to an EGU, and these heat rate benefits will begin 

to degrade immediately once the unit returns to service. Commenters stated that EPA cannot 

require affected EGUs to duplicate emission reductions they have achieved using measures they 

have already taken. 

Commenters stated that based on EPA's assumptions, an existing coal unit will be able to achieve 

a 6 percent improvement only if it both has high variability in heat rate that is attributable to poor 

O&M practices and has not already completed at least half of the available capital projects 
428

designed to improve heat rate. Commenters stated that while some units may fit this description, 

EPA presents no information that a majority of units, or even a large number, can make both the 

operating and capital improvements EPA assumes. Commenters stated that EPRI warns that its 

research shows that "heat rate improvements are not necessarily additive." Commenters stated 

that as Cichanowicz & Hein showed, the benefits of different efficiency measures are not 

cumulative.

Commenters stated that while EPRI studies indicate there may be opportunities to achieve a 

variety of heat rate improvements at an EGU in the range of 0.5% - 5% on a net generation basis, 

these values may not be additive and their applicability and realized savings are highly 

dependent on the characteristics of an individual unit. 

Commenters stated that EPA wrongly extrapolates that each of the heat rate improvement 

methods identified in the studies can be combined in practice to achieve a greater improvement, 

and that this assumption is flawed. Commenters stated that many of the heat rate improvement 

methods that EPA identifies cannot be combined and are not cumulative. Commenters stated that 

in other words, once the improvement is achieved by one method, another method cannot 

achieve the same or similar improvement. 

Commenters stated that it appears that EPA assumed that heat rate improvements cited in the 

2009 Report were additive and applicable to all coal-fired units, when the 2009 Report makes it 

clear that it would not be feasible to implement all of the examined alternatives to achieve the 

sum total of their heat rate improvements. Commenters stated that furthermore, the 2009 Report 

does not state any range of overall heat rate improvements that could be expected from 

implementing any combination of the examined alternatives. Commenters stated that in fact, the 

case studies provided in the report estimated potential heat rate improvements of 4% and 1.2% 

for the 250 MW and 850 MW units, respectively and contrary to the approach used by EPA, heat 

rate improvement opportunities, and the associated costs, must be evaluated on a case-by-case 

basis taking into consideration unit-specific design, operations, and controls. 

Commenters stated that Building Block 1 requires that affected coal-fired electric generating 

units improve operating efficiencies or "heat rates" to achieve a 6 percent target, however, EPA's 

assessment fails to consider that Vectren, like many utilities, has already installed many of the 

recommended heat rate improvement projects, including the installation of highly efficient 

"dense pack" turbine technology on its baseload units, thus, Vectren's ability to achieve 

additional heat rate improvements is constrained by its previous investments. Commenters stated 

that also, EPA incorrectly utilizes the data in prior heat rate improvement reports, particularly the 

Sargent and Lundy report cited in the proposal, by viewing the utilization of the upgrade options 

as additive. Commenters stated that many of the recommendations overlap or would be negated 

by the implementation of additional heat rate improvement projects and economics aside, it 

would not be physically possible to implement all of the Sargent and Lundy upgrade options at a 

single unit to achieve the additional efficiencies to meet the required 6 percent level.

Comment 51: Comments regarding units that do not have any efficiency improvement 

technically available
429

Response 51: See section V.C of the final rule preamble of the CPP and Chapter 2 of the GHG 

Mitigation Measures TSD supporting the final CPP for EPA’s response to this comment.

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

Commenters described that some of the units that are in service currently were not running at or 

near full capacity in 2012 and therefore have resulted in an incorrect baseline for the purposes of 

calculating goals. Commenters stated that for example, Sherco Unit 3 in Minnesota was not 

running in 2012 due to issues related to a turbine upgrade. Commenters stated that EPA's NODA 

appears to address this question, but if it promulgates a final rule that relies solely on 2012 data, 

the Agency should clarify how efficiency can be improved on a unit that was not running at the 

time of its analysis and hence not included in the baseline. Commenters stated that EPA should 

also address units that are operating at maximum efficiency. Commenters stated that for 

example, Iatan 2, Plum Point, and Prairie State units all came online in the last three years and all 

have the most efficient technology. Commenters stated that there is no improvement technically 

available for these units regardless of cost and that was not factored into EPA's baseline 

calculations. Commenters stated that the Agency should adjust its assumptions to take into 

account units that do not have any efficiency improvement technically available. 

Commenters stated that some of the improvements EPA assumes will be made at coal plants are 

not practically available for or usable by some of those plants. 

Commenters stated that heat rate improvement opportunities depend on the original design of the 

unit, including space constraints. Commenters stated that some units may not be able to achieve 

a 6% heat rate improvement because of their inherent physical design considerations. 

Comment 52: Comments regarding EGU retirements

Response 52: For the EPA’s response to these comments, see section V.C of the final rule 

preamble of the CPP and Chapter 2 of the GHG Mitigation Measures TSD supporting the final 

CPP. Furthermore, as discussed in section I.A of the final rule preamble, the interim compliance 

period has been adjusted to begin in 2022, and the reduced emissions from any affected EGU 

retiring post-2012 can be accounted for in demonstrating compliance. 

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

Commenters stated that there is no evidence that EPA considered the impact of retiring coal units 

on the results of the analyses. Commenters stated that if a unit closes, there can be no HRI 

potential at that unit. Commenters stated that EPA ran a sensitivity analysis that excluded units 

that have announced retirement dates before 2016. See Abatement Measures TSD at 2-35. 

Commenters stated that however, this did not include the additional 46-49 GW of coal-based 

units that EPA projects will retire as a result of compliance with the proposed guidelines. See 

Resource Adequacy and Reliability Analysis (Resource Adequacy TSD) at 1. Commenters stated 

that presumably, these units have higher design heat rates because they are older and that 

accordingly, they might appear (statistically) to have significant HRI potential, but this potential 

will not be realized if these units retire. Commenters stated that therefore, EPA should exclude 
430

these 46-49 GWs when assessing the future HRI potential of the existing coal-based fleet. 

Commenters stated that inclusion of these units likely inflated EPA's assessments of HRI through 

O&M "best practices." 

Commenters stated that EPA's assumed 4% to 6% efficiency improvement target at existing coal 

plants is not achievable in part because e remaining coal fleet after the anticipated 50+ GW of 

coal unit retirements in 2015-17 will consist mainly of large supercritical units that have little 

potential for additional efficiency gains. 

Commenters stated that while it is possible or even reasonable on a national scale to expect the 

total fleet of coal EGUs to achieve a heat rate improvement of 4 to 6 percent or more, a national 

potential does not correlate directly to the capabilities of a single coal EGU. Commenters stated 

the rule preamble and Goal Setting Technical Support Document (TSD) recognize that not all 

efficiency improvements can be made at each coal plant, and at many plants some improvements 

may have already been accomplished. Commenters stated that specifically in Washington, their

only coal fired power plant is under a federally enforceable, legal obligation to cease the 

combustion of coal by the end of 2025. Commenters stated that EPA guidance and rules 

regarding retrofitting emission controls on existing power plants require a consideration of the 

remaining useful life of the plant in the economic evaluation of the cost effectiveness of adding 

controls. Commenters stated that heat rate improvements are intrinsically a pollution prevention 

type of emission control. Commenters stated that all cost effective heat rate improvements have 

been made to this plant and the remaining plant lifetime is short enough to make any additional 

heat rate improvements not cost effective. Commenters stated that they would suggest that this 

situation may apply to other states where there is a legally binding and guaranteed commitment 

to cease coal combustion or shut down coal facilities in the interim period. Commenters also 

stated that for these situations they suggest that EPA consider excluding specific heat rate 

improvements for those units when the effects of building block one are calculated.

Commenters stated EPA's evaluation of historic heat rate data is biased by the inclusion of units 

that have been or will be retired before the first compliance period. Commenters stated that many 

of these retiring units were designed with less efficient processes (no reheat cycles, subcritical 

designs, and age-related operational constraints) which suggests a larger amount of heat rate 

variability and potential opportunities for improvement, than is present for the high-performing 

units that are suggested to remain in-service when the rule becomes effective. Commenters stated 

that units that are retired or that will be retired before 2020 should be excluded from the analysis 

to ensure that the evaluation reflects only those potential opportunities that may be available on 

the units that will remain in operation during the period affected by the guidelines.

Commenters stated that they strongly believe that the statistical analysis conducted by U.S. EPA 

should not have included those units which will be shutting down prior to the beginning of the 

interim compliance period, and that the inclusion of these likely inefficient units introduced a 

strong conservative bias to the analysis. 

Commenters stated that after announced and planned retirements, there will be very few, if any, 

uncontrolled coal-fired units operating in Ohio after 2016.
431

Commenters stated that in their analysis of existing plans, it was assumed that Tennessee's 

utilities are already planning to achieve a 6 percent heat rate improvement at existing coal plants. 

Commenters stated that while this assumption may be achievable, they instead evaluated the 

decisions that they have already made to retire a number of their oldest, dirtiest and least 

economic coal-burning units. Commenters stated that for the following units retirement decisions 

have already been made:

• Johnsonville

• John Sevier

• Allen

Commenters stated that EPA included the electric generation and carbon emission levels from 

these three coal-fired EGUs in Tennessee's baseline 2012 carbon emissions rate, however, EPA 

did not include the planned retirements of these EGUs when calculating Tennessee's emission 

reduction target.

Commenters stated that applying the retirement assumption to Tennessee's 2012 baseline 

emission rate by subtracting out the 2012 level of coal-fired generation from these units results in 

an emission rate reduction from 2,015 lbs/MWh to 1,963 lbs/MWh, a decrease of 52 lbs/MWh.

Commenters stated that given the fact that a strict application of the Building Blocks would 

result in all coal units in Nevada being replaced with natural gas re-dispatch by 2020, there exists 

a disincentive to invest in heat rate improvements since Nevada's coal fueled EGUs would be 

slated to retire at the same time the heat rate improvements are required. Commenters stated that 

EPA should properly consider the potential application of the Building Blocks where affected 

generating units may already be planned for retirement between 2020 and 2029. Commenters 

stated that currently, the depreciation schedule for NV Energy's North Valmy Generating Station 

would have both units at this facility retire as soon as 2025. Commenters stated that in this and 

other cases, it may not make economic sense to invest in high-cost plant heat rate improvements 

where depreciation schedules or firm commitments have been made to shut a unit down during 

this near term timeframe. Commenters stated that however, such unit retirements will still 

support the ultimate emission reduction target at 2030. Commenters stated that EPA should 

ensure that the final rule gives states the flexibility to address remaining useful life while 

meeting the final 2030 emissions goal by either removing the interim goal or phasing in all 

Building Blocks.

Commenters stated that the EPA should not have considered units that are expected to close 

when assessing fleet-wide heat rate improvement potential through statistical analysis. 

Commenters stated that there is no evidence that the EPA considered the impact of retiring coal 

units on the results of its HRI analyses. Commenters stated that if a unit closes, there can be no 

HRI potential at that unit. Commenters stated that the EPA ran a sensitivity analysis that 

excluded units that have announced retirement dates before 2016 but that however, this did not 

include the additional 46-49 GW of coal-based units the EPA projects will retire as a result of 

compliance with the Proposed Guidelines. Commenters stated that presumably, these units have 

higher design heat rates and have more variability in heat rate because they are older and tend to 
432

operate at relatively low capacity factors and accordingly, they might appear (statistically) to 

have significant heat rate improvement potential, but this potential will not be realized if these 

units retire. Commenters stated that therefore, the EPA should exclude these 46-49 GWs when 

assessing the future HRI potential of the existing coal-based fleet and inclusion of these units 

likely inflated the EPA's assessments of available HRI through O&M "best practices."

Commenters stated that they are concerned that HRI measures made at the coal-fired utilities 

prior to 2012 cannot be considered and are not taken into account by U.S.EPA. Commenters 

would stress that the coal fleet in Ohio is highly efficient when compared to the nationwide coal 

fleet and Ohio EPA's examination of gross heat rate data for the nation-wide coal-fired units, 

using data available from the Clean Air Markets Database showed of the top 10% of units in 

terms of efficiency (88 units), Ohio utilities represented 13 of these, or 15%. Commenters stated 

that similar representation was observed in 2013 data and nationwide in 2012, gross heat rate 

was 10,352 BTU/kW-h. Commenters stated that although Ohio utilities had 19 units with heat 

rates greater than this average, 11 of those units are to retire in 2015. Commenters urged U.S. 

EPA to develop options that would allow states to take credit for these retirements.

Commenters stated that EPA's broad application of the heat rate improvement assumption fails to 

consider planned retirements for coal units prior to 2020.

Commenters stated that EPA has relied on outdated information and reports to justify its 

proposed 6% (or 4%) heat rate improvement. Commenters stated that much of this data was 

collected prior to EPA's MATS rule and includes thousands of megawatts of generation that have 

either retired or are slated to retire in the near future. Commenters stated that units that are being 

retired are older plants that have the greatest potential for heat rate improvement; newer units do 

not and therefore, the average potential heat rate improvement targets may be artificially more 

burdensome by averaging units that are no longer operating. Commenters stated that further, 

EPA admits that its information is insufficient and that it is unaware of the efficiency of the 

current fleet - a critically important baseline if EPA is to establish the availability of percentages 

of reductions. 

Commenters stated that older power plants with higher heat rates and no longer considered 

economically viable have been retired by plant owners and that these retirements typically 

remove units with the most potential heat rate improvement from the fleet whereas units where 

investments have already been made to improve operations are less apt to be retired, but have 

less additional potential heat rate improvement. Commenters further stated that actual heat rate 

improvement achievable at any site is unit-specific, as shown in EPRI studies and that the 

maximum potential improvement depends on the condition and operation of the unit. 

Commenters stated that in addition, any fossil-fuel EGUs (coal-fired) that are planning to retire 

as a result of USEPA regulations (MATS, etc.) should be allowed to count towards compliance 

with the goals. Commenters stated that Michigan's largest utilities have already announced some 

closures of coal-fired EGUs and more are expected to be announced in the next couple years, 

resulting in substantial reductions in CO2 emissions from these to-be-retired coal plants.

Commenters stated that no improvements should be assumed for units that have firm 

commitments to retire or fuel-switch to natural gas before 2020. Commenters provided a 
433

summary of Alliant Energy's current announcements that should be excluded from the EPA's 

estimated Block 1 heat rate improvements.

Commenters stated that EPA projects that almost all of Florida's coal-fired capacity will retire as 

a result of the rule and assuming that to be the case, any heat rate improvement projects are 

completely moot.

Commenters stated that the 300 plus coal fired units that have or will retire in the 2010-2015 

timeframe generally represent the oldest, least efficient units within a utility fleet, and would 

typically be those units most likely to benefit from heat rate improvement projects. Commenters 

stated that when these units are removed from the coal-fired generation base, they are left with 

the most efficient and well-controlled units, so an additional across the board 6 percent heat rate 

improvement target is unrealistic for the remaining fleet. 

Commenters stated that coal units that are expected to retire soon could have distorted results 

from the bin analysis, because utilities are likely to have avoided costly maintenance measures 

on a unit used infrequently or scheduled for near-term retirement and once retired, these units 

obviously cannot apply HRI measures. Commenters stated that EPA performed a sensitivity 

analysis excluding units that have announced they will retire by 2016, but this group is a small 

fraction of the approximately 110 GW of coal units that EPA projects to retire between 2012 and 

2020.

Commenters stated that the U.S. is currently in the midst of a wave of coal plant retirements that 

could result in around 20 percent of the existing coal fleet being shut down. Commenters stated 

that Arch's experienced market analysis team estimates that nearly 60 gigawatts of coal-based 

capacity will be retired by the end of 2017 - a total that reflects already promulgated regulations 

such as the Mercury and Air Toxics Standards, and that assumes a fairly benign existing source 

standard for GHGs. Commenters stated that based on data from the Energy Information 

Administration (EIA), it does not appear as though other types of generating capacity will fill the 

void, at least not initially. Commenters stated that indeed, EIA estimates that only 14 new 

gigawatts of natural gas combined-cycle capacity will be added by the end of 2017 and thus, 

overall fossil fuel capacity will be reduced by approximately 46 gigawatts. Commenters stated 

that while it is certainly possible that new natural gas capacity could be built more rapidly than 

ETA currently projects, such a build-out would carry its own risks, e.g., pipeline deliverability 

challenges, increased price volatility, and potential supply shortfalls in critical end-use markets 

such as home heating.

Commenters stated that the anticipated retirement of 60 gigawatts of coal-based capacity within 

such a short period of time is unprecedented. Commenters stated that ETA data since 1949 

shows that prior to this decade there was only one year in which fossil fuel-based generating 

capacity declined. Commenters stated that it is also important to point out that the anticipated 

coal plant retirements are just getting underway. Commenters stated that they estimate that less 

than 20 gigawatts have been retired to date (since 2011), which means another 40 gigawatts or so 

will be taken offline in the next three to four years. Commenters stated that the closure of these 

units has placed and will continue to place substantial stress on the system. It is very difficult to 

predict how this substantial change in the composition of the grid's generation units will affect 

reliability and costs. 
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Commenters stated that in the State Agencies' comments, they argue that there is little incentive 

for upgrades to existing coal units, because they will have to be retired before the owners are 

able to recoup their capital investments. Commenters stated that they also argue that the TS 

Power Plant does not have much headroom to improve. Commenters stated that as laid out 

above, there is no need under the outlined goals for the TS Power Plant or North Valmy 

Generating Station to shut down in 2020 and NV Energy's planned retirement of North Valmy in 

2025 is not unreasonable and would not cause significant impacts to reliability or costs. 

Commenters stated that the reality is Nevada has already made the public policy decision to 

move away from coal by the passage of SB 123 in 2013 and NV Energy's retirement of coal 

EGUs in the implementation of that public policy decision will drive far greater reductions in 

carbon emissions than the heat rate improvements assumed by EPA in its development of 

Building Block 1 for Nevada. 

Commenters stated that EPA also attempts to look at the entire "existing" pool of coal fired units 

for heat rate improvement opportunities, however, these studies were completed prior to the 

significant round of coal fired plant retirements that have occurred in the last 2-5 years as a result 

of lower natural gas prices, increased generation from renewables, and costly control retrofits to 

meet new pollution standards. Commenters stated that the 300 plus coal fired units that have or 

will retire in the 2010-2015 timeframe generally represent the oldest, least efficient units within a 

utility fleet, and would typically be those units most likely to benefit from heat rate improvement 

projects. Commenters stated that when these units are removed from the coal-fired generation 

base, they are left with the most efficient and well-controlled units, so an additional across the 

board 6 percent heat rate improvement target is unrealistic for the remaining fleet. 

Commenters stated that PGE, the State of Oregon, local stakeholders, and the EPA made a 

binding, enforceable agreement to stop coal operations at Oregon's only coal-fired EGU, the 

Boardman Plant, on December 31, 2020, but not before. Commenters stated that this agreement 

was lauded as an historic and aggressive action to responsibly deal with climate change and that 

EPA was a necessary and indispensable party to this agreement, but the Clean Power Plan's 

application of the BSER to Oregon creates an interim goal that assumes Boardman ceases 

burning coal on January 1, 2020, one year before the current schedule. Commenters stated that 

EPA should amend the Clean Power Plan to avoid penalizing Oregon for developing and 

implementing a plan to end coal-burning at Boardman twenty years ahead of schedule despite no 

federal requirement to do so. Commenters stated that EPA can fix this issue by: i) applying a 

regulatory adjustment to account for coal plants that committed to enforceable retirement dates 

prior to the Clean Power Plan proposal; ii) modifying the glide path and interim goals to allow 

states to more gradually meet the final goal, or iii) allowing states to determine their own 

emission reduction trajectories to achieve the 2030 final goals.

Commenters stated that EPA forecasts retirements of specific generation units. Commenters 

stated that it is not clear how the retirement forecasts are generated, but this might be a modeling 

simplification to force reductions in emissions. Commenters stated that in any case, the CPP does 

not require any retirements and if a plant is required at peak, or if other plants or transmission is 

being maintained, the plant can remain in service, spending most of the year on standby and 

running when needed. Commenters stated that Nova Scotia Power, operating under provincial 

emissions caps for CO2, mercury, and other pollutants, has coal plants that shut down during the 

low load summer season and run at about 10% capacity factors over the course of the year.
435

Commenters stated that the errors in these analyses are straightforward. Commenters stated that 

when Akins referred to EPA's "2020 cornerstone assumptions," he apparently meant EPA's 

projected retirements, which are not required or fundamental to compliance. Commenters stated 

that he mentions only the capacity currently in the PJM queue, and not the additional central and 

distributed renewables that can be built within five years. Commenters stated that he does not 

mention the currently planned energy-efficiency programs (which PJM does not net from its load 

forecast) or expanded programs, but most importantly, he assumes that generators and utilities 

would retire plants required for reliability, which PJM has mechanisms to avoid.

Commenters stated that similarly, SPP started with the EPA's projected retirements by 2020 with 

the Plan (at slides 8 and 9), including the erroneous listing of Plum Point, and assumes that no 

new generation could be added in five years. Commenters stated that since many of the 

generators that EPA assumed would be retired by 2020 are already planned for retirement (e.g., 

one Northeastern and the equivalent of a Muskogee unit in Oklahoma, a Welsh unit in Texas) by 

2020, plans for replacing much of that capacity are underway. Commenters stated that in 

addition, SPP says it "used current load forecasts supplied by SPP members, currently planned 

generator retirements, currently planned new generator capacity with GIAs [generationinterconnection agencies], and EPA's assumed retirements" (at slide 14). Commenters stated that 

SPP appears to have made the following errors: 

• ignoring future energy-efficiency programs;

• ignoring any new generation that does not yet have a Generation Interconnection 

Agreement (including renewables earlier in the interconnection process) or does 

not require one (distributed generation); 

• counting both the planned SPP retirements and the EPA's retirements, which may 

double-count some retirements. For example, the EPA analysis assumes that 

Muskogee will retire, but not Mustang, while OG&E has decided to retire 

Mustang and convert Muskogee, to operate more like Mustang has. It appears that 

SPP has counted both the Muskogee and Mustang retirements.

Commenters stated that it is important to recall that the Plan does not require retirement of any 

capacity, and utilities will keep units available if they are required for reliability. Commenters 

stated that while a few coal units in a few places may need to operate at low capacity factors for 

a few years while transmission and renewables (and perhaps CCS and new nuclear) are 

completed. Commenters stated that many oil- and gas-fired steam plants operate as peakers, and 

their owners find ways to minimize further reduce costs, stretching out maintenance schedules, 

using the plant staff to perform maintenance on other units in the off-periods, and so on. 

Commenters stated that costs will be modest on a statewide basis. 

Commenters stated that the EPA's modeling of CPP compliance assumed retirement of a number 

of generating units.

Commenters stated that the gas-steam retirements in EPA's base case are quite sensible. 

Commenters stated that Harvey Couch did not generate any electricity in 2013, and Lake 

Catherine 3 operated in only two months (and not much even then). Commenters stated that 
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Entergy's 2012 Deactivation Study recommended retirement of both these units by 2016, 

regardless of carbon limits, and the units are listed as retired in the Entergy Statistical Report and 

Investor Guide 2013. Commenters stated that Lake Catherine 4 was apparently out of service for 

the first half of 2013, ran at about a 10% capacity factor when it was available, and is listed as a 

peaking plant in the 2013 Statistical Report. Commenters stated that in any case, whether these 

units are retired or continue to remain in standby and low-output operation makes little or no 

difference in Arkansas's compliance with the Plan.

Commenters stated that in the regional compliance case, EPA's modeling switches the fates of 

Lake Catherine 4 and the brand-new Plum Point plant. Commenters stated that this outcome is 

unlikely. Commenters stated that in contrast, White Bluff is likely to retire by 2020 or so, with or 

without the Plan. Commenters stated that in 2009, the commenters' analyses (unpublished) 

indicated that retrofitting White Bluff with all the control equipment necessary to comply with 

the Regional Haze Rule, maximum-achievable-control-technology rules, and other pending 

requirements was probably uneconomic, compared to purchasing and running underutilized gas 

plants, converting White Bluff to burn gas, or even building new gas combined cycle capacity. 

Commenters stated that commenters reached those conclusions with a forecast of gas prices 

reaching $10/MMBtu in 2020; gas price futures for 2020 are now about $4.50/MMBtu. 

Commenters stated that the Independence units are very similar to White Bluff in age, efficiency, 

operating costs, design and existing controls, and consequently their future is similarly doubtful. 

Commenters stated that one or both Independence units may stay in operation, depending on 

local reliability requirements and carbon allowance prices, but they will probably be economic 

only during summer peak periods and (depending on gas prices) perhaps the winter.

Commenters stated that the Virginia SCC Staff comments to EPA similarly assert (at 14) "that 

the Proposed Regulation will cause 2,851 MW of generation retirements in the Dominion 

transmission zone before 2020." Commenters stated that the VSCC Staff relied on a draft 

analysis of state-based compliance from April 2014, rather than the final analysis from June 

2014. Commenters stated that the EPA's April 2014 estimate of 2020 retirements in the 

Dominion zone in the Base Case without the CPP was 1,923 MW, so EPA was estimating only 

928 MW of additional retirements due to the Plan. 

Commenters stated that LUS recognizes that the IPM model has slated RPS-2 for retirement and, 

if that is the case, LUS will have no flexibility to meet any of its CO2 emission reduction 

obligations under Building Block 1. Commenters stated that thus, it is very likely that more 

reductions would have to be recovered under the remaining building blocks. Commenters stated 

that furthermore, even if RPS-2 were to remain in service, it would most likely have to be 

dispatched downward to accommodate increased NGCC dispatch, further increasing unit heat 

rate and again limiting any flexibility supposedly offered under Building Block 1. 

Commenters stated that EPA did not consider the remaining lifetime of units, as required by the 

CAA, when proposing building block 1. Commenters stated that in doing so, building block 1 

should not apply to any coal-fired EGUs that will be retired prior to 2020. Commenters stated 

that excluding retiring coal-fired units from this building block acknowledges that further 

investment is neither prudent nor cost-effective, other than for maintaining the EGU until it is 

retired. Commenters stated that this is particularly true in cases where the EGU has already been 

slated for retirement. Commenters stated that Wisconsin EGUs that will be retired between 2012 
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and 2020 are listed in Table 2 (titled: “Coal-fired EGUs to be retired by 2020”Commenters 

stated that in addition to removing these EGUs from building block 1 calculations, the final rule 

should allow states to adjust goals to exclude any other EGUs retired by 2020. 

Commenters stated that EPA should exclude coal-fired EGUs that will be retired before 2020 in 

calculating the heat rate improvement target for each state. 

Commenters stated that recognizing that economic calculations vary from plant to plant, UCS 

agrees with the EPA that a six percent HRI across the coal fleet is cost effective. Commenters 

stated that moreover, UCS emphasizes that retirement of older, less efficient, and dirtier coal 

plants will help states achieve their targets. Commenters stated that the average age of the 

nation's coal fleet is 38 years, compared to an average expected lifetime of 30 years and by 2013, 

24 GW of coal-fired generation, with an average age of 51 years, had already been announced 

for retirement. Commenters stated that by 2020, the start of the compliance period, more existing 

plants will have outlasted their expected lifetimes, thus for some EGUs, investments in HRI may 

not make sense because of the age of the facility. Commenters stated that for others, however, 

HRI may make sense and may even extend their useful lifetimes. Commenters stated that States 

will have to consider their own individual generating fleets to determine the most cost-effective 

way to meet their targets. Commenters stated that case law affirms that reduced usage of covered 

entities (including retirement) is consistent with complying with air pollution regulations. 

Commenters stated that States have been given maximum flexibility to comply with their 

individual state targets, but as noted by the RGGI states, that flexibility should not extend to 

setting the targets. 

Commenters stated that many stakeholders have and will continue to comment on the 

achievability of a 6 percent HRI, especially in the context of whether it is appropriate to apply 

such an assumption uniformly given HRIs accomplished by some coal-fired EGUs prior to the 

2012 baseline and given the remaining useful life of such plants. Commenters stated that 

specifically, in a November 2013 resolution with regard to this proposal, the National 

Association of Regulatory Utility Commissioners ("NARUC") noted that Section 111(d)(1)(B) 

requires the Administrator to permit a state, in applying such standards of performance, "to take 

into consideration, among other factors, the remaining useful life of the existing source to which 

such standard applies." Commenters stated that therefore, to the extent that the 6 percent HRI 

assumption is perceived as presenting a near-term challenge with respect to the achievability of 

individual state goals, Connecticut reiterates the suggestions of the RGGI states with respect to 

several important factors that show that this perception is incorrect. Commenters stated that first, 

the range of relative in-service dates of the nation's coal fleet indicates that many of these units 

may face potential retirement in the coming decade due to age alone, thereby resulting in 

significant emission reductions during the 111(d) compliance timeframe and second, should 

these aging coal units elect to invest in HRI efficiency measures as part of a larger strategy for 

emission reductions in a state, such investments will also serve to increase the lifespan of these 

units. 

Comment 53: Comments regarding unit specific versus national fleet-wide goal. 
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Response 53: For the EPA’s response to these comments, see sections V.A and V.C of the final 

rule preamble of the CPP and Chapter 2 of the GHG Mitigation Measures TSD supporting the 

final CPP. As discussed in those documents, the EPA’s heat rate assessment under building 

block 1 is part of a broader process of determining the BSER, and does not establish a unitspecific requirement to improve heat rate. States, in turn, are not required to establish emission 

standards for sources to implement the BSER. Accordingly, the EPA’s assessment of potential 

heat rate improvement reasonably identifies the average capabilities of large populations of 

EGUs, rather than what individual EGUs are capable of achieving. Additionally, as discussed in 

the above-referenced documents, the final rule assesses potential heat rate improvement on a 

regional basis.

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

Commenters stated that EPRI's research neither proves nor disproves that a 6% heat rate 

improvement could be attained in any given operating power plant. Commenters stated that 

however, EPRI's research [EPRI Report 3002003457, "Range and Applicability of Heat Rate 

Improvements", 2014 for a summary of recent research] does show that (i) heat rate 

improvements are not necessarily additive, (ii) they are very sensitive to operational issues -

cycling, fuel type, etc., and (iii) they are very dependent on the type of equipment installed such 

as emissions controls. Commenters stated that EPRI research has not yet developed data on the 

sustainability of most of the heat rate improvements discussed in these comments. Commenters 

stated that EPRI research identified potential unit-specific, heat rate improvements in the range 

of 0.5 - 5% on a net basis. Commenters stated that however, the numerical values for separate 

heat rate improvements may not be additive. Commenters stated they also may not be achievable 

or justifiable at every coal-fired plant. Commenters stated that in many cases, staff at many well 

performing plants have been proactive and already implemented some of the possible 

improvements (e.g., steam turbine upgrades, remote monitoring centers, etc.), thus reducing the 

potential for further maximum heat-rate improvement. Commenters stated that estimates of heat 

rate improvements at existing coal EGUs are very dependent on the individual unit 

characteristics (age, design, maintenance history, type of coal, etc.) and are difficult to apply a 

national fleet-wide heat rate goal. 

Commenters stated that EPA's uniform assumption that these levels of heat rate improvement are 

feasible and achievable nationwide at all affected coal units is not technically sound. 

Commenters stated that utility companies, including Alliant Energy, already complete many of 

the suggested heat rate improvement work practices and equipment replacement projects 

suggested by EPA. Commenters stated that utilities are incented to complete these projects in 

order to provide for affordable, reliable power and the benefit of reducing the CO2 emission rate. 

Commenters stated that efficient operation of coal units is necessary to reduce fuel costs and 

preventative maintenance is important to avoid unforeseen shutdown due to equipment 

malfunction or failures.

Commenters stated that EPA states it has independently analyzed the improvements in gross heat 

rate that can be achieved by reducing variability in gross heat rate through adoption of best 

practices for operation and maintenance at each of the twelve coal-fired EGUs in Arizona. 

Commenters stated that however, EPA did not take these unit-specific analyses into account in 

reaching a conclusion regarding the improvements in gross heat rate that could be achieved by 
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reducing variability in gross heat rate through adoption of best practices for operation and 

maintenance at the coal-fired EGUs in Arizona. Commenters stated that instead, EPA based its 

assumption of what is achievable for the coal-fired EGUs in Arizona on the results of its analysis 

for a larger "study population" of 884 coal- and petroleum coke-fired EGUs and thus, EPA's 

results are indicative only of the improvements in gross heat rate which may be achievable for 

the "study population" as a whole; they did not consider what unit-specific improvements have 

already been completed or which specific improvements might be available at the coal-fired 

EGUs in Arizona. 

Commenters stated that EPA mistakenly concludes that a 2009 study conducted by Sargent & 

Lundy supports the 6% across the board heat rate improvement. Commenters stated that Sargent 

& Lundy explicitly rejected EPA's findings and stated that "Sargent & Lundy's 2009 Report does 

not conclude that any individual coal-fired EGU or any aggregation of coal-fired EGUs can 

achieve 6% [heat rate improvement] or any broad target, as estimated by the EPA." Commenters 

stated that EPA's analysis neglects to account for numerous factors that impact EGUs' process 

efficiency and NERC identified these factors as: (1) subcritical versus supercritical boiler 

designs; (2) fluidized bed combustion, integrated gasification combined-cycle, and pulverized 

coal; (3) unit size and age; and (4) coal quality variations in moisture and ash. Commenters 

stated that the same solution cannot be applies to all units as each facility is different and to 

obtain reliable information on achievable heat rate improvements, each unit should be evaluated 

individually to determine what cost effective improvements are available at each unit. 

Commenters stated that because of the variation among units, requiring a universal 6% heat rate 

improvement is unrealistic. 

Commenters stated that the most significant and fatal flaw with EPA's methodology is that it 

assumes all EGUs can achieve the same level of HRI irrespective of their unique characteristics. 

Commenters stated that the absurdity of this approach can be illustrated by a simple analogy 

involving jogging "suppose we take a group of joggers and examine the variability of their times 

for running one mile. We subsequently conclude that the existence of variability in jogging times 

demonstrates that the jogging times for all joggers can improve, thus leading us to establish a 

goal of reducing each jogger's time by 4%. Additionally, we examine the run time for fifteen 

joggers that have undertaken conditioning programs and determined that such programs resulted 

in improved run times for two of the joggers by approximately 2%." Commenters stated that 

using EPA's methodology, the entire group of joggers would be expected to reduce their run 

times by a total of 6%; however, not every jogger will be capable of achieving a 6% reduction in 

his or her run time. Commenters stated that based on each jogger's individual circumstances, one 

jogger may be able to reduce his or her run time by 10% or 15%, while another may already be 

near the limit of what his or her body can achieve. Commenters stated that applying such a onesize-fits-all standard to circumstances that are heavily dependent on individual characteristics 

produces absurd results and sets the high achievers up for failure and likewise, EPA's use of an 

across-the-board, one-size-fits-all 6% HRI without regard to what is technically achievable at a 

given EGU is arbitrary and should not be included in the Final Rule. 

Commenters stated that the same solution cannot be applied to all units as each facility is 

different and to obtain reliable information on achievable heat rate improvements, each unit 

should be evaluated individually to determine what cost effective improvements are available at 
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each unit. Commenters stated that because of the variation among units, requiring a universal 6% 

heat rate improvement is unrealistic. 

Commenters stated that EPA has proposed a 6% increase in coal plant heat rate improvement 

(fossil fuel efficiency) based on a national assessment of the capabilities of the industry to 

improve plant efficiency (~2%) and to improve operational efficiency (~4%). Commenters 

stated however EPA's assessment of national capabilities does not appear to be sufficiently 

rigorous or granular to conclude that such a reduction is indeed attainable and EPA fails to 

provide data to support the case that all coal plants in the country are capable of this level of 

improvement.

Commenters stated that the 6 percent emission rate reduction goal-setting for coal units is 

applied across the board, but it's not achievable on all units.

Commenters stated that for Building Block 1, in that the heat rate improvements suggested by 

the EPA are not attainable on a fleet-wide basis, or for certain circumstances where it is possible, 

could ever be sustainable.

Commenters stated that as with other building blocks, blanket goal setting based on national 

averages does not work for Ohio's coal-fired fleet, which is both efficient and well controlled. 

Commenters strongly urged U.S. EPA to examine net generation and heat rates, with 

consideration given to the environmentally favorable outcomes of well-controlled coal-fired 

generation.

Commenters believed that it is inappropriate for EPA to apply a nationally assumed HRI to each 

state, given the unknown technical feasibility of implementing HRI at the proposed levels across 

affected coal EGUs in Tennessee. Commenters stated further that there are various other 

considerations EPA ignored or failed to address with regard to achieving the 6 percent HRI such 

as assuming an average HRI of 6 percent to be achievable across the nation's entire fleet of coalfired EGUs. Commenters stated this standard of HRI is then applied to each state, absent 

consideration of unit-level information, including its remaining useful life and without full 

consideration of the drivers of net generating efficiency.

Commenters stated that EPA's belief that Companies can achieve 6% more energy (heat rate 

improvement) out of existing coal-fired power plants and whether the EPA is overestimating the 

amount of additional energy efficiency gains states can achieve is dubious. Commenters stated 

that real concern is that EPA's assumed improvements will most likely not be realized across the 

entire generation fleet since many plant efficiencies have already been realized and economic 

heat rate improvements have been achieved.

Commenters stated that EPA uses a breakeven analysis to show that if a fleet-wide heat rate 

improvement of 6% in coal plants is technically feasible, then by default, it is economic. 

Commenters stated that moreover, the 6% improvement in heat rate is a national average that is 

not specific to Kansas EGUs. Commenters stated they assert that any achievable heat rate 

improvements are specific to each coal-fired unit and cannot be generalized through a national 

average. Commenters added that because the EPA has not adequately demonstrated that heat rate 
441

improvements can be made to any specific EGUs in Kansas, they have set the heat rate 

improvement increase in efficiency to zero percent for Kansas's affected EGUs. 

Commenters stated that EPA has become so distracted by the notion that it can fundamentally 

change the electricity system in all 50 states, or at least 49 states, that it still hasn't done the 

technical work that will be necessary to develop legally sound regulations to reduce carbon 

emissions from existing power plants. Commenters stated that unfortunately there's not that kind 

of analysis in this rule, even with building block no. 1. Commenters encouraged EPA to do at the 

very least, is to actually do the technical work that is necessary to determine for different sizes 

and types of plants, what is the carbon emission rate that can reasonably be achieved as opposed 

to simply assuming that everybody can achieve a six percent reduction.

Commenters stated that realistically, the heat rate improvement that is actually achievable is unitspecific, and depends on site-specific factors like current operating practices and past efficiency 

upgrades and that a six percent heat rate improvement is not achievable for coal-fired EGUs as a 

category. 

Commenters stated that EPA proposes a Block 1 heat rate improvement target of six percent for 

every major U.S. coal plant but that however, the ability of a plant owner or operator to improve 

the efficiency of a given unit is entirely dependent on unit-specific factors such as unit age, 

equipment condition, prior efficiency projects, current emissions controls and other factors. 

Commenters further stated that EPA's approach to Block 1 assumes one level of heat rate 

improvement is universally achievable across all U.S. coal plans, and ignores the wide variations 

in the potential for efficiency improvements, and a better approach is to allow states to set their 

own targets based on unit-specific information that accounts for differences in achievable heat 

rate improvements. 

Commenters stated that the benefits and cost of potential heat rate improving actions are highly 

variable and depend on the specifics of any one site and that EPA's projection of heat rate 

improvements of 6% with an alternative target of 4% is not applicable to the entire U.S. 

generating fleet, over a long-term operating period, due to site-by-site differences, the actions 

taken by owners as part of regular maintenance and normal operating procedures, and the 

temporal variation of the payoff reduce the system-wide, long-term target.

Commenters stated that EPA should also consider whether its conclusion that "a U.S. coal-fired 

EGU fleet-wide improvement ranging from 9% to 15% is theoretically possible," TSD, p. 2-13, 

is a firm ground for the target it proposes. Commenters stated that for the Wyoming coal fleet, 

Commenters saw no evidence of an ample harvest of heat rate improvements that the utility 

industry has overlooked or ignored. Commenters stated that many of the S&L recommendations 

do not apply to Wyoming EGUs as they are designed and/or operated. Commenters stated that 

some problems identified by S&L do not in fact occur and that in many instances, the 

improvement value associated with the measure is at the low end of S&L's scale. Commenters 

stated that in most instances, the actual implementation of these measures is most wisely done 

consistent with a maintenance schedule that supports system reliability and that it is only 

sensible, and more fair, to consider the practical realities of the state fleet when setting a binding 

target. Commenters stated that it is not sensible, and not fair, to set a binding target based on 
442

averages for the national fleet; this is a large and diverse country, a reality which should be the 

foundation of any lasting effort to regulate greenhouse gas emissions from existing EGUs.

Commenters stated that the Wyoming Public Service Commission and the Wyoming Department 

of Environmental Quality consulted with the operators of Wyoming's coal fleet and asked these 

operators to ascertain what heat rate improvements were feasible, and more specifically, to 

review the applicability of available technologies listed by Sargent & Lundy - all of them, not 

just the technologies highlighted by EPA. Commenters stated that the reason for the disparity 

between EPA's 6% estimate and the commenters' 2% estimate is EPA's flawed rationale for the 

4% best practices improvement. Commenters stated that EPA's logic rests on improvements to 

the national fleet of coal-fired EGUs, rather than the much smaller fleet that will be regulated by 

each state. Commenters stated that the smaller state fleet does not share the same characteristics 

as the national fleet and that EPA nonetheless reasons that "if each unit achieved heat rate 

performance equal to its best three-year moving average [out of eleven years of data], the study 

population as a whole would post a 3.9% heat rate improvement". Commenters stated that EPA

believes that the minimum three-year moving average heat rate is a reasonable target for the 

improvement potential from applying best practices. TSD, p. 2-34. Commenters stated that while 

"[t]he heat rate improvement for the study population is derived from the performance of each 

individual EGU as compared to its own record," TSD, p. 2-31, the proposed rule does not 

consider each individual plant or the statewide fleet of plants, but instead computes a single 

national target based on a single national average. 

Commenters stated that this creates a severe prejudice for a state with a fleet of EGUs largely or 

exclusively in the first and second quartiles. Commenters stated that if the plants are already 

within a limited range of variability, EPA cannot reasonably require a percentage improvement 

based on the entire national fleet which, by definition, is characterized by substantially greater 

variability. Commenters stated that at the very least, EPA's state targets should begin with 

disclosure of the results of its calculations for individual plants or units, including the three-year 

moving average of each plant or unit, then rank order each plant or unit. Commenters stated that 

those results should be provided with sufficient context to consider what a fair target for 

individual plants or units might be, and with that, what a fair composite target for a state might 

be. Commenters stated that EPA's approach to Block 1, which was to simply adjust the combined 

state-level emissions rate for all state coal-fired EGUs by 6%, is arbitrary. 

Commenters stated that with specific information about where these plants fall on EPA's 

continuum, the state would be in a position to address specific issues that might warrant 

adjustment in a proposed heat rate for an EGU, and for the state fleet as a whole. Commenters 

stated that the EPA should be considering just such a process and that the consequences for the 

state and the utility are too dire to rush to judgment on an erroneous target, as they will discuss in 

further detail below in the conclusion section of these comments. 

Commenters stated that EPA's analysis is nationwide and generic, and so does not account for 

the likelihood that certain states will have fewer units that fit EPA's description than the national 

average and the goals for those states, therefore, will be arbitrarily strict. 

Commenters stated that EPA's generic conclusion that the coal fleet as a whole can improve 

efficiency by 6 percent fails to recognize that the potential for efficiency improvements is highly 
443

unit specific. Commenters stated that the National Coal Council a federal advisory committee 

reporting to the U.S. Secretary of Energy, recently reported that in some cases, the opportunity 

[for efficiency improvements] will be negligible because the unit either is already operating in a 

highly efficient mode with some or all of the improvements in place or because the 

implementation of potential improvements is not cost-effective and/or technically feasible and as

such, the degree of efficiency improvement possible at a given unit is highly site-specific, and 

may depend on the design of the unit, current maintenance procedures, whether the unit operates 

as base load or cycling, the type of coal used by the unit, system economics and the economics of 

the specific measure and the configuration of the unit. Commenters stated that even the location 

of a unit is relevant to efficiency because plant efficiency is sensitive to ambient temperature and 

atmospheric pressure (elevation). Commenters included the document: "National Coal Council, 

"Reliable & Resilient, The Value of Our Existing Coal Fleet" as an attachment (Attachment 

Number A8). This document is an "assessment of measures to improve reliability and efficiency 

while reducing emissions", conducted by the National Coal Council. Commenters stated that 

EPRI has extensively studied the possibility of improving heat rate efficiency at coal generators 

and it concluded that "[e]stimates of heat rate improvements at existing coal EGUs are very 

dependent on the individual unit characteristics (age, design, maintenance history, type of coal, 

etc.) and are difficult to apply a national fleet-wide heat rate goal." Commenters stated that EPRI 

further warns that the opportunity for heat rate improvements is diminishing as the older, less 

efficient coal plants either have retired or are retiring. Commenters stated that NERC echoed 

these observations, noting that "[m]ultiple incentives are in place to operate units at peak 

efficiency, and periodic turbine overhauls are already a best practice. Commenters stated that 

site-specific engineering analyses would be required to determine any remaining opportunities 

for economic heat rate improvement measures." Commenters stated that similarly, a detailed 

review of possible heat rate improvements by industry experts concluded that "the payoff from 

any given heat rate improvement is highly site-specific." 

Commenters stated that EPA expects the additional 2 percent improvement in heat rate to come 

from equipment upgrades, selected from a list provided by the aforementioned Sargent & Lundy 

study. Commenters stated that the agency rightly recognizes that "some EGUs may have already 

implemented some of these upgrades." Commenters stated that however, the proposed rule 

assumes without justification that roughly half of the equipment upgrades in question remain and 

are thus realizable at EGUs across the country and EPA presents no data to support this 

assertion. Commenters stated that furthermore, the equipment profile of coal-fired EGUs in 

Indiana may vary substantially from that of the average U.S. unit. EPA has yet to conduct any 

subnational analysis of the potential for plant upgrades and as such, the 2 percent improvement 

in heat rate Indiana plant operators are supposed to achieve at their coal-fired units is 

unsubstantiated and should be reconsidered. Commenters stated that instead, EPA should 

conduct a plant-specific analysis at each existing source to render an appraisal of potential 

improvements that is more sensitive to real present-day circumstances in Indiana. 

Commenters stated that EPA's erroneous 6 percent figure is apparently based on its incorrect 

assumption that all the heat rate reduction strategies discussed in the 2009 Report can be applied 

at all coal-fired units. Commenters stated that to the contrary, "[a]ll efficiency improving 

measures are unit and site-specific and will not always be technically and/or economically 

feasible." Commenters stated that therefore, the 2009 Report does not support EPA's 6 percent 

figure.
444

Commenters stated that heat rate is not a constant value and compared it to the fuel efficiency 

rating of an automobile. Commenters further stated that variability in operations or operating at 

less than "full load" have similar impacts on a generating unit. Commenters provided a graph 

showing the relationship of unit load to heat rate for a typical supercritical unit - as a unit cycles 

loads up and down, or runs at minimum loads for which the unit was not optimally designed, 

heat rate increases significantly. Commenters further pointed to process and equipment design, 

maintenance and cleanliness of critical components, changes in weather conditions, changes in 

fuel energy content or fuel delivery, changes in process water and cooling water temperatures, 

and other factors that can impact the heat rate. Commenters stated that although EPA attempted 

to identify operational practices and equipment upgrades that affect heat rate performance, the 

agency failed to fully consider the range of variables that drive performance, incorrectly 

identified the level of improved performance associated with the variables considered, and 

erroneously concluded that all existing coal units could achieve the same level of improvement 

from implementing a common set of measures. Commenters stated that EPA must broaden its 

analysis of heat rate improvement opportunities to more accurately evaluate the range of unit 

specific factors that impact performance.

Commenters stated that heat rate improvements are site specific and that each power plant is 

unique and is designed for an optimum heat rate at the time of its design/construction. 

Commenters described that over the course of its life each plant has undergone physical (e.g., 

repairs, cooling water system), operational (e.g., fuel composition changes), and regulatory (e.g., 

installation of pollution control equipment, grid dispatch changes) that has altered its original 

optimum heat rate. Commenters stated that some of the plants may be able to improve their heat 

rate to the levels suggested by the EPA while others may not be able to do so. Commenters 

stated that as the National Coal Council indicated in its report, many of the heat rate 

improvements "are not a one-size fits all package of solutions" and as the report indicates some 

plants may not see any improvements as they may be operating in most efficient mode or 

changes over the years (e.g., fuel composition) may not allow any further improvement. 

Commenters stated that in U.S. EPA's GHG Abatement Measures TSD it is stated that the gross 

heat rate of the nationwide study group is 9,754 BTU/kW-h and following U.S. EPA's goal 

setting procedure, a 6% reduction in this value would yield a reduced nationwide gross heat rate 

of 9,169 BTU/kW-h. Commenters stated that their analysis demonstrated that the 2001 to 2012 

average gross heat rate of Ohio's coal-fired fleet is 9,788 BTU/kW-h and accounting for 

shutdowns due to the MATS rule, Ohio's remaining coal-fired fleet would have a gross heat rate 

of 9,287 BTU/kW-h. Commenters stated that this calls into question whether Ohio's coal-fired 

EGU fleet could achieve a further 6% reduction, when U.S. EPA's analysis yields a similar value 

of 9,169 BTU/kW-h and furthermore, given the variability of heat rates, it is likely that in some 

future years, Ohio's coal-fired fleet could potentially meet or exceed U.S. EPA's goal. 

Commenters stated that Ohio EPA recognizes that some units may be able to take some steps to 

increase heat rates marginally and does not believe that Ohio's post-MATS-compliance fleet, 

which will continue to operate in a competitive market, will be able to realize a further 6% 

reduction as envisioned by U.S. EPA. Commenters stated that they also wished to emphasize, as 

Sargent & Lundy also emphasizes, that "installation of additional pollution controls such as that 

required by regulations including BART, MATS, etc. will decrease the heat rate efficiency of 

any unit as compared to its heat rate efficiency before the installation." 
445

Commenters stated that again, a blanket, nationwide approach to setting the BSER is not 

appropriate for all units, and the results of their analysis further reinforces the position that any 

HRI goals should be based on a unit-by-unit analysis of past and potential future HRI projects. 

Commenters stated that more robust analyses of the potential improvements in heat rate of coalfired EGUs have been performed by agencies within the federal government that have particular 

expertise in efficiency and reliability of fossil fuel-fired EGUs. Commenters stated that EPA has 

overlooked this work in deriving its own conclusions regarding heat rate improvements under 

Building Block 1, for example, a Department of Energy (DOE) analysis published in 2014 

included the following findings:

• As these results show, the potential reduction in emissions (in percent terms) is greatest 

when the base plant (before retrofit) is less efficient. Commenters stated this is a 

recurring theme throughout the analysis, and is intuitive: when efficiency improvements 

are performed at an existing coal unit, there is greater potential for improvement at a unit 

that operates less efficiently to begin with, than at a newer unit with an already-low heat 

rate.

• These results illustrate that a "one-size fits all" solution does not exist when it comes to 

power plant retrofits, and that some retrofits may not make sense for certain plants, such 

as pulverizer upgrade for Plant B. Instead, utilities are likely to weigh their options based 

on the expected plant life, anticipated fuel costs, and other such factors - such as 

familiarity with a technology - before making the decision to invest in capital 

improvements.

Commenters stated that the S&L report makes no assertion of what fraction of the national coal 

unit fleet would actually be able to achieve specific improvement levels, however, the preamble 

jumps to an unsubstantiated conclusion that "implementation of the full subset of appropriate 

opportunities at a single EGU could be expected to result in an aggregate heat rate improvement 

of approximately four percent." Commenters stated that without substantiation, the preamble 

then, for state goal purposes, arbitrarily "estimates" that half of the fleet would have the full (4%) 

"equipment upgrade opportunity" - and selects a 2% improvement as a goal basis. 

Commenters stated that further, these cited improvements were determined on an industry-wide 

aggregate basis and therefore, they apply well to some individual generating units and not so 

well to others. Commenters stated that it is inappropriate to apply measures determined in 

aggregate to individual units, especially when the information is available to determine what 

improvements are achievable for each. 

Commenters stated that in establishing its targets for coal generation heat rate improvements, 

EPA repeatedly highlights the range of practices, technologies, and measures adopted by the 

various EGU's that make up the nation's coal generation fleet. Commenters stated that EPA's 

finding of technical feasibility relies on fleet-wide averages, recognizing that "some EGU's may 

have already implemented some upgrades," and best practices associated with heat rate 

improvements. Commenters stated that in so doing, EPA declines to set plant-specific targets. 

Commenters stated that in New York, attainment of EPA's targets is based on the existing 

technology and practices at a small cohort of plants. Commenters stated that only seven coal-
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fired plants operated in New York in 2012, for a total nameplate capacity of roughly 1,350 MW. 

Commenters stated that since that time, one plant has retired, a second co-fires natural gas, and a 

third is being closed and re-powered to burn natural gas. Commenters stated that two of the 

remaining plants are required to operate under reliability-must-run orders. Commenters stated 

that this calls into question the technical feasibility using a "fleet-wide average" to implement the 

draft rule's targets. Commenters stated that to resolve this technical feasibility concern resulting 

from "fleet-wide" assumptions being applied to a small cohort of units, they recommend that 

EPA consider an incremental approach to Building Block #1 so that there would be no 

reductions associated with coal plant heat rate improvements for states that generated less than 

roughly 10 percent of their total annual energy from coal as of the end of 2012. Commenters 

stated that such an incremental approach could be applied fairly across all States and would 

support EPA's intention to avoid setting emission standards on a plant-by-plant basis. 

Commenters stated that EPA has determined in some cases an efficiency improvement of 4-6 

percent is achievable and automatically assumed that such improvements can be made at all 

facilities. Commenters stated that however, EPA should be aware that opportunities to improve 

heat rate are determined at the unit level. Commenters stated that factors such as age, basic 

design, location, fuel, type of service and many others dictate the degree to which EGUs can 

improve efficiency and to assume that all units within Virginia can achieve enough efficiency 

improvement to meet this goal is faulty. Commenters stated that this highlights an area that EPA 

must allow States, who have a better understanding of these factors, the flexibility to set such 

targets. Commenters stated that further, since it is unlikely that Virginia's EGUs would be able to 

meet EPA's proposed heat rate improvement, in its Section 111 (d) plan, Virginia will be forced 

to mandate further reductions within other "building blocks" that are equally or even more 

challenging.

Commenters stated that EPA should determine heat rate improvement on a state-by-state basis 

that accounts for the technical and economic feasibility of improvement for each affected unit 

(bottom-up approach) rather than assuming a percentage based on national averages. 

Commenters stated that heat rates are dependent on parameters such as humidity, elevation and 

temperature and the same type of unit operating in the Northeast will have a very different heat 

rate from one operating in the Southwest due to the differences in elevation and climate, even if 

operation and maintenance are similar. Commenters stated that further, a lack of available water 

can reduce heat rate in that dry cooling is less efficient than wet cooling. Commenters stated that 

some coal-fired steam generators in New Mexico have water restrictions imposed by the federal 

government due to international compacts. 

Commenters stated that Building Block 1 is fatally flawed and EPA's emission reduction targets 

for Block 1 are unrealistic and unsupported by any administrative record put forward to date. 

Commenters stated that there is no precedent or record basis for suggesting that emission 

reductions of 6 percent are achievable by any source, let alone by all existing sources across-theboard and the 6 percent assumption cannot be squared with the existing landscape of utility 

assets. Commenters stated that in compliance with other regulatory efforts, many existing 

facilities have already made substantial investments in emission reductions, as Xcel and 

SMMPA have done with Sherco 3 as discussed above. Commenters stated that there is scant 

evidence to suggest that these facilities can wrest additional reductions from further measures 

and moreover, there is no administrative record to support the efficacy of such efforts, or their 
447

cost-effectiveness when placed in the context of the remaining life of a given facility. 

Commenters stated that it is precisely this unit-by-unit assessment that the Clean Air Act requires 

and that EPA's Proposed Rule abandons. 

Commenters stated that the EPA assumes the industry can improve heat rate by 6% over the 

entire coal fired power plant fleet. Commenters stated that although there may be an isolated 

generating station that can accomplish that goal they believe it is the exception rather than the 

rule. Commenters stated specific targets should be set on each unit's specific characteristics and 

credit given based on past improvements. 

Commenters stated that since it is recognized that each EGU is unique as to how much HRI can 

actually be realized, commenters recommended that the EPA allow, and specify the manner in 

which each affected EGU should, conduct a heat rate improvement audit. Commenters stated the 

results of these unit specific audits would serve as the "goal" for the degree of heat rate 

improvement which could be achieved by that EGU, and would be included in the state's plan as 

such. 

Commenters stated that the flawed methods used by the EPA have resulted in the Agency 

assigning an unachievable 6 percent HRI assumption for Building Block 1. Commenters stated 

that in addition to the flawed methodology, the EPA has only provided assumptions as to what 

HRIs may already have been implemented by coal-fired EGUs rather than conducting and 

presenting the results of a thorough analysis that looks at each individual unit. Commenters 

stated that there are also several other serious oversights in the EPA evaluation which would 

greatly affect the calculation of any HRI target. 

Commenters stated that more importantly, however, potential heat rate improvements to existing 

facilities depend entirely on site-specific issues, which EPA did not evaluate, rather instead, EPA 

relied on a study that examined a wide range of heat rate improvements that may be possible 

across coal facilities in a range of types and sizes. Commenters stated that certainly, not every 

investment is applicable to all units, but should be considered in context with facility design, 

operating conditions, age, maintenance status, etc. Commenters stated that it is also important 

that EPA recognize that heat rate improvements are not one-time investments, but that each 

improvement degrades over time and with use and assuming 6 percent improvement across the 

board does not reflect a realistic understanding of facility operations. 

Commenters stated that rather than applying a blanket 6 percent assumption for heat rate 

improvements to all coal-fired EGU's that may be impossible to achieve, IPA urges the EPA to 

compare historic values to best achievable heat rate by individual EGU in the computation of 

heat rate improvement goals under building block 1. 

Commenters stated that San Miguel requests EPA to delete Building Block #1. Commenters 

requested to allow (states) evaluation of heat rate improvements on a unit-by-unit basis as 

prescribed by section 111(d) and stipulate that improvements will not trigger a New Source 

Review. 

Commenters stated that a more careful analysis of the availability of heat rate improvements 

suggests that applying a blanket average percentage is improper; instead, the amount of 
448

improvements available must be determined on a far more facility-specific basis. Commenters 

stated that for those facilities for which equipment upgrades make economic sense, such facilities 

likely have already made such improvements, thereby reducing the amount of further heat rate 

reductions that can be attained and for other facilities, however, the same degree of equipment 

upgrades may not be technologically feasible or cost-effective. Commenters stated that as a

result, BSER building block 1 represents a flawed determination of the magnitude of heat rate 

improvements that can be achieved by a substantial subset of the coal fleet. 

Commenters stated that EPA's assumptions on heat rate improvements for Building Block 1 are 

invalid because EPA erroneously assumed that a national average heat rate improvement would 

be appropriate to impose upon states with diverse coal fleets and grossly underestimated the cost 

of heat rate improvements at existing coal-fired power plants.

Commenters stated that EPA did not provide justification for why a 6% reduction is the 

appropriate target for all existing coal-fired power plants within the range of potential heat rate 

reductions at model plants. Commenters stated that use of a single study and application of its 

general conclusions to every coal-fired power plant in the country, irrespective of age, class, 

type, fuel, maintenance history, upgrades or any other relevant factors is, on its face, arbitrary 

and capricious. 

Commenters stated that as EPA notes in the "GHG Abatement Measures" technical support 

document, the cost of, and fleet-wide potential for, adopting HRIs is influenced by a diverse set 

of factors, many of which are site-specific. Commenters stated that first, technology and BMPs 

in this space may evolve during the compliance period and second, there is variability in what 

may be achieved at any given unit, and there is certainly variability in what has occurred at a 

specific unit historically. Commenters stated that under the proposed guidelines, forwardthinking utilities that have taken the initiative to improve technology and promote BMPs at their 

facilities would be required to do more at a higher cost. Commenters stated that rather than 

applying a uniform HRI level across the nation's fleet of affected units, states should be allowed 

to apply a performance standard in this category based on unit-specific factors and costs, 

including remaining useful life and previously-upgraded equipment, the effect of added 

environmental controls, and other factors, such as consideration of variable dispatch effects on 

efficiency that are specific to EGUs within each state and region. 

Commenters stated that the proposed guidelines set a uniform rate of 6 percent on a nationwide 

basis without discounting or looking for what percentage of reductions may have already been 

accomplished at any specific unit and without considering improvements and other types of 

environmental controls that may have been implemented in recent years across the national fleet. 

Commenters stated that this methodology is not appropriate because it overlooks the significant 

variability between coal-fired EGUs across the nation and within each state. Commenters stated 

that EPA then applies the 6 percent HRI to Tennessee's affected coal-fired EGUs to set the state's 

goal, again without consideration of what may have already occurred at Tennessee units or other 

important, relevant factors.

Commenters stated that EPA based the 6 percent HRI on averaged national data across the fleet 

or average ranges of potential from studies and EPA did not conduct a unit-by-unit analysis to 

determine of the 6 percent application to all affected coal EGUs within each state is technically 
449

feasible. Commenters stated that as a result, the proposed BSER is based on assumptions about 

the availability and appropriateness of HRI at facilities across the nation without taking into 

consideration unit size, facility location, age, operational limitations and cost recovery 

constraints. Commenters stated that additionally, the analysis does not take into account whether 

HRI measures anticipated as represented in the 6 percent have already been implemented at 

affected coal EGUs or what current applicable BMPs exist at the units today. Commenters stated 

that the significant variation in estimated efficiency potential across the fleet at a national level 

within the studies evaluated by EPA demonstrates the level of uncertainty as to what is possible. 

Commenters stated that because the current fleet of coal-fired plants has endured age-related 

degradation, changed operational requirements such as fuel quality, low emissions, flexible 

operations and physical modifications, achievable heat rates may be significantly different from 

initial design values. Commenters stated that making broad assumptions about the 884 coal and 

petroleum coke-fired EGUs identified by EPA in their analysis, which ranged from 1-69 years 

old, is arbitrary and overlooks potential significant issues related to the technical feasibility of 

achieving a 6 percent HRI target. Commenters stated that further, TVA has conducted an 

analysis of EPA's HRI strategies taken from the Sargent & Lundy Report and their applicability 

to TVA units across the TVA system. Commenters stated that according to TVA, the majority of 

the HRI strategies EPA relies upon to get to 6 percent are not applicable to TVA units, either 

because they have already been, or are currently being, implemented, or because the application 

of a measure is not appropriate for a particular facility. Commenters stated that in addition, TVA 

has retired or idled a number of its least-efficient units over the last decade. Commenters stated 

that as an aging fleet retires the oldest and less-efficient units, the HRI opportunities across that 

fleet will necessarily diminish. Commenters stated that the analysis of their own units suggests 

that EPA's HRI of 6 percent may not be achievable at affected coal EGUs in Tennessee today. 

Commenters recommended EPA to evaluate specific characteristics of the affected coal EGUs 

today and modify the 6 percent accordingly, or finalize the 6 percent, and the corresponding 

emission reduction included in each state's goal, as presumptive and allow states to perform this 

analysis during the state planning process to provide a demonstration of technical feasibility at a 

reasonable cost or a demonstration of what is technically feasible at a reasonable cost within 

building block 1, given state-specific, unit-specific circumstances. 

Commenters stated that the CPP should allow for each state to conduct a unit by unit evaluation 

of reasonable heat rate improvement projects and establish emission rate targets as required by 

EPA section 111(d) of the Clean Air Act. 

Commenters stated that in general, estimates of heat rate improvements at existing coal-fired 

facilities are largely dependent on the unit's unique characteristics. Commenters stated that 

application of a uniform, across-the-board, standard based on generalized assumptions regarding 

improvements from equipment upgrades and the exercise of best practices fails to take into 

account a facility's specific age, design or attributes. Commenters stated that rather than impose a 

blanket requirement, they suggest that EPA adopt a more flexible approach that allows the states 

to tailor Building Block 1 improvements to the facility's own individualized circumstances. 

Commenters stated that specifically, they recommend that the proposed average 6 percent heat 

rate improvement be utilized as a backstop. Commenters stated that however, states should be 

afforded the opportunity in coordination with EPA to adjust their state specific targets based on 

the state's determination of what is actually achievable after taking into account the specific coal 
450

plants within their jurisdiction. Commenters stated that this adjustment could be either a 

reduction or increase and incorporated into the State implementation Plan. Commenters stated 

that under this approach, efficiency improvements could be better targeted to those facilities 

capable of making such efficiency gains while recognizing the capital investment made by those 

plants already realizing such efficiency improvements. 

Commenters stated that by requiring across-the-board, rather than individualized, heat rate 

improvements, the proposed rule disfavors modern units of more efficient design that have less 

room for efficiency improvements. Commenters stated that to avoid penalizing units that are 

already more efficient, EPA should evaluate heat rate improvement capability at individual coalfired units. 

Commenters stated it is reasonable for EPA to base building block 1 on the average expected 

improvement in heat rate at existing coal-fired power plants, rather than demonstrating the 

feasibility of achieving this target at each individual plant. Commenters referred to Sierra Club v. 

Costle and said the case law under section 111 specifically recognizes that a standard of 

performance may be based on reliable data about the average performance of a control 

technology, so long as EPA grants sufficient flexibility in demonstrating compliance to account 

for the variability in performance of the control technology

Comment 54: Targets should be based on regional, state-specific or site-specific analysis 

Response 54: For the EPA’s response to these comments, see sections V.A and V.C of the final 

rule preamble of the CPP and Chapter 2 of the GHG Mitigation Measures TSD supporting the 

final CPP. For the reasons described in those documents, the EPA has adopted a regionalized 

analysis for building block 1.

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

Commenters believed that EPA has miscalculated the technical feasibility and the cost to 

existing EGUs to undertake new measures to increase their heat rates. Commenters stated that in 

this case, EPA has determined in some instances an efficiency improvement of 4-6% is 

achievable and automatically assumed that such improvements can be made at all facilities. 

Commenters stated that however, as EPA should be aware, opportunities to improve heat rate is 

determined at the unit level. Commenters stated that factors such as age, basic design, location, 

fuel, type of service and many others dictate the degree to which EGUs can improve efficiency 

and to simply assume that all units within a specific state can achieve enough efficiency 

improvement to meet this goal is faulty. Commenters stated that this highlights an area that EPA 

must allow States, who have a better understanding of these factors the flexibility to set such 

targets. Commenters stated that since it is unlikely that EGUs will be able to meet this efficiency 

improvement, states will be forced within the construct of the proposal to mandate further 

reductions within other remaining "building blocks" each of which are challenged in their own 

right. 

Commenters stated that EPA acknowledged in its rationale that it "is simply suggesting that 

BSER assumptions (e.g., 6% heat rate improvement for the coal fleet) can be achieved at the 
451

state level", however with only seven units making up Mississippi's coal fleet, Mississippi does 

not have the unit variability necessary to achieve 6% heat rate improvements. Commenters stated 

that EPA acknowledges that unique characteristics at the unit level may prevent some units from 

achieving the average applied to the state goal, and also indicates that individual unit assessment 

is not part of the goal setting exercise. Commenters stated that Mississippi contends it is exactly 

that exercise that must occur, especially when dealing with a limited universe of facilities, to 

establish responsible regulations. Commenters stated that preliminary discussions with their 

stakeholders indicate a maximum potential heat rate improvement of only 2% may still be 

available on some units. Commenters stated that they also indicate these improvements would 

come at an extreme cost since those improvements that were most feasible and cost effective 

have already occurred. Commenters stated that with Building Block 2 calling for early closure of 

these units, requiring the implementation of costly measures for heat rate improvements is 

unreasonable. Commenters suggested that a state-level assessment of the state's coal fleet be 

performed with regard to feasibility and unit-life expectancy before a final heat rate 

improvement goal is set for Mississippi.

Commenters stated that the EPA should acknowledge that it is simply not feasible for the agency 

to perform an appropriate assessment of potential HRI opportunities across the fleet of existing 

coal-fired EGUs due to the unit-specific nature of potential HRI opportunities, and the need to 

perform evaluations on a case-by-case basis. Commenters stated that therefore, if the EPA 

continues with a determination that HRI is BSER for existing coal-fired EGUs, it should defer to 

the states to determine the level of HRI that is appropriate for the existing coal-fired EGUs in 

their states. Commenters stated that only the states, working with the affected sources, can 

perform the unit-specific assessment that is required, factoring in other regulatory requirements 

that would apply to the affected sources and their impact on unit heat rates. Commenters stated 

that the statute requires that EPA permit the states to take these factors into consideration. 

Commenters stated that EPA does not take into account all of the variables that can affect heat 

rate, including coal quality, boiler design, and unit size. Commenters stated that for all of these 

reasons, site-specific analyses are critical for understanding actual heat rate improvement 

potential. 

Commenters stated that the national assumption of a heat rate improvement of six percent for 

Florida's coal-fired generating fleet is not technically feasible, given the long history of 

efficiency improvements to Florida's fleet. Commenters stated that in 1980, they developed a 

generating performance incentive factor program (GPIF) for investor-owned utilities, which 

encourages utilities to maximize unit heat rate efficiency of electric baseload generating units. 

Commenters stated that unit specific heat rate and availability requirements are set annually 

through a formal hearing procedure, and they have the authority to reward utilities that reach 

their requirements and penalize those utilities that do not. Commenters stated that effectively, the 

GPIF program provides multi-million dollar incentives for utilities to maximize supply-side 

energy efficiency improvements, thus reducing average fuel consumed per MWh at the source of 

air emissions. Commenters stated that in over 30 years of offering incentives, they have not seen 

consistent heat-rate improvements in the six percent range as suggested in the Proposed Rule. 

Commenters stated that in the last five years alone, changes in EGU specific heat rate 

efficiencies ranged from negative eight percent to positive four percent, even with the GPIF 

program incentives. Commenters stated that these fluctuations appear to be driven, in part, by 
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efforts to comply with environmental requirements. Commenters stated that rather than relying 

on an across the board six percent assumption, they propose a more Florida-specific analysis of 

achievable, permanent and cost-effective CO2 emission reductions. Commenters stated that such 

an analysis will take into account, not only potential for heat rate improvements (which can be 

verified through historical data under incentive programs like the GPIF program), but also steps 

already taken to increase efficiencies in Florida's fleet relative to EPA's baseline. 

Commenters stated that EPRI and NERC have expressed concerns about the validity of EPA's 

approach in establishing the 6% reduction requirement. Commenters stated that NERC expressed 

concern "...that the assumed improvements may not be realized across the entire generating fleet 

since many plant efficiencies have already been realized and economic heat rate improvements 

have been achieved." Commenters stated that EPRI indicated that:

• Estimates of heat rate improvements at existing coal EGUs are very dependent on 

individual unit characteristics (age, design, maintenance history, type of coal, etc.) and 

are difficult to apply a national fleet-wide heat rate goal. In estimating mitigation 

potentials, EPRI recommends that the estimates should be based on current studies and 

data that take into account recent EPA environmental control regulations. Regional or 

state-specific research and data should be used for the basis for estimating potential heat 

rate improvements rather than use of a national average for all. States differ widely in the 

characteristics and operating performances of their respective generating fleets.

Commenters stated that while six percent may be technically feasible at a single point in time, at 

certain units, and under ideal conditions, in practice, the best heat rate improvements achievable 

for such upgrades and practices are significantly lower. Commenters stated that the heat rate 

improvement that is actually achievable is unit-specific, and depends on site-specific factors like 

current operating practices and past efficiency upgrades and that a six percent heat rate 

improvement has not been adequately demonstrated for coal-fired EGUs. Commenters stated that 

EPA's failure to consider site-specific limitations on improvements to heat rates at coal-fired 

EGUs is unreasonable, and renders Building Block One arbitrary and capricious. 

Commenters stated that from the opening sentence of EPA's evaluation of potential heat rate 

improvement opportunities, the agency mischaracterizes observed differences in operating 

efficiencies as being "evidence" that existing coal-based generating units are not being 

adequately operated or maintained. Commenters stated that EPA is incorrect in this conclusion 

and that heat rate performance is influenced by a variety of known and unknown, controllable 

and uncontrollable factors, whose interaction and degree of impact is unit-specific and will vary 

throughout the life of the unit. Commenters stated that EPA itself in a 2010 report on available 

and emerging technologies for reducing greenhouse gas emissions from coal-fired electric 

generating units stated that: 

• The actual overall efficiency that a given coal-fired EGU achieves is determined by the 

interaction of a combination of site-specific factors that impact efficiency to varying 

degrees... Because of these factors, coal-fired EGUs that are identical in design but 

operated by different utility companies in different locations may have different 

efficiencies. Thus, the level of effectiveness of a given GHG control technology used to 
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improve the efficiency at one coal-fired EGU facility may not necessarily directly 

transfer to a coal-fired EGU facility at a different location.

Commenters further stated that although EPA in the proposed rule alludes to this wide scope of 

influences and the "site specific" factors that drive heat rate performance, the agency fails to 

objectively and holistically account for these drivers, and concludes that, except for the 

variability attributable to ambient temperatures and load factor, poor operational practices and 

lack of equipment maintenance or upgrades are the exclusive source of observed "difference[s] 

in operating efficiency." Commenters stated that EPA's evaluation ignores or does not fully 

consider the following:

• the other uncontrollable factors that impact heat rate performance;

• the availability, technical viability, and economic feasibility of potential 

improvement opportunities at individual units;

• heat rate improvement measures that have already been implemented;

• unit-specific factors that influence the magnitude and sustainability of potential 

heat rate improvements; 

• the impact of other environmental requirements that may mask or eliminate 

potential heat rate improvements.

Commenters stated that, had EPA fully considered these factors, the agency would have 

correctly concluded that both the proposed 6% and alternative 4% targets for heat rate

improvements are overly aggressive, and cannot feasibly be implemented by the majority of 

existing coal-based generating units. Instead of collecting the information necessary to 

reasonably evaluate these issues, EPA chose to evaluate potential heat rate improvement 

opportunities by:

• performing a flawed statistical analysis of heat rate variability;

• performing a narrow review of available information on heat rate performance by 

examining a single technical report with a study of just two units and select 

vendor information;

• incorrectly estimating the applicability of and cumulative impact of a portfolio of 

potential improvement measures; 

• incorrectly assuming that a high rate of cumulative improvements are achievable 

by all coal units.

Commenters stated that, based on this evaluation, EPA determined that a 6% efficiency 

improvement has been adequately demonstrated to be achievable through improved operating 

practices (4%) and equipment maintenance/upgrades (2%). Commenters stated that EPA's 

flawed assessment is grounded in uninformed and inaccurate assumptions and conclusions that 
454

reflect an incomplete understanding of the nature, cost, and availability of potential heat rate 

improvement opportunities. 

Commenters stated that, should the improvements in Block 1 prove attainable, the EPA estimates 

a 30 lbs/MWh reduction in Florida's CO2 emissions. Commenters stated that the EPA estimates 

the cost of implementing heat rate improvements at "relatively modest capital costs" of $100 per 

kilowatt (kW). Commenters further stated that using Florida's 2012 coal capacity of 11,491 MW, 

Florida consumers would pay $1.15 billion for these heat rate improvements and although some 

of these costs may be offset by lower fuel costs per MWh, a fluctuation of fuel prices could also 

eliminate any savings. Commenters stated that moreover, Florida's investor owned utilities are 

incentivized to improve heat rate performance, and historical data shows sustained heat rate 

improvements are not easily achieved. Commenters described that in 1980, the FPSC developed 

a generating performance incentive factor program (GPIF) for investor-owned utilities, which 

encourages utilities to maximize unit heat rate efficiency, and that targets are set annually 

through a formal hearing procedure, and investor-owned utilities either gain rewards or suffer 

penalties based on the prior year's performance compared to the previously set annual targets. 

Commenters stated that the GPIF program creates multi-million dollar incentives for utilities to 

maximize efficiencies at their fossil-fired units and that in over 30 years of offering incentives, 

Florida has not seen consistent heat-rate improvements in the 6 percent range as suggested in the 

Proposed GHG Rule. In the last 5 years alone, heat rate efficiencies ranged from negative 8 

percent to positive 4 percent, even with the GPIF program incentives. Commenters stated that 

rather than relying on an across-the-board assumption of a 6 percent improvement to calculate a 

Final Goal, they suggest that a more state-specific analysis be utilized, which will take into 

account, not only potential for heat rate improvements (as verified through historical data under 

incentive programs like the GPIF program), but also steps already taken to increase efficiencies 

in the state's fleet. Commenters concluded that a state-specific fleet analysis is more reasonable 

in determining a state's Final Goal.

Commenters stated that in summary, while there is a basis for considering heat rate performance 

or potential improvements in heat rate as BSER, states-which have the authority under section 

111(d) to establish standards of performance-are in the best position to determine unit-specific, 

achievable heat rate improvement levels. Commenters stated that heat rate level or potential 

improvements in heat rate are very case-specific, and states are in a better position than EPA to 

develop case-specific standards that consider all of the section 111(d) requirements for 

achievability, cost, any non-air quality health and environmental impact, and adequate 

demonstration. Commenters stated that EPA should consider any BSER information states may 

provide in setting state emission rate goals, and in making subsequent adjustments to those goals 

so that states can set attainable standards of performance on a case-by-case basis for each 

affected existing source within its jurisdiction. 

Commenters stated that EPA asserts that it is possible under Building Block 1 to achieve overall 

HRIs of 6% (or 4% under the alternate goals) on average at existing coal-fired EGUs. 

Commenters stated that by applying this 6% average HRI to all EGUs in a state without 

consideration of unit-specific limitations, EPA violates its statutory obligation to allow states to 

conduct unit-specific assessments in establishing standards of performance for existing sources, 

and in violating this statutory obligation, EPA acts arbitrarily, capriciously, and contrary to law. 

Commenters stated that Big Stone Plant is the only coal-fired EGU operating in South Dakota 
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and therefore, South Dakota's ability to attain the 6% (or alternate 4%) HRI required by the 

proposed rule depends entirely on whether each of the HRI measures identified in the Sargent & 

Lundy report can be made at Big Stone Plant.

Commenters stated that first, EPA's proposal for a 6% HRI is adequate on a national basis but 

does not take into account state-specific or regional considerations. Commenters stated that 

regional or state-specific research and data, including HRI methods, should be used as the basis 

for estimating potential heat rate improvements rather than sole reliance on national averages for 

all states. Commenters stated that States differ widely in the characteristics and operating 

performance of their generation fleets. Commenters stated that also, there are considerable 

differences between individual units in terms of age, size, degree of environmental retrofits and 

HRI methods employed. Commenters stated that EPA should solicit this information on regional 

and state-specific heat rates from state agencies and/or the generators themselves.

Commenters requested that EPA take into consideration in its development of its BB1 proposal: 

(1) the importance of regional and individual generation facility characteristics in estimating 

HRI; (2) ability for generation facilities to support investment in HRI equipment; and (3) the 

impact of regional load factors on HRI.

Commenters stated that the actual HRI achievable at any generation unit is unit-specific with the 

maximum HRI improvement depending on the condition and operation of the individual unit. 

Commenters stated that units where major modifications or replacements of the turbine have 

been recently completed will have much smaller potential for heat rate improvements, while 

those units that have not upgraded equipment or have been less well maintained will have a 

larger potential for heat rate improvement. Commenters stated that these latter units, however, 

may also be at greater risk for retirement insofar as the cost of installing HRI upgrades at this late 

date may be outweighed by the cost savings from retiring the plant altogether. Commenters 

stated that the costs to improve heat rate are also unit-specific such as the impact of age of the 

unit, its location and its overall condition including maintenance. Commenters stated that 

generator plant size also plays a role, as the expenditures are more easily justified for larger units 

with higher capacity factors.

Commenters stated that this concern was highlighted in a 2014 National Coal Council report 

which noted that some HRI options can have cumulative benefits and a number of measures may 

work together synergistically to improve heat rate while others may negatively impact reliability. 

Commenters stated that other combinations of HRI measures may also not be technically or 

economically feasible, but in any case, all HRI measures must be assessed with reference to the 

specific characteristics of the generation unit and the costs of particular HRI technology utilized 

for that unit. Commenters stated that the report also has a detailed list of reasons why cited heat 

rate improvements might not be applicable at a specific power plant and it also includes a list of 

factors that could lead to an increase in coal power plant heat rates including more operation at 

partial load, adding more environmental control equipment, switching from once-through to 

evaporative or air cooling, and switching from bituminous to lower sub-bituminous coal.

Commenters requested that EPA take into consideration in its development of its BB1 proposal: 

(1) the importance of regional and individual generation facility characteristics in estimating 
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HRI; (2) ability for generation facilities to support investment in HRI equipment; and (3) the 

impact of regional load factors on HRI. 

Commenters stated that the proposal to include 6 percent efficiency improvement is unworkable 

on the Santee Cooper system and is not a useful building block in the reduction of CO2. 

Commenters stated that its use by the EPA as a building block requires further analysis by the 

EPA and is arbitrary and capricious when applied to the facts in South Carolina. Commenters

stated that as an alternative to this arbitrarily reached HRI, the EPA should examine the coal 

plants in each state and determine, based on analysis of actual data, what the appropriate HRI 

should be. 

Commenters stated that the EPA's broad application of a nationwide average 6 percent HRI goal 

in calculating individual state CO2 emission rate targets has failed to account for unique 

differences in coal-fired EGUs that affect potential HRI opportunities at individual unit, state, 

regional, and national levels. 

Commenters stated that they support a BSER approach for reducing emissions by improving the 

heat rate of generating units but believe that the six percent improvement used to establish state 

goals in the Proposed Rule is not achievable for most units on a statewide basis. Commenters 

stated that the EPA should allow each state to conduct a unit-by-unit evaluation of existing HRI 

projects and establish emission rate targets as required by EPA. Commenters stated that a more 

reasonable plant heat rate efficiency goal needs to be established with credit given to utilities that 

have already performed projects identified by the EPA. 

Commenters stated that the unprecedented intervention by EPA in the way in which they

produce electricity is unsupported by any evidence specific to their plant. Commenters stated that 

if EPA is going to urge Puerto Rico to pursue heat rate improvements in determining the BSER 

for the island, then the agency should first authorize the Commonwealth to develop data and 

analysis specific to their plant to determine what, if any, realistic heat rate improvements could 

in fact actually be achieved and sustained at their facility. Commenters stated that moreover, 

crucially, any BSER must consider the PPA between their plant and PREPA that governs their

operations through 2027. Commenters stated that any large projects that would require material 

new investments and significant down time for the plant simply would not be feasible under the 

PPA. Commenters stated that EPA's "one-size-fits-all" approach effectively mandates heat rate 

improvements at their plant without any specific evidence that the assumed improvements could 

even be accomplished at their facility. Commenters stated that in support of its heat rate 

improvements, EPA relies to a significant degree on a brief 2009 document prepared by Sargent 

& Lundy, a report which has been the subject of previous criticism and which Sargent & Lundy 

itself has explained was misapplied by EPA in its BSER analysis. Commenters stated that the 

S&L report lists various "best practices" and "equipment upgrades" that purportedly improve 

heat rate at power plants, but there is no evidence that any of these would work at their plant to 

the degree EPA assumes in its Supplemental Proposal. Commenters stated that in all events, 

none of the extremely limited (three) case studies discussed in the S&L report (or elsewhere in 

EPA's analysis) involved a CFB boiler like those operated by their plant. Commenters stated that 

EPA must justify its dramatic and intrusive proposal to set CO2 emission goals by transforming 

the way energy is supplied in Puerto Rico. Commenters stated that it is unreasonable for the 

agency to base BSER goals for Puerto Rico on heat rate improvements at their plant without first 
457

having a specific engineering analysis of their facility. Commenters stated that in fact, as Sargent 

& Lundy itself explained in their comments on the proposed rule, application of a performance 

standard to individual coal-fired EGUs would require a "detailed site-specific analysis" that 

considers, among other factors, "plant design, previous equipment upgrades, and existing 

operation and maintenance practices."

Commenters stated that EPA failed to consider the significant differences between coal-fired 

plants across the country, and EPA fails to provide the States with the flexibility to make these 

considerations when implementing the Proposed Rule. 

Commenters stated that even if EPA's nationwide assumptions were reasonable, EPA fails to 

recognize that applying those assumptions at the state level is inappropriate for states like New 

Mexico with only a few coal-fired generators that have already completed most of EPA's 

recommended efficiency projects, making further improvements much more difficult and costly, 

and likely unachievable. 

Commenters stated that EPA should allow states to propose heat rate improvement targets that 

are appropriate to their coal-fired power plant fleets, taking into consideration the technological 

feasibility, cost and remaining useful life of each unit as Section 111(d) requires. Commenters 

stated that various limitations exist for applying each heat rate improvement strategy, and these 

limitations depend on the unit type, fuel type, and many other site-specific conditions and 

therefore, the ability to apply each strategy and the amount of heat rate reduction that can be 

achieved by each strategy is site-specific and must be evaluated on a case-by-case basis. 

Commenters stated that under no circumstance should EPA base the state emission rate goals on 

a uniform heat rate improvement of six percent, as such a rate is arbitrary and unsupported in 

practice. 

Commenters stated that to address these concerns EPA should specifically allowing a state the 

ability to recognize and give credit for past energy efficiency accomplishments. Commenters 

stated that additionally, states should be authorized to provide reliability exemptions or minimum 

exempt run periods for smaller units that are necessary for local voltage support or to provide the 

needed peak load support during high load months. Commenters stated that this could be 

accomplished through a subcategory or through operational limitations that allow for exemptions 

from the program. Commenters stated that examples of how these types of programmatic 

exemptions include in the EPA's RICE Rules which allow for a certain number of reliability run 

hours from uncontrolled diesel engines or even in the application of reformulated gasoline 

standards that allow for certain fuels to be sold during certain times of the year. 

Commenters recommended that EPA amend Building Block 1 stipulating that no reductions 

associated with coal plant heat rate improvements will be required for states that generated less 

than 10% of their total annual energy from coal. Commenters stated that there are many reasons 

EPA should exclude states with limited coal production from Building Block 1. Commenters 

stated that first and foremost those states with less than 10% of their total energy generated from 

coal have already undergone a significant change in the energy mix. Commenters stated that the 

coal currently operating in New York is performing a needed function as it helps to address local 
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reliability issues and in many instances is operating because those units must run for local 

reliability needs. 

Commenters stated that such an exemption or conditional operational authority is likely to have 

limited GHG impacts while significantly aiding localized reliability as they transition to a larger 

intermittent, renewable energy portfolio. Commenters stated that the small affected units in the 

US are a very small proportion of nameplate capacity. Commenters stated that most of these 

small units are expected to retire due to other air pollution regulations. Commenters stated that as 

a result, small units that meet other air regulations, such as 31 and 32, and that provide critical 

voltage support and peaking capabilities, are likely to equal less than 1% of total GHG emissions 

across the nation, but these units will provide great value in the transition of their energy supply 

makeup. Commenters stated that providing states with express guidance that addressing localized 

reliability concerns should be a priority for EPA, but it will also be important for EPA to build 

into the final goal it sets for states the capability to modify the goal to reflect these kinds of unit 

and state specific concerns. 

Commenters stated that EPA should allow states to propose heat rate improvement targets that 

are appropriate for their coal-fired power plant fleets, taking into consideration the technological 

feasibility, cost and remaining useful life of each unit as Section 111(d) requires. 

Commenters stated that they do not believe that the technical documentation provided adequately 

justifies EPA's assumption that an average 6 percent heat efficiency increase is reasonably 

achievable for coal-fired EGUs on either a state-wide or nation-wide basis. Commenters stated 

that EPA's own analysis indicates that a 6 percent efficiency increase is on the upper bound of 

achievability for most facilities. Commenters stated that different facilities are starting (as of 

2012) at different efficiency levels, depending on unit age, condition, and design. Commenters 

stated that given the limited available opportunities for efficiency improvements, a more 

reasonable state-based or facility-based factor should be used for Building Block 1. 

Commenters stated that they agree with the EPA that heat rate improvements at coal-fired EGU's 

are a potential source of emission reductions, however, in calculating the goal for EPA's 

Building Block 1, they suggest that the EPA modify its approach to allow for consideration of 

individual unit characteristics. Commenters acknowledged that such an analysis would be 

difficult for the EPA to perform at a national level, therefore, Commenters suggested that the 

analysis be done as part of the state's Section 111(d) plan, and that the goals be adjusted 

accordingly. 

Commenters stated that coal-fired EGUs are subject to air regulations that have required the 

installation of controls over the last decade. Commenters stated these controls reduce efficiency. 

Commenters stated that for example, according to TVA, when it installed scrubbers at its 

Kingston Coal Plant, the unit heat rates increased by 4-6 percent and the installation of selective 

catalytic reduction and/or flue gas desulfurization on many coal units resulted in a 3-4 percent 

increase in heat rate. Commenters stated that now, with the proposed BSER, EPA suggests 

that 6 percent HRI can be achieved in each state at coal affected units with various controls, 

despite having failed to actually conduct a unit-by-unit analysis to understand whether this is 

actually the case. Commenters stated that they are concerned that recent investments in 

environmental controls at coal-fired EGUs have not been taken into account with regard to their 
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impact on costs and technical feasibility of HRI at 6 percent as proposed. Commenters stated that 

having failed to conduct a unit-by-unit analysis, EPA's proposal does not demonstrate that costs 

will be reasonable or that the 6 percent, in every state, is feasible. Commenters stated that they

recommend EPA to address the impact of control technology on the technical feasibility of 

achieving the 6 percent HRI and adjust the target accordingly or finalize the 6 percent, and the 

corresponding emission reduction included in each state's goal, as presumptive and allow states 

to perform this analysis during the state planning process to provide a demonstration of technical 

feasibility at a reasonable cost or a demonstration of what is technically feasible at a reasonable 

cost within building block 1, given state-specific, unit-specific circumstances. 

Commenters stated that EPA should not impose a six percent across the board heat rate 

improvement, and should rather allow states to determine the appropriate heat rate reduction for 

each affected unit based on a case-by-case assessment of the unit's history, boiler configuration, 

fuel type and remaining useful life. 

Commenters stated that EPA's proposal and its technical support documents do not indicate 

whether EPA considered HRI loss over time in setting the 6 percent HRI nationally and applying 

it to each state. Commenters stated that HRI may degrade over time and may vary in potential 

achievement from one unit to the next depending on unit specific considerations and level of use. 

Commenters stated that is, an HRI measure may not result in a permanent and consistent change 

in performance of the unit. Commenters stated that the requirement included within EPA's 

application of the proposed 6 percent HRI to states that the reductions be achieved by 2020 and 

then maintained consistently in perpetuity will not be met if the performance of a particular HRI 

degrades over time or is variable from unit to unit. Commenters stated that EPA must consider 

both of these in establishing the proposed BSER and applying it to units within states. 

Commenters stated that EPA's adoption of a 6 percent HRI nationally and then application of 

that 6 percent to each state fails to account for performance loss over time or variability; 

Commenters stated that however, EPA does take into account life-cycle performance and 

degradation of measures in its approach to energy efficiency in building block 4. Commenters 

stated that EPA must be consistent in its development of BSER across the building blocks. 

Commenters stated recommended EPA to consider HRI loss over time and variability at the unit 

level and adjust the proposed BSER accordingly or finalize the 6 percent, and the corresponding 

emission reduction included in each state's goal, as presumptive and allow states to perform this 

analysis during the state planning process to provide a demonstration of technical feasibility at a 

reasonable cost or a demonstration of what is technically feasible at a reasonable cost within 

building block 1, given state-specific, unit-specific circumstances. 

Comment 55: Comments regarding unit specific HRI data (unit-by-unit evaluations may not 

support 6% HRI)

Response 55: See section V.C. of the final rule preamble of the CPP and Chapter 2 of the GHG 

Mitigation Measures TSD supporting the final CPP for EPA’s response to this comment. 

The following are summaries of the specific public comments under this comment:
460

Commenters stated that EPA should allow states to propose heat rate improvement targets that 

are appropriate to their coal-fired power plant fleets, taking into consideration the technological 

feasibility, cost and remaining useful life of each unit as Section 111(d) requires, because of 

various limitations for applying each heat rate improvement strategy, and these limitations 

depend on the unit type, fuel type, and many other site-specific conditions. Commenters stated 

that therefore the ability to apply each strategy and the amount of heat rate reduction that can be 

achieved by each strategy is site-specific and must be evaluated on a case-by-case basis, and 

under no circumstance should EPA base the state emission rate goals on a uniform heat rate 

improvement of six percent, as such a rate is arbitrary and unsupported in practice.

Commenters stated that EPA's assumption that coal-fired EGUs can achieve an additional two 

percent improvement in heat rate through implementation of equipment upgrades is flawed and 

that EPA relies exclusively on the S&L Report to conclude a two percent net heat rate 

improvement (incremental to EPA's perceived improvement from best practices) is feasible and 

sustainable through equipment upgrades. Commenters stated that S&L recently provided critical 

context to its 2009 report in a letter sent to the National Rural Electric Cooperative Association 

("NRECA") that EPA cannot now ignore. Commenters stated that Sargent & Lundy explicitly 

stated that "the only technically appropriate method to properly evaluate potential heat rate 

improvements is to conduct a unit-by-unit evaluation "and further clarified the conclusions of its 

2009 report:

• No conclusion was made that any individual EGU or aggregation of EGUs could 

achieve a six percent heat rate improvement or any broad target;

• Case studies showed that not all of the heat rate improvements could be applied to 

individual units;

• Implementing heat rate improvements are limited due to unit type, fuel type, and 

many other site-specific conditions;

• Heat rate improvements cannot be assumed as additive;

• Verification of actual heat rate improvements at individual units were not made;

• Plant operating variables impact the economics of and heat rate reductions from 

projects;

• Some heat rate improvements degrade over time, even with best maintenance 

practices;

• Heat rate is impacted by a unit's load factor;

• Environmental controls will increase a unit's heat rate; and

• Many projects listed by the report have triggered NSR.
461

• EPA cannot rely on the S&L Report to justify the availability and sustainability of 

any level of heat rate improvement. 

Commenters stated that the heat rate of an EGU is not a constant value and, as the EPA points 

out, a number of factors can affect an EGU's efficiency that include its: thermodynamic cycle; 

coal rank and quality; facility size; pollution control systems; operating/maintenance practices; 

type of cooling system; geographic location and ambient conditions; load generation flexibility 

requirement (baseload vs. load following); and plant components. Commenters stated that in 

addition, not all EGUs are designed to be operated at the same exact heat rate. Commenters 

stated that coal-fired EGUs throughout the U.S. differ in age; burn differing types of coal; and 

have been designed and constructed by different manufacturers. Commenters stated that for 

instance, an EGUs "design heat rate," and its actual average heat rate, are likely to differ 

significantly since the design heat rate is a "theoretical target that represents an optimal, fullload, steady-state condition and is considered the best a unit could potentially achieve under its 

original design conditions." Commenters stated that the age of a coal generation unit, its historic 

operations and maintenance, and the retrofit of any auxiliary equipment like emissions controls 

will significantly impact the coal unit's heat rate; in other words, unit HRIs are unit-specific and 

it is unreasonable to assume that all EGUs could incorporate all heat rate improvement methods 

and that each method would impact each and every EGUs in the same manner. 

Commenters stated that they operate a fleet of six coal-fired EGUs at two separate electrical 

generating stations: the Four Corners Power Plant has two 770 MW (nominal) supercritical 

boilers that are equipped with FGD and fabric filters, and soon will be equipped SCR, and the 

Cholla Power Plant has four tangentially fired boilers ranging in size from 116 MW to 380 mw 

(nominal) and three of the four Cholla units are equipped with FGD and fabric filters. 

Commenters stated that they conducted a study to determine the heat rate improvement projects 

that could be implemented on these units to effect efficiency improvement and identified a few 

projects that could be implemented to achieve an improved heat rate, but that however, when 

combined with other required environmental projects that will negatively impact unit heat rate, 

such as the installation of SCR controls and a stack liner, the net effect is a potential maximum 

efficiency improvement of between 0.7 percent and 1.6 percent. The commenters stated that the 

efficiency improvement study at Cholla showed that an efficiency improvement between 0.4 

percent and 2.1 percent may be achievable and while Commenters agreed that these projects will 

be helpful in lowering the carbon emission rate, the proposed six percent efficiency 

improvements are simply not available for these units. Commenters summarized that the 

contribution to the state's carbon goal from efficiency actions (operating practices and equipment 

upgrades) at Subpart Da EGUs should be determined by each state after a careful case-by-case 

analysis of what can actually be achieved at each EGU and not only will this result in more 

realistic and achievable carbon emission rate reductions, this is precisely what the CAA requires.

Commenters stated that EPA cannot rationally prescribe a specific percentage of improvement 

that could be achieved across all coal-fired EGUs and that EPA did not analyze the best practices 

being implemented across the industry and the heat rate improvements achieved as a result of 

their adoption. Commenters stated that instead, EPA should leave it to the states to perform a 

unit-by-unit analysis, only which would accurately identify the degree, if any, to which net heat 

rates vary and can be improved upon and whether best practices are being used. Commenters 

stated that a unit-by-unit analysis is important because utility maintenance practices vary based 
462

on their different circumstances and operating and maintenance best practices may have already 

been developed and implemented - as they have been at Southern Company. 

Commenters stated that EPA should consider allowing states to replace the assumed 6% heat rate 

improvement in the goal-setting formula with a case-by-case evaluation of the potential for, and 

cost-effectiveness of, further heat rate improvement projects at individual EGUs. Commenters 

stated that case-by-case evaluation of heat rate should calculate efficiency improvements on a net 

basis (i.e., lbs CO2/MWh net).

Commenters stated that NERC is concerned that the assumed improvements may not be realized 

across the entire generation fleet since many plant efficiencies have already been realized and 

economic heat rate improvements have been achieved. Commenters stated that multiple 

incentives are in place to operate units at peak efficiency, and periodic turbine overhauls are

already a best practice. Commenters stated that site-specific engineering analyses would be 

required to determine any remaining opportunities for economic heat rate improvement 

measures. 

Commenters stated that EPA's methodology in calculating its proposed reduction in heat rate for 

coal-fired EGUs (building block 1) is flawed because it does not account for the fact that sources 

have already reduced their heat rate through available technology for their own reasons of 

operational efficiency and it does not calculate potential efficiency net of what is necessary to 

satisfy other environmental commands. Commenters stated that it is completely undemonstrated 

that equivalent across-the-board reductions can be made on top of what already has been done 

and that the November 2014 NERC report expresses concern "that the assumed improvements 

may not be realized across the entire generation fleet since many plant efficiencies have already 

been realized and economic heat rate improvements have been achieved." Commenters stated 

that NERC notes that "[s]ite-specific engineering analyses would be required to determine any 

remaining opportunities for economic heat rate improvement measures."

Commenters stated that the proposed rule suggests that a 6% improvement can be made across 

the board for coal fired units. Commenters stated that Georgia Power has retired, and is planning 

to retire, older and less efficient coal units. Commenters stated that they have approved Georgia 

Power's investments to maximize the power output of its units and maximize the economically 

viable heat rate. Commenters stated that a set reduction should not be applied abjectly across all 

states, but should be based on existing technology at each unit to determine whether 

improvements have potential and are economic. Commenters added that working toward a six 

percent improvement will require detailed analysis at each coal unit to determine the realistic 

heat rate improvements, whereas applying a general standard across various technologies and 

unit ages masks the true potential gains that could actually be achieved by an individual state. 

Commenters stated that, also on a basic level, it is unlikely that any utility would not invest in 

heat rate improvements for its existing units if economically viable and that this investment 

would undoubtedly be less capital intensive than new facilities and, in Georgia, would be 

approved in an IRP if found to be viable.

Commenters stated that the 6% efficiency improvement projected in the CPP model is not 

achievable for most units or on a statewide or system average and that a more realistic plant 

efficiency goal needs to be established or credit given to utilities that have already performed 
463

projects identified in the proposed CPP. Commenters stated that CPP should take into 

consideration generating units that are well operated and maintained to determine which 

additional realistic heat rate improvements are achievable. 

Commenters referred to S&L stating in its letter to the National Rural Electric Cooperative 

Association, "the only technically appropriate method to properly evaluate potential HRI is to 

conduct a unit-by-unit evaluation." Commenters stated that the case-by-case evaluation or energy 

audit S&L recommends is a common sense approach EPA ignored when setting a national six 

percent heat rate reduction requirement in Building Block 1. Commenters stated that many EGUs 

are designed and operated as base load units and simply cannot achieve it and continued that 

West Virginia base load EGUs cannot meet the six percent mark, as they have already minimized 

heat rate variation and operate at high boiler efficiencies. Commenters stated that this assertion is 

bolstered by the fact that based upon 2012 Clean Air Markets Division (CAMD) data, West 

Virginia's coal-fired EGUs have the lowest average heat rate (9294 BTU/kWh-gross) of any state 

in the nation. Commenters stated that this is true because the base-load EGUs in West Virginia 

have already achieved the possible boiler efficiency improvements outlined in S&L. 

Commenters stated that it is disingenuous for EPA to insist that existing EGUs that comply with 

the ARP, CAIR, CSAPR, and MATS can significantly improve heat rate, because these units 

have already done so and clearly the sources EPA identified in its data analysis have already 

achieved significant heat rate improvement, and the majority of those opportunities for 

improvement outlined in the proposed rule would no longer be available to them.

Commenters stated that since EPA did not provide the data for individual EGUs analyzed in its 

statistical approach, they were unable to discern where North Carolina's fleet ranked relative to 

others and to assess the relative performance of their coal fleet, Commenters calculated the statelevel gross heat rate using EPA AMPD data for year 2012 and found that North Carolina's 2012 

gross heat rate for coal-fired EGUs was 9,071 Btu/kWh, which is significantly lower than EPA's 

national average of 9,753 Btu/kWh and the lowest in the country. Commenters stated that North 

Carolina's heat rate performance results are before making corrections that EPA made to account 

for variability in meteorology and capacity factors, and would most likely be lower when these 

factors are accounted for. Commenters provided a table showing gross heat rate calculations per 

state in 2012.

Commenters stated that having the lowest gross heat rate reflects that some or most of North 

Carolina's coal-fired EGUs have successfully implemented efficiency measures prior to the 

proposed rulemaking. Commenters stated that North Carolina's heat rate values can be correlated 

with the actions taken by the state legislature with the enactment of the Clean Smokestacks Act 

in 2002 which required significant reductions in NOx and 502 emissions from coal-fired EGUs. 

Commenters stated that compliance with the law resulted in multiple retirements, natural gas 

conversions, and add-on pollution control equipment, with 2013 being the final compliance year 

for meeting emissions targets. 

Commenters stated that the 2012 heat rate data presented here reflect the operating changes that 

occurred at the EGUs as each of the affected plants were retrofitted with NOx, SO2, and PM 

controls and it should be noted that in 2012, a significant shift to natural gas had already 

occurred, and many coal-fired EGUs were operating at much lower capacity than previous years. 

Commenters stated that despite this change, North Carolina's state-wide average heat rate 
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remained the lowest in the nation. Commenters presented a figure showing the cumulative effect 

of the EGU fleet change on the baseline CO2 rate and demonstrates that North Carolina's CO2 

rate declined during the recession and increased post-recession. Commenters stated that the CO2 

rate was at the lowest level in 2012 due to compliance with the CSA and a shift to lower carbon 

emitting fuels.

Commenters listed several principles that are critical in determining the realistic applicability and 

degree of potential heat rate improvement that any specific project might afford:

• improvements are not uniform and what may work for one unit, may not work for 

another;

• the heat rate benefit of multiple improvement projects is not necessarily 

cumulative; improvements in one area can be masked by operations or conditions 

in another, thus diminishing any overall heat rate improvement;

• -outside influences beyond the control of the unit operators can alter or erase heat 

rate improvements, because plants are dispatched based upon electricity demand, 

and the availability of other units;

• improvements must be cost-effective and measurable to justify their 

implementation;

• space constraints may exist on a particular unit that prohibit the addition of 

equipment or re-routing of ductwork/piping to implement a heat rate improvement 

project;

• the benefit derived from many of the suggested heat rate improvement 

technologies is temporary and will diminish over time due to the age and 

operation of the unit;

• for some heat rate improvement projects the potential benefits will only be 

apparent at full load operations, and offer no measurable improvements for cyclic 

or minimum load operations;

• conversely, some base load units would show no benefit to heat rate if the 

improvement is experienced only at lower loads or during cycling operations;

• EPA's 111(d) proposal suggests that existing coal power plants will be dispatched 

and operated much differently from the past, so historic experience may not 

provide an accurate projection of future benefits. 

Commenters stated that most power plant owners regularly assess the potential for heat rate 

improvements in order to capture these cost savings. Commenters stated that however, this past 

practice means that every well-maintained unit likely has implemented several cost-justified 

methods to improve heat rate, and that only marginal projects remain for consideration.
465

Commenters stated that units vary significantly due to their design, manufacturer, operating 

history, age, and type of coal consumed, among many other factors and that it is completely 

unreasonable and technically infeasible to expect that this widely diverse fleet could all achieve 

the same level of improvement in heat rate performance. Commenters stated that for example, 

the AEP John W. Turk, Jr. Plant ("Turk") that began operation in 2012 represents a state-of-theart ultra-supercritical steam cycle, which is a design that produces higher steam temperatures and 

pressures than is typical in most units. Commenters stated that the result is that the Turk Plant 

has a much higher overall efficiency (~38%) and much lower average net unit heat rate (~9,000 

Btu/kWh net), than the 2012 coal-fired generation fleet average of 34 % and 10,107 Btu/kWh 

net. Commenters stated that Turk is the only operating ultra-supercritical unit in the U.S., in 

large part because it has only been within the last decade that advanced steam piping materials 

have been available. Commenters stated that EPA's flawed "one-size-fits-all" approach in 

building block one (a) incorrectly assumes that the newest and most efficient coal units, 

including the Turk Plant, could achieve a 6% heat rate improvement, and (b) ignores the 

significant unit-specific design differences that physically limit the potential opportunities for 

improvement.

Commenters stated that conversely, even similar or identical unit types can experience 

significant variability in heat rate performance. Commenters supported this point with a 

graph that plots the range of gross annual unit heat rates from 1999-2013 of their units that are of 

similar size and/or design. Commenters stated that the units at each respective plant, while 

sharing similar attributes in terms of the equipment technology and vintage, location (ambient 

temperature), fuel supply, operational characteristics, and other factors, have experienced quite 

dissimilar average gross annual heat rates, attributable to many of the factors discussed herein. 

Commenters stated that even similar units operating under similar ambient conditions can have 

significant variations in heat rate. Commenters stated that it is important to differentiate between 

the "design heat rate" and the average heat rate of a unit (design heat rate is a theoretical target 

that represents an optimal, full-load, steady-state condition and is considered the best level of 

unit performance that could potentially be achieved under original design conditions). 

Commenters stated that it is possible that units may achieve their design heat rate when new with 

all components in their best condition but that it is well-understood by manufacturers, operators, 

and most regulators, however, that the unit will not, and should not be expected to achieve its 

design unit heat rate under all operating conditions or throughout its operating life. Commenters 

stated that the age of the unit, historic operations and maintenance over its life, as well as the 

retrofit of any auxiliary equipment like emissions controls, will all negatively impact the heat 

rate over the life of the unit, resulting in an average unit heat rate that is higher than the unit's 

original design heat rate. Commenters stated that while there may be similarities between units, 

often even identically designed units at the same plant site have very different heat rates because 

each unit has been operated and maintained differently. 

Commenters stated that heat rate efficiency improvements must be based on each facility's 

circumstances. Commenters stated that 6% heat rate efficiency improvement figure that the 

USEPA proposes to utilize represents a national average that the USEPA believes facilities could 

achieve but it does not take into account individual circumstances of the affected sources; for 

example, TS Power Plant (TSPP), a 242 MW (gross) pulverized coal-fired power plant, was 

constructed to supply electrical power to nearby mining and mineral processing facilities owned 

by Newmont Mining. Commenters stated that, commissioned in 2008, TSPP is one of the newest 
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coal- fired power plants in the country and has demonstrated some of the lowest emission rates 

for SO2, NOx, Hg and PM10 due to state of the art air quality control systems that include low 

NOx burners, over-fire air and selective catalytic reduction (SCR) for NOx control, powdered 

activated carbon mercury control system, spray dry absorber for SO2 removal, and a fabric filter 

baghouse for particulate control. 

Commenters stated that numerous efficiencies were incorporated into the design in order to 

achieve the lowest possible heat rate, which efficiencies make achievement of the 6% 

improvement in heat rate as proposed by Building Block 1 for TSPP unrealistic and 

unachievable. Commenters stated that TSPP has evaluated potential additional efficiencies and 

estimates that it can achieve, at most, a 1.5 percent heat rate improvement by installing a neural 

network. 

Commenters stated that the 6% heat rate efficiency improvement that the USEPA has utilized in 

the first building block is based on its review and interpretation of a report prepared by Sargent 

& Lundy in 2009, entitled Coal-Fired Power Plant Heat Rate Reductions. (2009 S&L Report, 

available at http://www.epa.gov/airmarkets/resource/docs/coalfired.pdf.). Commenters stated that 

the 6% heat rate improvement scenario is based largely on methods described in the 2009 S&L 

Report and incorporated in the GHG Abatement Measures TSO. Commenters stated the USEPA 

designated nine methods as best practices, representing a 4% improvement, and four additional 

methods designated as equipment upgrades with the potential for a 2% improvement in heat rate. 

Commenters presented Table 2 (lists the no and low-cost heat rate improvement options and the 

status of TSPP's current use of the option) and Table 3 (lists the higher-cost heat rate 

improvement options and the status of TSPP's current use of the option) which show the majority 

of these methods cannot be implemented by TSPP because they are either currently installed, 

currently being implemented, or not compatible with the plant's existing configuration. 

Commenters stated that as indicated, of the various methods described by the USEPA as 

justification for the Building Block 1 heat rate improvement , the majority are not applicable to 

TSPP because: (1) the proposed upgrade has already been incorporated into the TSPP designs; 

(2) as a new facility, age-related degradation of various components that would negatively 

impact heat rate has not occurred, making equipment replacements unnecessary; and (3) 

equipment designated for upgrades is not installed at TSPP. Commenters stated that in fact, of 

the thirteen methods included in the USEPA analysis, only one - installation of a neural network 

system - has the potential to improve heat rate at TSSP. Commenters stated that Section 2.3 of 

the 2009 S&L Report indicates that a neural network could improve heat rate by up to 1.5%, but 

may not result in an improvement at all. 

Commenters stated that they do not agree that 6% heat rate improvement is feasible at all coal 

units, especially those that have already upgraded turbines and other equipment. Commenters 

stated that they have upgraded HP, IP, and LP turbines at several units along with upgrading ID 

fans and fan drives, upgrading sootblowers, upgrading/replacing cooling tower fill, and replacing 

feedwater heaters. Commenters stated that they have also installed SCRs and/or FGDs on many 

coal units resulting in a 3-4% increase in heat rate (according to design) that can never be 

recovered. Commenters stated that when their Kingston Coal Plant added scrubbers, the unit heat 

rates increased by 4-6%. Commenters stated that increasing a unit's heat rate also increases the 

CO2 emission rate. Commenters stated that EPA should specify in its emission guidelines a 
467

methodology for including unit efficiency improvements in state plans. Commenters stated that 

the States should set efficiency improvement targets based on unit specific factors and costs 

including remaining useful life and previously-upgraded equipment, added environmental 

controls, and other factors. Commenters stated that an important factor is how dispatch

significantly impacts efficiency 

Commenters stated that HRI depends on EGU load levels and therefore a facility's average heat 

rate is lower when it is base-loaded than when it is load-cycled, resulting in less potential for 

achieving HRI. Commenters stated that thus, HRIs achieved at a specific unit by implementing 

the strategies discussed in the 2009 report could be negated if the unit shifts from being baseloaded to load-cycled, and that for these reasons, Sargent & Lundy believes that the only rational 

method for evaluating the technical feasibility and effectiveness of potential HRI projects is to 

conduct a unit-by-unit evaluation. Commenters stated that therefore EPA cannot reasonably rely 

on the 2009 S&L study to finalize any HRI targets without conducting a unit-by-unit analysis of 

all designated facilities to determine the extent to which HRI can be implemented at each. 

Commenters stated that it appears as though the EPA concluded that heat rate improvements

cited in the 2009 Report were additive and applicable to all coal-fired units. Commenters stated 

that heat rate improvement ranges described in the 2009 Report case studies were estimated at a 

conceptual level, and were not based on detailed site-specific analyses. Commenters stated that 

verification of actual heat rate improvements was not made to determine whether any of the 

strategies were implemented and what actual heat rate improvements were realized based on sitespecific design.

Commenters provided unit specific information to demonstrate that unit-by-unit audits may not 

support 6% HRI. Commenters described the results of an heat rate improvement audit for a total 

of five units that are located at "Station A" and "Station B" for members of "The National Rural 

Electric Cooperative Association" (NRECA) to demonstrate that unit-by-unit audits may not 

support 6% HRI. Commenters then summarized technical methods that were identified in the 

2009 Report for efficiency improvement and heat rate reductions described under the technology 

specific summaries and described what is documented in the S&L reports and the S&L analysis 

key assumptions for Station A and B units (what year the technologies were installed, what heat 

rate changes were observed, and if additional improvements would achieve further reductions in 

heat rate): 

Two units at Station A were audited as part of this study. Units A1 and A2 are supercritical 

pulverized coal units that are between 500-700 MWNET. Each unit is equipped with electrostatic 

precipitators (ESPs), selective catalytic reduction (SCR) systems, wet flue gas desulfurization 

(WFGD) systems, and dry sorbent injection (DSI). Commenters concluded for STATION A, 

Unit A1 or A2: 

• Unit A1 increased heat rate by 2.4% since 2000 due primarily to the installation 

of wet FGD and SCR systems. Future potential heat rate improvement is limited 

to 0.6%. 
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• Unit A2 increased heat rate by 1.81% since 2000 due primarily to the installation 

of wet FGD and SCR systems. Potentially 2.1% future heat rate improvement is 

available.

• Continuation of good maintenance and operating practices is necessary to 

maintain the units' heat rates that are made possible by improvements completed 

in the past. In addition, the units' heat rates at the time of the audit may not be 

sustainable if the units' loads or dispatch change.

Commenters stated that Station B includes a compilation of three units that were audited as part 

of this study. Unit B1, B2, and B3 are subcritical pulverized coal units that are between 300-600

MWNET. All three units are equipped with FGDs and baghouses. Commenters concluded for 

STATION B that no future potential heat rate improvement is available on Unit B1, B2, or B3:

• Unit B1 improved heat rate by 5.6% since 2000. No future potential heat rate

improvement is available. The net potential changes identified for Unit B1 will 

degrade heat rate by 0.9%.

• Unit B2 improved heat rate by 5.3% since 2000. No future potential heat rate 

improvement is available. The net potential changes identified for Unit B2 will 

degrade heat rate by 0.9%.

• Unit B3 improved heat rate by 1.97% since 2000. No future potential heat rate 

improvement is available. The potential changes identified for Unit B3 will 

degrade heat rate by 0.3%.

• Continuation of good maintenance and operating practices is necessary to 

maintain the units' heat rates that are made possible by improvements completed 

in the past. In addition, the units' heat rates at the time of the audit may not be 

sustainable if the units' loads or dispatch change. 

Commenters stated that past and future projects at their J.H. Campbell Plant, Unit #3 (JHC3) 

provide a good example of the above issues. Commenters stated that the JHC3 boiler underwent 

a dense pack high pressure turbine upgrade in the early to mid-2000's. Commenters stated that 

post turbine upgrade, JHC3 was rated at 820 MW with an auxiliary load of 31.5 MWs. 

Commenters stated that increasing blends of sub-bituminous coals occurred until the 2006 to 

2007 time frame, when a boiler modification project and concurrent installation of additional 

NOx control equipment was completed allowing up to a 100% sub-bituminous fuel mix, with the 

associated emissions control devices. Commenters stated that at this point the boiler was capable 

of 835 MW net, but had an associated auxiliary load of 46 MWs. This project resulted in a total 

heat rate penalty of 1.2%.

Commenters stated that in 2016, JHC3 will undergo major air quality control equipment 

upgrades associated with MATS compliance. Commenters stated that installed equipment will 

include a spray dry absorber for flue gas desulfurization, a pulse jet fabric filter for particulate 

matter, and activated carbon injection for mercury control and this new equipment will also 

require new Induced Draft (ID) fans. Commenters stated that as a result, the total auxiliary load 
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will increase greatly and it is estimated that auxiliary power will increase to 78 MW when the 

emissions control equipment is complete. Commenters stated that this will reduce net generation 

from 835 MW to 807 MW and will be a heat rate penalty of 3.8%. Commenters stated that to 

offset as much of the increase auxiliary power as possible, the low pressure (LP) section of the 

steam turbines will also be upgraded in 2016. Commenters stated that this project is expected to 

recover 26 MW of the 32 MW increase in auxiliary power and will reduce the 3.8% heat rate 

penalty to a heat rate penalty of 0.7%.

Commenters stated that at the conclusion of the MATS project, JHC3 will have an overall net 

heat rate penalty, as compared to a pre-2012 baseline, and will have exhausted those upgrade 

options which offer the largest opportunities for heat rate improvement. Commenters stated that 

the CPP proposed Building Block #1 does not account for the MATS requirements and the 

significant heat rate penalty associated with additional emission control equipment.

Commenters stated that EPA does not account for natural degradation of operating equipment in 

the Building Block #1 analysis and provided a Figure (Fig 1 - maps % heat rate deterioration) 

showing the turbine degradation curve provided for the JHC3 turbines by the Original 

Equipment Manufacturer (OEM). Commenters stated that using the "Most Probable" degradation 

curve, it shows a heat rate penalty of 1% over four years of operation. Commenters stated that 

this is the degradation associated with turbine efficiencies only and does not include balance of 

plant auxiliary loadings.

Commenters stated that using the JHC3 example, the CPP proposal of a 6% heat rate 

improvement, from a 2012 baseline, would also need to account for the ~ 1% heat rate penalty 

associated with requisite MATS emissions control equipment as well as natural degradation 

estimated to be another 1% over 4 years. Commenters stated that properly accounting for these 

factors, the 6% heat rate improvement actually amounts to almost 8% by 2020; and that is after 

major turbine efficiency projects had already taken place. Commenters stated that achieving the 

Building Block #1 heat rate improvements at JHC3 is not feasible at this time. 

Commenters stated that opportunities for increasing the energy efficiency of the existing coalfired units are very limited because of past successful efficiency improvement efforts. 

Commenters stated that Healy Unit 1 has been in operation for the past 47 years and throughout 

this period, they have undertaken numerous actions to help reduce station service energy 

consumption and improve the plant heat rate, including

• Installation of Variable Frequency Drives on large motor pump/fan trains;

• Lighting system upgrades to CFB and LED lighting;

• Condenser retubing for increased efficiency which allowed for water circulation 

to move from a two pump operation to a one pump operation;

• Automated soot blowing controls upgrade;

• PI data analysis system monitoring over 3,000 points in the plant, enabling "real 

time" monitoring of systems;
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• Coal pulverizer flow and balance studies to improve boiler combustion;

• High efficiency baghouse bag replacement that reduced ID fan back pressure;

• High efficiency plant air compressors;

• Steam turbine seal upgrades; and

• Economizer tube replacement upcoming in 2015.

Commenters stated that while station service energy consumption can be reduced as new 

products are brought to the market and techniques are developed and made available, additional 

substantial reductions in station service energy consumption are not readily available at this time.

Commenters stated they completed a high level review of the best practices and equipment 

upgrades suggested by EPA in the Sargent and Lundy "Coal-Fired Power Plant Heat Rate 

Reductions Final Report" dated January 22, 2009. Commenters stated some of the 

upgrades/activities identified by Sargent & Lundy have already or will be implemented at Healy 

Unit 1 and Healy Unit 2, however, the units evaluated by Sargent & Lundy have a much larger 

capacity (hundreds of MW) compared to Healy Unit 1 and Healy Unit 2 and as a result, the 

suggested upgrades/activities will likely not have the same level of heat rate improvement for the 

much smaller capacity Healy units. Commenters stated they anticipate heat rate improvement for 

both units will be approximately 2 percent with the implementation of future upgrades. 

Commenters stated that however, a projected 2.87 percent increase (degradation) in heat rate will 

occur after the installation of SCR on Healy Unit 2. Commenters stated for Alaska CO2 

Performance Goal calculation purposes, EPA must recalculate the goals using a realistic overall 

1 percent heat rate improvement for both units. 

Commenters stated that the uniform methodology used by EPA in arriving at its six percent heat 

rate improvement target cannot be applied to every unit in the country without consideration of 

each unit's characteristics, and in fact, many of the efficiency improvements necessary to meet 

such a goal have already been applied or installed at their coal-fired plants. Commenters stated 

that this applies to both best practices for operation/maintenance and equipment upgrades, the 

means by which EPA suggests to reduce heat rate. Commenters stated that accordingly, a 

"uniform" methodology is not appropriate for setting realistic efficiency improvement goals for 

each state/utility.

Commenters stated that they have already completed turbine overhaul projects on most of its 

units and this improvement opportunity is not available and this highlights a fundamental flaw in 

EPA's one-size-fits all proposal; the amount of heat rate improvement available on each unit, and 

hence the improvement available in each state, can vary significantly based on numerous factors 

including what efficiency improvements have already

been made.

Commenters stated that in the TSD (Table 2-13), EPA breaks up the projects in the Sargent & 

Lundy report into two categories: "best practices" and "equipment upgrades." Commenters stated 

that they ready perform many of the "best practices" provided in the report and in addition, 

several of the "best practices" projects are not applicable to any of their units. Commenters 
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presented Table 1 "Best Practices" from the Sargent & Lundy report and their applicability to 

their coal-fired fleet.

Commenters stated that further, many equipment optimizations purported to reduce heat rate are 

only relevant to large wall fired boilers burning eastern bituminous coals, rather than tangentially 

fired boilers (T-fired) burning sub-bituminous PRB coal (most of their coal fleet). Commenters 

stated that these items include changes to: air in leakage, pulverizer performance, air flow, 

balance of air and fuel flows, air heater leakage, reheater sprays, reheater steam temperature, 

superheat spray, superheat temperatures, and carbon in ash. Commenters stated that while 

optimization of these parameters is important, improvements in these areas simply are not 

possible due to the design of boilers.

Commenters stated that their boiler efficiencies are generally at or very near design efficiencies 

when changes due to fuel switching from original design bituminous coals to currently burned 

subbituminous coals are taken into account. 

Commenters stated that air in-leakage primarily impacts auxiliary power requirements by 

increasing fan loading and by itself does not have a major impact on efficiency (net MWs). 

Commenters stated that excessive air in-leakage can impact slagging and fouling within the 

boiler, which can in turn affect steam temperature and sprays and other parameters. Commenters 

stated that air heater leakage has a similarly small impact on efficiency as it is mainly an impact 

on auxiliary power from fan loading. Commenters stated that air heater leakage will not impact 

slagging or fouling and its impact on unit efficiency is relatively small.

Commenters stated that they maintain their pulverizers on regular outage intervals and 

performance measurements are regularly monitored. Commenters stated that likewise, they do 

not routinely experience slagging and fouling in the boiler that adversely impacts steam 

temperatures, spray flows, or other performance parameters. Commenters stated that this is a 

result of proper sootblowing, installing additional sootblowers as required, good combustion 

optimization, along with boiler components designed to minimize slagging and fouling impacts.

Commenters stated that generally speaking, steam temperatures on their boilers are at design 

with minimal or expected spray flows. Commenters stated that no boiler that operates at design 

steam temperatures has zero spray flow and also, it would be rare for a boiler to have high spray 

flows and low steam temperatures because if temperatures were low, spray flows would be 

reduced until temperatures were at design and as a result, there are little or no efficiency gains to 

be realized on their boilers in the area of steam temperatures or spray flows.

Commenters stated that for optimization, air flow and the balance of air and fuel flows impact 

the combustion process directly and impact the carbon in the ash. Commenters stated that carbon 

in the ash is a direct loss on boiler efficiency. Commenters stated that CO2 emissions from the 

boiler can act as an indicator of poor combustion and possible higher carbon in ash. Commenters 

stated that they use neural net optimizers on most of their units to continually optimize the 

combustion process with the goal of lower NOx, while at the same time, maintaining reasonable 

CO2 emissions. Commenters stated that for T-fired units, carbon content in fly ash is usually less 

than 0.5%, which means the efficiency loss for carbon in ash is less than 0.1%. Commenters 
472

stated that this is due not only to optimization, but also to the PRB coal that has a high volatility 

and burns more readily.

Commenters stated that in summary, they do not believe that significant additional efficiency 

improvements can be yielded from combustion optimization and actual losses from the 

parameters relied upon by EPA are inconsequential for their units, on the order of perhaps 0.5%, 

and better than most other utility boilers. Commenters stated that this is in part due to the design 

of the boilers, the fuel burned, and the continual neural net combustion optimization they

employ. Commenters stated that only some portion of this actual loss could be recovered and 

doing so would be extremely expensive. Commenters presented a table ("Potential Efficiency 

Improvements at their Facility by Plant") listing projects that may result in additional, but 

modest, heat rate improvement.

Commenters stated that more generally, this technical discussion illustrates their contention that 

EPA's heat rate improvement projections are not achievable and thus, EPA's assumption that coal 

units can achieve a 6% reduction in carbon emissions via heat rate improvements is 

demonstrably wrong. Commenters stated that for the same reasons, EPA's alternative of 4% is 

also wrong. Commenters stated that they have invested a tremendous amount of capital to ensure 

that it is operating at an optimal efficiency because this approach is not only good for the 

environment - it is good for business. 

Commenters stated that EPA does not seem to recognize the impact of security constrained 

economic dispatch on organized wholesale power markets like ERCOT (Electric Reliability 

Council of Texas). Commenters stated that specifically, EPA's Block 1 assumes that "best 

practices" have not already been implemented at coal-fired units in Texas, however, economic 

signals and competitive pressures inherent to the ERCOT market have already motivated coalfired generators to adopt state of the art operational strategies and technologies available to 

improve thermal efficiencies in order to compete effectively. Commenters stated that ERCOT's 

competitive market has in effect already been implementing this aspect of "building block 1" for 

over a decade, specifically, due to the competitive economic nature of the ERCOT market, FPP 

has already identified and implemented "best practices to reduce hourly heat rate variability." 

Commenters stated that Florida utilities, including their plant have already taken steps to 

improve heat rates and optimize the efficiency of their fossil fuel-fired generating units. 

Commenters stated that their plant as well as other Florida utilities cannot realize EPA's 

estimated gains from heat rate improvements. Commenters stated that as an example, they

undertook a major turbine efficiency improvement in 2008 that decreased a unit's heat rate by 

two percent and which cost approximately $5 million. Commenters stated that no more can be 

done to that unit to improve its heat rate, at any cost, and stated that the unit would have to be 

completely replaced. 

Commenters referred to the following study: Sargent & Lundy Unit Heat Rate Improvement 

Study At Springerville Generating Station. Commenters provided the executive summary of this 

study conducted by Sargent & Lundy examining the possibility for Unit Heat Rate Improvement 

At Springerville Generating Station in Arizona. Commenters stated that this study compares 

EPA's claims of heat rate improvement of 6% at an average power plant with a detailed study of 
473

the actual heat rate improvements deemed possible at the four EGUs at the Springerville 

Generating Station:

Sargent & Lundy Executive Summary (November 14, 2014). On June 18, 2014, 

the United States Environmental Protection Agency (EPA) published the "Carbon 

Pollution Emission Guidelines for Existing Stationary Sources: Electric Utility 

Generating Units; Proposed Rule" in the Federal Register. (79 Fed. Reg. page 

34830). The proposed rule does not set emissions standards for individual 

sources, but provides guidelines for states to follow in developing plans to address 

greenhouse gas (GHG) emissions from existing sources. Specifically, the EPA 

proposed to establish state-specific rate-based (or mass-based) goals for carbon 

dioxide (CO2) emissions from the power sector, including existing fossil fuelfired electric generating units (EGUs). Proposed emission goals vary from state to 

state.

The EPA's proposal includes four building blocks to lower GHG emissions from 

power plants. To establish each state's rate-based CO2 emissions goal, the EPA 

concluded that "a six percent reduction in the CO2 emission rate of the coal-fired 

EGUs in a state, on average, is a reasonable estimate of the amount of heat rate 

improvement that can be implemented at a reasonable cost." (79 FR 34861). Heat 

rate improvements that may be achieved by adopting best practices and 

equipment improvements were based in part on EPA's review and interpretation 

of a report, titled "Coal-Fired Power Plant Heat Rate Reductions" prepared by 

Sargent & Lundy in 2009 for the EPA (hereafter referred to as the "2009 

Report").

The purpose of the 2009 Report was to identify various methods that have been successfully 

implemented in the industry to reduce the heat rate of existing U.S. coal-fired power plants. For 

each alternative, S&L quantified the potential heat rate improvement that may be achieved at a 

200, 500, and 900 MW coal plant. The 2009 Report also provided two conceptual level case 

studies: one for a 250 MW unit and the second for an 850 MW unit, to provide examples of how 

heat rate improvement projects would be implemented and to identify some of the site-specific 

technical issues that would need to be taken into consideration.

Heat rate improvements described in the 2009 Report case studies were estimated at a conceptual 

level, and were not based on any site-specific detailed analysis. In addition, verification of actual 

heat rate improvements was not made to determine whether any of the changes were 

implemented and what actual heat rate improvements were realized based on detailed design. 

Furthermore, the case studies showed that it would not be feasible to apply all of the examined 

alternatives from the study to an individual generating unit due to a number of factors including 

plant design, previous equipment improvements, and operational approaches.

Based on information provided in the 2009 Report, "EPA estimated that for a range of heat rate 

improvements from 415 to 1205 BTUs per kWh, corresponding to percentage heat rate 

improvements of 4 to 12 percent for a typical coal-fired EGU, the required capital costs would 

range from $40 to $150 per kW." (79 FR 34861)1 However, based on a review of the 2009 

Report, as well as a review of EPA's Goal Computation Technical Support Document, it is 
474

apparent that EPA misapplied information presented in the 2009 Report when it calculated heat 

rate improvements of 415 to 1205 Btu/kWh and 4 to 12 percent.

It appears EPA assumed heat rate improvements cited in the 2009 Report were additive and 

applicable to all coal-fired units, when the 2009 Report makes it clear that it would not be 

feasible to implement all of the examined alternatives to achieve the sum total of their heat rate 

improvements. Furthermore, the 2009 Report does not state any range of overall heat rate 

improvements that could be expected from implementing any combination of the examined 

alternatives. In fact, the case studies provided in the report estimated potential heat rate 

improvements of 4% and 1.2% for the 250 MW and 850 MW units, respectively. Contrary to the 

approach used by EPA, heat rate improvement opportunities, and the associated costs, must be 

evaluated on a case-by-case basis taking into consideration unit-specific design, operations, and 

controls.

The purpose of this engineering study is to review the potential heat rate improvement strategies 

identified in S&L's 2009 Report and assess their feasibility to improve heat rate for the four units 

at Springerville Generating Station (SGS).

In both the 2009 Report and EPA's proposed regulation for GHG emissions for existing 

stationary sources, the areas of a power plant where efficiency improvement and heat rate 

reduction may be possible are:

• Boiler Island

• Turbine Island

• Flue Gas System

• Air Pollution Control Equipment

• Water Treatment System

This study identifies systems and equipment at Springerville Units 1, 2, 3, & 4 where efficiency 

improvements can be realized. This study also provides estimates of the resulting net plant heat 

rate reductions and the order-of-magnitude costs for implementation. To conduct this evaluation, 

S&L reviewed equipment data manuals, system description manuals, plant data, test reports, and 

documents received from the client for each of the units.

It should be noted that the scope of this report does not include any detailed design work. Should 

TEP implement any of the technologies identified as potentially improving heat rate at any of 

their SGS units, detailed design work may reveal limitations in either the applicability of the 

technology or limitations on the achievable heat rate reduction.

For each unit, two numbers were estimated based on this evaluation (1) percent change in heat 

rate achieved to date from original designed based on past repairs and (2) potential future percent 

improvements in heat rate. The following tables summarize these changes for Springerville Units 

1, 2, 3, and 4. Negative values listed in the tables are considered to be improvements in the unit's 

heat rate while positive values represent penalties in heat rate.
475

Commenters provided four data tables showing the Heat Rate Improvement area, % Change 

Achieved to Date, and the Potential % to Change for these four units 

• Table ES-1 - Summary of Heat Rate Changes for Unit 1 (Achieved to Date and Potential)

• Table ES-2 - Summary of Heat Rate Changes for Unit 2 (Achieved to Date and Potential)

• Table ES-3 - Summary of Heat Rate Changes for Unit 3 (Achieved to Date and Potential)

• Table ES-4 - Summary of Heat Rate Changes for Unit 4 (Achieved to Date and Potential)

Commenters stated that the interim and final goals proposed by EPA for the State of Arizona are 

735 lb/MWh (net) and 702 lb/MWh (net), respectively. 79 Fed. Reg. at p. 34,957. Commenters 

stated that alternative interim and final goals proposed by EPA for the State of Arizona are 779 

lb/MWh (net) and 763 lb/MWh (net), respectively. 79 Fed. Reg. at p. 34,898. Commenters stated 

that EPA's computation of these goals assumes that the entire fleet of twelve coal-fired EGU's in 

Arizona will be shut down (i.e., zero MWh of generation and zero tons CO2) before January 1, 

2020. Commenters stated that this includes three units owned by SRP - Units 1 and 2 at the 

Coronado Generating Station and Unit 4 at the Springerville Generating Station - so EPA's 

proposal is of particular concern to SRP.

Commenters stated that because EPA's goal calculation assumes their shutdown, heat rate 

improvements purportedly achievable at coal-fired EGU's in Arizona, under "building block 1," 

do not affect the goals proposed by EPA. Commenters stated that nonetheless, assuming that 

EPA corrects its clear errors regarding achievability and reasonableness of CO2 emission 

reductions through dispatch changes among affected EGU's under "building block 2," SRP 

requested that RTP prepare this analysis. Commenters stated that this memorandum describes 

EPA's numerous invalid assumptions and erroneous conclusions regarding heat rate 

improvements purportedly achievable at coal-fired EGU's in Arizona.

Commenters stated that EPA's computation of the proposed interim and final goals for the State 

of Arizona assumes a six percent improvement in heat rate before January 1, 2020, is achievable 

for the fleet of twelve coal-fired EGU's in Arizona. (See, docket item EPA_HQ_OAR-2013-

0602-0255.xlsx, "Appendix 1," at cells L5 and AQ5.) Commenters stated that based on these 

purportedly achievable improvements in heat rate, EPA concludes the generation-weighted 

average CO2 emission rate of the fleet of twelve coal-fired EGU's in Arizona will decrease from 

2,268 lb/MWh in 2012 to 2,132 lb/MWh in 2020. (See, docket item EPA_HQ_OAR_2013-0602-

0255.xlsx, "Appendix 1," at cells B5 and L5.) Commenters stated that similarly, EPA's 

computation of the proposed alternative interim and final goals for the State of Arizona assumes 

a four percent improvement in heat rate before January 1, 2020, is achievable for the fleet of 

twelve coal-fired EGU's in Arizona. (See, docket item EPA-HQ-OAR-2013-0602-0255.xlsx, 

"Appendix 2," at cells L5 and AG5.) Commenters stated that based on these purportedly 

achievable improvements in heat rate, EPA concludes the generation-weighted average CO2 

emission rate of the fleet of twelve coal-fired EGU's in Arizona will decrease from 

2,2681b/MWh in 2012 to 2,177lb/MWh in 2020. (See, docket item EPA-HQ-OAR-2013-0602-

0255.xlsx, "Appendix 2," at cells B5 and L5.)

Commenters stated that EPA's assumptions regarding achievability of four to six percent 

improvement in heat rate across the fleet of twelve coal-fired EGU's in Arizona are based on 

underlying assumptions regarding "improvements that could be achieved by reducing heat rate 
476

variability ... through adoption of best practices for operation and maintenance" and regarding 

"improvement[s] that could be achieved through further equipment upgrades." 79 Fed. Reg. at p. 

34,860. Commenters stated that these underlying assumptions are invalid, leaving EPA's 

assumption regarding the achievable improvement in heat rate across the fleet of twelve coalfired EGU's in Arizona clearly erroneous and entirely without foundation.

Commenters stated that these errors are so fundamental to EPA's entire rationale for its "system," 

that EPA's proposal is legally flawed because EPA has not substantiated that a heat rate 

improvement "has been adequately demonstrated" at the levels claimed. Commenters stated that 

they disagree with EPA's legal interpretation that it has authority to specify the level of emissions 

reductions achievable through the "best system," but even if EPA's interpretation were proper, 

before EPA could require States to consider any specific level of heat rate improvement in their 

plan submissions, EPA must provide an opportunity for public comment on a corrected analysis 

of the emissions reductions achievable through heat rate improvements.

3.1.5 Heat rate improvement - economics 

This section discusses the economics costs, and applicability commenters believe are related to 

heat rate improvements at existing coal-fired EGUs.

Commenters have raised a number of issues related to this subsection which are organized by 

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

Comment 1: General comments regarding HRI - Economics

Response 1: The response to comments regarding costs of this rule overall is addressed in 

section 8.0. For EPA’s response to the remainder of these comments, see sections V.A and V.C

of the final rule preamble of the CPP, and Chapter 2 of the GHG Mitigation Measures TSD 

supporting the final CPP. For example, as discussed in the preamble and TSD, the EPA’s 

assessment of the costs of many heat rate improvement measures is conservative.

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

Commenters stated that even if EPA had authority to regulate these pieces of equipment under 

Section 111, its technical conclusions are erroneous. Commenters stated that as discussed by 

UARG's consultants, J. Edward Cichanowicz and Michael Hein, the Agency does not account 

for the fact that the efficiency benefits associated with the measures identified in the Sargent & 

Lundy report are highly variable by unit, are not cumulative, and are only temporary. 

Commenters stated that large benefits from steam turbine upgrades (the highest payoff measure) 

are only possible for units that are already severely degraded; for most units, the available 

payoffs would lie at the low end of the possible range. Commenters stated that many of the

available heat rate improvements for which the efficiency benefits outweigh the costs have 

already been implemented by EGU owners for economic reasons and would not yield substantial 

benefits if they were implemented again.
477

Commenters stated that the costs to improve heat rate are unit-specific; factors that may affect 

the costs include the age of the unit, its location, its condition, and whether asbestos removal is 

required. Commenters stated that the economy of scale also plays a role, as the expenditures are 

more easily justified for larger units with higher capacity factors.

Commenters stated that the cure for EPA's approach to cost estimates is to eliminate reliance on 

the national average and to embrace standard cost evaluation practices. Commenters stated that if 

elaborate calculations from an extensive dataset must be made, they should include more 

accurate fuel cost data, some of which is available from the FERC Form 1.

Commenters stated that in contrast to EPA's assertion, a six percent heat rate improvement is 

unrealistic and unachievable for most coal-fired plants and, to the extent that some heat rate 

improvements may be available, the costs of implementing these upgrades at affected units 

would generally be prohibitive and could trigger onerous New Source Review permitting 

requirements.

Commenters stated that EPA's approach serves to potentially require costly additional equipment 

upgrades and practices at units for utilities that chose to maximize efficiency early on, serving to 

disincentivize early action and increase rates disproportionate to utilities that chose to do 

nothing. 

Commenters stated that their Missouri generation facilities already have implemented 

improvements and best practices that have significantly improved efficiency and additional 

improvements to eke out minute efficiency increases of 1% or 2% would be extremely 

expensive. 

Commenters stated that a cost-benefit study would need to be conducted for each specific coalfired unit to determine if any achievable heat rate improvements can be economically justified. 

Commenters stated that a 6% heat rate improvement target is not reasonable for smaller 

generating units. Commenters stated this is both a consequence of how small units don't carry the 

economy of scale that helps keep cost per unit of electricity output affordable and due to the 

manufacturers of heat rate improvement equipment not offering "off the shelf" components for 

small units. Commenters stated that customizing equipment to accommodate small unit-specific 

requirements adds to cost, if such equipment is available at all. 

Commenters stated that as EPA notes in its Abatement Measures TSD, the costs associated with 

the Block 1 HRI will not be exorbitant, particularly in light of the fact that the fuel savings 

associated with increased EGU efficiency will offset these costs in considerable part. 

Commenters recommended improvements to Building Block 1 will not alter this picture 

dramatically and demonstrated that units will be able to improve their heat rates by at least six 

percent (as opposed to EPA's predicted four percent) through operating and maintenance 

techniques, which are associated with very low costs. Commenters stated that while equipment 

upgrades are more expensive than operating and maintenance modifications, EPA's analysis 

shows that these costs are still well within the range of what is reasonable. Commenters believed 

that the agency has overestimated the extent to which the nation's coal plants have already 

implemented some of these upgrades (in particular turbine blade replacements); commenters 
478

expect that units can achieve a four percent (as opposed to two percent) HRI improvement 

through those measures. Commenters stated that while this may yield marginally higher 

aggregate costs than EPA's predictions, they are nonetheless economically reasonable and will 

produce greater savings in conserved fuel. 

Commenters stated that U.S. EPA cites "the cost of CO2 emission reductions achievable through 

heat rate improvements is quite low, and that cost would remain reasonable even if it was 

substantially increased." Commenters disagreed and stated that U.S. EPA's assumption regarding 

the cost-effectiveness of HRIs is primarily based on units being able to achieve the more costeffective "maintenance type" HRIs. Commenters presented comments in regards to the HRIs, 

and stated that Ohio's fleet will be a well-controlled, well-maintained and efficient fleet after the 

post-MATS shutdowns occur. Commenters stated that cost-effective HRIs will not provide 

additional benefit in Ohio as much of these actions have already occurred. 

Commenters stated that the one of key concerns regarding the ability of New Hampshire to 

achieve the CO2 emission rate proposed by the EPA in the CPP is that the commenters already 

invested in cost-effective heat rate improvement projects for their fossil-fueled EGU fleet, and 

cannot expect to see substantial increases from future improvements without significant costs.

Commenters stated that the incremental cost of improving heat rates further may be significantly 

higher for generating units that have accomplished some heat rate improvements in the past. 

Commenters stated that this may result in higher costs for customers of utilities that have 

implemented heat rate improvements in the past. 

Commenters stated that the finance requirements of electric generation facilities require that any 

large investment be justified as contributing toward improved performance as well as 

profitability. Commenters stated the smaller and/or older units operate less frequently often 

making a reasonable return on investment difficult to achieve for expensive modifications. 

Commenters stated that these units may have a limited remaining life and under these 

circumstances, costly HRI may require a longer time to recover the investment than the facility's

useful life. 

Commenters stated that costs can be reduced for users, because efficiency can be so high, simply 

by modernizing the controls.

Commenters said when capital investments (i.e. HRIs) are made in merchant markets, investors 

carefully consider whether the forward looking revenues will cover the costs of the investment.

Comment 2: Applicable to the supplemental proposal for Tribal and Territorial - IPM specific 

comments

Response 2: See section V.C. of the final rule preamble of the CPP and Chapter 2 of the GHG 

Mitigation Measures TSD supporting the final CPP for EPA’s response to this comment.

The following are summaries of the specific public comments under this comment:
479

Commenters stated that Building Block One presumes that coal-fired power plant owners are not 

sufficiently motivated to improve heat rate absent a CO2 rule, such as the Proposed Rule. 

Commenters stated that if, however, 4% fuel savings are in fact available at no or low cost 

through "best practices," as EPA concluded in its statistical analysis, what is preventing power 

companies from deploying them? Commenters questioned what obstacles prevent such easily 

deployable methods that yield a large improvement in fuel cost from taking place. Commenters 

questioned if the report Sargent & Lundy prepared for EPA and that EPA relies upon for this rule 

documents the investments plants make to improve heat rate, doesn't this report suggest that 

utilities are already pursuing whatever investments can be justified and will not trigger 

NSR? Commenters stated that these are questions worth exploring with EPA's policy analysis 

tools. Commenters stated the implication is very significant for this rule because if power plant 

owners have already implemented most of the heat rate improvements that EPA relies upon for 

Building Block One it will not be possible to achieve the heat rate improvements that are called 

for in the Proposed Rule. 

Commenters provided a recommendation regarding evaluation of the reasonableness of 

assumptions using EPA's policy analysis tools and stated that EPA should explore the 

reasonableness of its assumptions using its policy analysis tools. Commenters stated it is possible 

to evaluate to what degree power plant owners are already motivated to pursue heat rate 

improvements with the Integrated Planning Model ("IPM") while running the Base Case (no 

Proposed Rule) with an assumed heat rate reduction and assumed cost (i.e., 6% heat rate 

reduction at a capital cost of $100/kW). Commenters stated if IPM modeling predicts that, absent 

the Proposed Rule, heat rate reductions are selected by a large number of units likely to remain in 

operation, it would appear that most of the low-cost heat rate improvement opportunities that 

EPA relies upon for Building Block One may have already been realized and further reductions 

for heat rate improvement will not be as great as EPA's analysis for the Proposed Rule suggests. 

Commenters stated that EPA must assume the coal-fired EGUs listed in Table 7 will be 

operating past 2020 in applying both building blocks 1 and 2. Commenters stated that in 

addition, specific corrections to the IPM model are marked in Table 7, presented by the 

commenters. Commenters noted that the coal-fired EGUs that EPA should assume will continue 

operating past 2020, with specific corrections to IPM model results are marked "*". 

Comment 3: Comments regarding concerns that HRI will make EGUs more economically

competitive and thus increase their dispatch—i.e., the "rebound effect"

Response 3: For the EPA’s response to these comments, see sections V.A and V.C of the final 

rule preamble of the CPP.

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

Commenters stated that the issue of "rebound" whereby heat rate improvements would cause 

increase in utilization of coal- fired capacity, though cleaner with respect to CO2 intensity, 

should only be a concern for emissions with acute local effects such as mercury and ozone. 

Commenters stated that acknowledging that "climate change" is a global phenomenon with 
480

extraordinary political, social, and economic ramifications, focus on the controls of CO2 should 

be on cost effective reductions overall. Commenters stated that with a proposed regulation that 

purports to allow regional controls, and considering that electrical demand is finite on any given 

day, cost effective cleaner power from coal should be an objective. Commenters noted as an 

example, an 800 MWe unit in Pennsylvania that decreases heat rate by 500 BTU/kwh thereby 

causing an increase in utilization of 5% implies a more marginal unit in Kansas has decreased its 

output of otherwise higher CO2 intensity emissions. Commenters stated that there is a net benefit 

relative to CO2 emissions, at lower marginal cost. 

Commenters stated that improving the fossil units with respect to heat rate will make them more 

economically competitive and many existing coal units will increase in dispatch. Commenters 

stated that this is an undesired effect under EPA's proposal and EPA refers to it as the "rebound" 

effect. Commenters stated that EPA proposes to force the improved units to reduce in dispatch 

by various means and again, there is little reason to improve heat rate under these rules which 

reduce coal dispatch on the remaining units by some 26% which takes away the incentive for 

generators to make such improvements, and clearly makes the case of EPA's effort to force the 

interconnected electrical system into environmental dispatch and away from market dispatch, 

which is clearly opposed to the Clean Air Act and beyond EPA's authority. Commenters stated 

that if we examine the current economic market model, as acknowledged by EPA, coal is the 

base load system with typically capacity factors between 65 and 70% and NGCC currently runs 

at an average capacity factor of 46%. Commenters stated that this reflects the economic/cost 

dispatch. Commenters stated that should they further improve the coal fleet in efficiency (also 

then improving their cost of generation), clearly the role of coal should move to higher capacity 

factors thus making the EPA goal of increased operation of gas more difficult. Commenters 

stated that it should be noted that this is the case in the current low gas price scenario and even 

EPA does not project gas prices to ever be lower. Commenters stated that thus EPA needs to 

invoke the environmental dispatch which makes upgrading of coal an effort with no return. 

Commenters stated that EPA recognizes that improving a unit's heat rate likely will mean that 

such a unit is more economical to operate and normally this would result in that unit being called 

upon to generate electricity before other, more costly, alternatives. Commenters stated that this 

reflects the economic cost of dispatch and should coal fleet efficiency improve (also lowering the 

cost of generation), coal-fired plants should move to higher capacity factors thus making the 

EPA goal of increased operation of NGCCs more difficult. Commenters stated that the Agency 

refers to this normal economic selection as the "rebound effect" and proposes through 

implementation of Building Block 2 to reduce the dispatch of coal-fired units, thus, there is little 

economic justification to improve the heat rate of coal-fired units under these proposed rules. 

Commenters said it is unrealistic to assume that an EGU will spend money on a HRI project and 

then utilize the EGU less. Commenters said it appears that EPA simply discounts this as a 

potential issue, concluding that the rebound effect would only be a concern if the rule were 

contemplating only HRIs. Commenters said the agency concludes that the rebound effect can 

simply be addressed by establishing BSER as a combination of approaches, such as demand side 

actions and an increase in renewable generation; however, that view can only be supported by an 

assumption that a state utilizes all of the building blocks. 
481

Commenters stated issue of "rebound" whereby HRIs would cause increase in utilization of coalfired capacity, though cleaner with respect to CO2 intensity, should only be a concern for 

emissions with acute local effects, such as mercury and ozone. Commenters said acknowledging 

that "climate change" is a global phenomenon with extraordinary political, social, and economic 

ramifications, focus on the controls of CO2 should be on cost effective reductions overall. 

Commenters added with a proposed regulation that purports to allow regional controls, and 

considering that electrical demand is finite on any given day, cost effective cleaner power from 

coal should be an objective. Commenters provided an example, an 800 MWe unit in 

Pennsylvania that decreases heat rate by 500 BTU/kwh thereby causing an increase in utilization 

of 5% implies a more marginal unit in Kansas has decreased its output of otherwise higher CO2 

intensity emissions. Commenters said there is a net benefit relative to CO2 emissions, at lower 

marginal cost

Commenters said those coal-fired EGUs that are able to achieve additional HRI may then be 

positioned for more frequent dispatch. Commenters said EPA's proposal discusses the situation 

where EGU output increases due to the "rebound effect" from improvements in heat rate at 

individual EGUs.

Comment 4: Comments regarding unrealistic heat rate improvements forcing units to retire or be 

rendered uneconomic

Response 4: The response to comments regarding reliability is addressed in section 8.0. For the 

EPA’s response to these comments, see section V.C of the final rule preamble of the CPP and 

Chapter 2 of the GHG Mitigation Measures TSD supporting the final CPP. Among other things, 

those documents explain that with respect to concerns about individual EGUs or groups of 

EGUs, the final CPP provides states the flexibility to develop plans with emission standards that 

more precisely take into account the potential heat rate improvement of individual EGUs—

should states desire to consider potential heat rate improvement at all. Furthermore, if an affected 

EGU cannot meet the particular emission standard solely because it has below-average potential 

to reduce emissions through heat rate improvements, then in instances where the EGU’s state 

plan allows emissions trading, the EGU can acquire credits or allowances from affected EGUs 

that have above-average potential.

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

Commenters stated that under Building Block 1, the EPA assumes that New York's coal-fired 

EGUs can improve (lower) their heat rates by 6% - a rate deemed by the EPA to be feasible 

nationwide. Commenters stated that New York's market structure, as well as the requirements of 

RGGI, already provide strong incentives for existing EGUs to improve operations and lower 

their heat rates in order to increase their profitability. Commenters stated that accordingly, New 

York generators have already made significant improvements in their heat rates and, were further 

heat rate improvements reasonably attainable, generators would have made them. 

Commenters stated that market forces are already driving down the utilization of coal-fired 

EGUs, which are a diminishing portion of the generation mix in New York. Commenters stated 
482

that in 2005 they produced 21,184 GWh, or 14% of the total output of the New York fleet; in 

2013, this had shrunk to just 4,494 GWh or 3% of total output. Commenters stated that there are 

six coal-fired EGUs still operating in New York and three of these are operating under 

Reliability Support Service Agreements, as their continued operation has been determined to be 

necessary to address local reliability issues. Commenters stated that these arrangements are 

necessary because, even though their operation is critical, they are not cost-effective to operate 

without a special compensation agreement to keep them available. Commenters stated that plans 

are in place to retire one of these units, and the New York Public Service Commission is 

considering options to address the reliability issues related to the other two of these coal-fired 

units.

Commenters stated that as New York's coal-fired units have run less in recent years, their heat 

rates have predictably increased. Commenters presented Figure 1 (titled: “NY Coal Fleet and 

Heat Rate Capacity Factor”) which demonstrates that New York's coal fleet has experienced a 

drop in its capacity factor and a corresponding increase in its heat rate as its percentage of the 

fleet's capacity has declined.

Commenters stated that coal-fired EGUs with low capacity factors operate at higher average heat 

rates as they cycle to meet peak demand and as the EPA explains, EGUs operate at higher heat 

rates during periods of startup and shutdown. Commenters stated that when reduced demand for 

a fossil-fuel fired unit results in a lower capacity factor, heat rate improvements would be 

possible only by forcing their capacity factor higher through scheduling the unit to operate even 

when it is uneconomic to do so. Commenters stated that this would be illogical and 

counterproductive, however, as it would actually increase the unit's total CO2 emissions and 

require the unit to operate at an economic deficit. 

Commenters stated that moreover, the further decline in operation of New York's coal fleet that 

would necessarily result from the assumptions in Building Block 2 would render any heat-rate 

improvement even less plausible. Commenters stated that Building Block 2 contemplates a 

significant redispatch of energy from New York's coal-fired EGUs to NGCC EGUs and this 

would further decrease the capacity factor of coal-fired EGUs and further increase, not decrease, 

their heat rates. Commenters stated that it is unrealistic to assume that fossil-fuel fired facilities 

can run fewer hours and run more efficiently, a point that the EPA itself has acknowledged. 

Commenters stated that for these reasons, they encourage the EPA to eliminate the assumptions 

made in Building Block 1 for states like New York where an already low utilization rate is not 

conducive to heat rate improvements. 

Commenters stated that based on the analyses of technical potential and cost, they propose to 

find that a six percent reduction in the CO2 emission rate of the coal-fired EGUs in a state, on 

average, is a reasonable estimate of the amount of heat rate improvement that can be 

implemented at a reasonable cost but that states and sources would be free to use heat rate 

improvements at those other units to help reach the state goals. Commenters stated that coal 

generating plants are designed with a 30-year life cycle and after 30 years, significant upgrades 

become necessary because aging coal plants face serious reliability, efficiency, and performance 

problems. Commenters stated that five out of six coal plants in Louisiana are already beyond 

their designed life expectancy. Commenters stated that these plants will need turbine, boiler, and 

other infrastructure replacements that are estimated to cost as much as a new CCGT power plant 
483

and further, in US v Ohio Edison Co. 2003, older generators were found to require significantly 

more maintenance unless costly, life-extending overhauls were not implemented. Commenters 

provided a table with Louisiana Coal plants, their capacities, and their HRI costs. Commenters 

stated that HRI is certainly achievable but not advised and that their economic analysis indicates 

that even though HRI is affordable, utilities will be throwing good money after bad. Commenters 

stated that it makes more financial sense to decommission the current coal fleet in Louisiana than 

to invest in HRI because these investments assume other costs (i.e. significant upgrades). 

Commenters stated that the capacity from coal should be replaced by re-dispatching natural gas, 

nuclear power plant upgrades, utility scale renewable energy, and energy efficiency. 

Commenters stated that improvements from equipment upgrades would unavoidably require 

capital investments at many existing coal plants. Commenters stated that the clear trend toward 

reduced use of coal generation and greater restrictions on emissions strongly disincentivizes 

capital investments at existing coal plants, particularly plants at or beyond the end of their 

economic life. Commenters stated that use of this factor should be accompanied by the types of 

assurances described above: if the most stringent standard considered is adopted, no further 

improvements in plant performance will be mandated before 2030. 

Commenters stated that many coal plants will be forced to retire or rendered uneconomic to 

operate in many hours under the rule, which would make it uneconomic for them to make the 

heat rate improvements EPA relies on as available

Commenters stated that the proposed rule provides flexibility on how a state achieves the 6% 

HRI and does not require that each unit meet a target gross heat rate and this allows for 

flexibility in unit operation as needed to provide reliability while still ensuring the base load coal 

units are operated efficiently. Commenters stated that whether these units can continue to be 

operated cost effectively under the proposed rule will be determined on a unit by unit case. 

Commenters stated that since it is costly to operate a coal unit at low loads, it is assumed that 

some units are required to operate at low loads to ensure reliability of the electricity supply 

during peak load periods. Commenters stated that these units may be capable of being tuned to 

have more complete combustion at lower loads, however, low load operation is still significantly 

inefficient compared to operating at the design load, even after tuning.

Commenters stated that it is necessary that certain units operate at high load factors to costeffectively improve the heat rate of the unit, however, this increase in operating load may trigger 

PSD/NSR permitting for certain units and units that trigger PSD/NSR for HRI may become 

"stranded assets" since they cannot meet a lower CO2 emission rate in a cost-effective manner.

Commenters stated that meeting even the first "building block" requirement of a 6% 

improvement in efficiency at Gibbons Creek will be economically unfeasible. Commenters 

stated that they operate in the competitive ERCOT (Electric Reliability Council of Texas 

(ERCOT) market and have therefore already squeezed most of the efficiencies that are 

economically feasible out of its Gibbons Creek plant and that to reach the additional 6% 

improvement they believe it could capture waste heat by adding a natural gas combustion turbine 

to displace the feedwater heating system. Commenters stated that however, this would need to be 

retrofitted to the existing unit at a cost of many tens of millions of dollars and there would also 

be an additional operating cost for the natural gas to operate the combustion turbine.
484

Commenters stated that such an expense, coming on top of other expenses associated with 

complying with EPA's other environmental regulations, would make it very difficult for Gibbons 

Creek to compete in the ERCOT competitive market and would force Gibbons Creek to shut 

down. Commenters stated that going further to meet EPA's "final" 2030 requirement of 791 

pounds of CO2/MWh would be cost prohibitive and they would be unable to comply. 

Commenters stated that in South Dakota's case, all of this will result in the Big Stone Plant not 

being able to run economically and forces the unit to be a stranded asset. Commenters stated that 

if the Big Stone Plant becomes a stranded asset, it would cause additional costs to consumers and 

may create reliability concerns in the region. Commenters stated that on page 34926 of the 

preamble, EPA states the establishment of the goals provides states with flexibility to design a 

plan to avoid stranded assets. Commenters stated that however, the unique circumstances in 

South Dakota provide little flexibility to meet its state goal and without EPA making proper 

adjustment to South Dakota's target the Big Stone Plant could become a stranded asset.

Commenters said given the uncertainties that building block 2 introduces into how coal units will 

be dispatched, it is unlikely that investors relying on the market for recovery of investments will 

choose to invest in these improvements. Commenters said this dynamic does not exist for 

regulated generators and points out how this proposed rule exacerbates the inequity between 

regulated and restructured states

Comment 5: Comments regarding HRI capital cost assumptions

Response 5: For the EPA’s response to these comments, see section V.C of the final rule 

preamble of the CPP and Chapter 2 of the GHG Mitigation Measures TSD supporting the final 

CPP. Furthermore, the compliance deadlines provides sufficient lead time to not overwhelm 

national or regional contracting capacity regarding heat rate improvements, and commenters 

have not offered sufficient information to suggest otherwise. 

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

Commenters stated that, in determining BSER, EPA is required to consider, among other things, 

cost. See CAA section 111. Commenters stated that EPA asserts that the costs of the projected 

HRI are reasonable based on cost data from the S&L report and because fuel savings will offset 

the costs of HRI measures. See Abatement Measures TSD at 2-33 to 2-34. Commenters stated 

that neither of EPA's assertions about HRI costs is reasonable. Commenters stated that first, 

EPA's cost assessment is based on costs as reported in the 2009 S&L report. See 79 Fed. Reg. at 

34,861. Commenters stated this cost data is nearly five years old and that EPA must explain why 

it is appropriate to rely on old data before asserting that any assessment of this cost data is 

reasonable. Commenters stated that second, EPA's core argument in support of the reasonable 

cost of the HRI is that "any heat rate improvement made for the purpose of reducing CO2 

emissions will also reduce the amount of fuel the EGU consumes to produce its electricity 

output." Id. at 34,861. Commenters stated that using cost estimates from the S&L report, EPA 

calculates an annualized cost per kilowatt hour (kWh) of HRI measures. See Id. Commenters 
485

stated EPA then calculates an annualized fuel cost to estimate the average fuels savings related to 

a six percent HRI.

Commenters stated that EPA's capital analysis relies on a 2009 report issued by Sargent & 

Lundy, a vendor of the types of equipment EPA now expects its rule will require all units to 

consider. Commenters stated that the report lists the following types of projects that could 

improve efficiency at existing coal-fired units: upgraded pulverizers, economizer replacements, 

neural network controls, intelligent soot blowers, improved air heater seals, sorbent injection into 

air heaters, advanced turbine designs, condenser upgrades and maintenance, boiler feed pumps 

overhauls, induced draft fan upgrades, variable frequency drive fans, and various projects 

designed to reduce the electricity used by conventional pollution control equipment, such as flue 

gas desulfurization systems, electrostatic precipitators, and selective catalytic reduction systems. 

Commenters stated that EPA's capital analysis examines four of those projects, specifically 

economizer replacements, acid dew point control projects, combined variable frequency drive 

fans, and turbine overhauls but that EPA, however, made a simplifying assumption that 

undermines the validity of the analysis. Commenters stated that EPA assumed that half of these 

projects have not already been completed at existing generators: "We considered that a 4% 

reduction in heat rate might be achieved on a coal-steam unit by applying the four higher cost 

upgrade actions described in Table 2-13. However, because details of current actual unit 

configurations are unknown, and some units may have applied at least some of the upgrades, we 

conservatively estimate the heat rate improvement potential for upgrades at 2%." Commenters 

stated that that assumption, in truth, is not "conservative," because it is little more than a coinflip, indicating that EPA does not have any basis to estimate, liberally or conservatively, how 

many coal units may already have undertaken these projects. Commenters stated that utility 

companies, however, have likely installed far more than half of the projects EPA cites, 

particularly if those equipment installations are as cost-effective as EPA claims. 

Commenters stated that electric utilities like theirs have strong financial incentives to deploy 

measures that improve heat rate because of fuel savings and that these measures often provide 

greater reliability as well, thus providing additional economic incentives. Commenters stated that 

these factors argue that the improvements sought by EPA and suggested by the S&L report may 

already be "baked into" the existing fleet and cannot be "counted twice." Commenters stated that 

EPA has made no effort to determine if these measures have already been implemented.

Commenters stated that if measures have been implemented, EPA should adjust the analysis 

accordingly and at a minimum if a state can demonstrate that HRI projects already have been 

implemented at in-state affected coal-based EGUs, EPA should recalculate that state' emission 

rate goals accordingly.

Commenters stated that while incentives are already in place for their facilities to make costeffective, efficiencies improvements, in an initial analysis, they have identified 35 additional, 

specific projects that would decrease the heat rate at its coal-fired generating units. Commenters 

stated that these projects are for generating units that they anticipate will remain in service 

during the compliance period. Commenters stated that EPA should recognize that many units 

with the most opportunity to improve heat rate will be retired before or during the compliance 

period. Commenters stated that in total, these projects would reduce their coal plant heat rate by, 
486

at best, 1.6 percent. Commenters stated that the total capital cost of these projects is estimated at 

$60 million with a $2.5 million annual O&M cost. 

Commenters stated that because EPA's technical data is lacking, its cost data is suspect, as well.

Commenters stated that EPA estimates that a fleet-wide average heat rate net improvement of 

6% would cost only $6 to $12 per ton of CO2 removed but that the actual costs, however, are 

likely to be dramatically higher. 

Commenters stated that EPA's cost estimates for achieving heat rate improvements is 

unsupported by assuming that the cost of a six percent heat rate improvement will be $100 per 

kilowatt on average nationally, without providing a detailed explanation how the agency arrives

at the figure.

Commenters stated that for power plants constructed or upgraded within the past decade, 

additional upgrades would be marginally beneficial and economically unjustifiable, costing 

significantly more than the $100 per kilowatt (kW) that EPA estimates heat rate improvements 

will cost in the Proposed Rule. Commenters added that such new and recently upgraded coal 

power plants simply could not achieve meaningful improvements in heat rates without massive 

reconstruction and redesign, for example by converting a low pressure, subcritical plant into a 

supercritical plant, and that the cost of rebuilding such a plant would be in excess of $2,000 per 

kilowatt, over twenty times EPA's estimate of $100 per kilowatt.

Commenters stated that heat rate improvement estimates provided in the 2009 S&L Report were 

incorrectly applied in the GHG Abatement Measures TSD when the HRI methods were 

combined as though they were applied to a single EGU to establish a combined fleet-wide 

minimum/maximum heat rate improvement range of 415-1,205 Btu/kWh (or 4% to 12%).

Commenters stated that by combining all HRI methods as though they were all applied to a 

single EGU, the GHG Abatement Measures TSD overestimates both the minimum and 

maximum potential heat rate improvement that may be achieved on a fleet-wide basis -for 

example, in its Min-Max evaluation, EPA presumably included a minimum 30 Btu/kWh 

improvement with the installation of intelligent sootblower (ISB) technology, whereas S&L's 

report states that boiler efficiency improvements obtained by installing ISB systems "on older 

boilers" have ranged from 0.3 to 0.9 percentage points, and that "specific performance 

improvement depends on the type of fuel used and the age of the furnace." Commenters further 

stated that the heat rate improvement ranges included in the 2009 S&L Report were, by 

necessity, based on the assumption that the unit under consideration could benefit from such a 

system. Commenters stated that minimum heat rate improvements listed in the report would not 

be realized on units that have already implemented the HRI method or on units on which the HRI 

method is not technically feasible. Commenters stated that nevertheless, EPA applied a minimum 

heat rate improvement of 30 Btu/kWh for ISB projects in its Min-Max evaluation.

Commenters stated that the 2009 S&L Report included minimum heat rate improvements for 

other HRI methods including: 50 Btu/kWh for economizer upgrades; 10 Btu/kWh for air heater 

leakage; 50 Btu/kWh for acid dew point reductions; 30 Btu/kWh for condenser cleaning and 

maintenance; 25 Btu/kWh for boiler feed pump overhaul; 10 Btu/kWh for combined variable 

frequency drives (VFD) and fan modifications; and 100 Btu/kWh for turbine overhauls. 
487

Commenters stated that all of these "minimums" assume that the HRI method is technically 

feasible and that the method is not currently utilized by the unit. Commenters further stated that 

combining all of the HRI methods to establish a minimum expected fleet-wide heat rate 

improvement is not a valid use of the data provided in the 2009 S&L Report.

Commenters stated that HRI cost ranges included in the 2009 S&L Report show that, in general, 

HRI methods will be more costly on a $/kW basis on smaller units, such that turbine overhaul 

projects could cost between $5.6 and $27.8/kW on larger units, but cost between $10 and 

$60/kW on smaller units. Commenters stated that EPA acknowledged in the GHG Abatement 

Measures TSD that "the economy of scale of larger units allows the use of higher cost 

improvements to be more economic" and "economy of scale causes most HRI methods to be 

more costly ($/kW) on smaller units." Commenters stated that yet, the economic impact analysis 

included in the GHG Abatement Measures TSD is based on average values that do not account 

for any unit-specific feasibility issues or costs, including economy of scale, and results in the 

erroneous conclusion that HRI methods are generally more cost-effective on smaller units.

Commenters stated that all of the HRI methods evaluated in the 2009 S&L Report showed 

significant variability in both the potential heat rate improvement and costs; for example, the 

combined overall heat rate improvement associated with upgrading a plant with new centrifugal 

fans with VFD ranged from 10 to 150 Btu/kWh for all boiler size categories (200 MW, 500 MW 

and 900 MW), with costs ranging from $6 to $16 million depending on unit size and retrofit 

difficulty. Commenters stated that the cost-effectiveness of this potential HRI method will vary 

significantly from plant to plant and must be evaluated on a case-by-case basis taking into 

consideration technical feasibility, effectiveness, and costs. Commenters stated that the same 

result applies to all HRI methods with wide ranges of both HRI improvement and HRI costs and 

that applying an assumed total capital cost to an average heat rate improvement masks the wide 

range of HRI improvement and costs presented in the 2009 S&L Report.

Commenters stated that EPA assumed 6% improvement could be achieved at a capital cost of 

$100/kilowatt (kW). Commenters stated that understand that various industry experts have 

concluded that these assumptions are unrealistic in light of practical engineering considerations, 

actual industry experience, and the incentives owners of electricity generators already have to 

improve plant efficiency and that their clients suggested an alternative set of assumptions, in 

particular, (a) for a cost of $100/kW, a maximum efficiency improvement of 1.5% would be 

achievable for the most inefficient existing units and a 0.75% improvement would be available 

for units with average efficiency, and (b) no efficiency improvements would be available to the 

most efficient units. Commenters investigated the significance to incremental energy cost 

estimates of these alternative sets of assumptions regarding potential heat rate improvements and 

found that this set of assumptions did not have a major effect on the results; using EPA's heat 

rate assumption rather than the alternative set resulted in less than a 1% change in their estimate 

of the overall energy system cost of the CPP in the unconstrained scenario. Commenters stated 

that although they were not indicating that they attempted to determine the most realistic set of 

assumptions, they adopted the alternative industry set of assumptions regarding potential heat 

rate improvements. Commenters noted that while this set of assumptions has de minimis impact 

on estimates of the impacts of the proposed CPP, this issue would be much more significant if 

the Section 111(d) limits for legal reasons had to be based solely on systems of emissions 

controls that can be achieved on the existing fossil units themselves. Commenters stated that in 
488

that legal situation, this uncertainty would warrant a more thorough treatment of heat rate 

improvement assumptions than they determined was necessary for the present analysis.

Commenters stated that EPA states that an additional 2% of heat rate improvements to get to 6% 

are available with some expense (presumably, most of that $100/kW) and to put things in 

perspective, $100/kW is about one fifth the cost of a wet scrubber. Commenters stated that is an 

expense that is not excessive for most power plants and that the one sticking point is concern 

about New Source Review. Commenters stated that in a 2013 paper published in Power 

Magazine prepared by ASME's Research Committee on Energy, Environment and Waste titled 

"The Case for Fuel Delivery System Upgrades on Utility Boilers" they found that by upgrading 

the fuel delivery system they could achieve a 0.34% improvement in boiler efficiency on a 500 

MW wall fired coal boiler at a cost of $13,600,000. Commenters stated that a major steam 

turbine overall/upgrade for a 500 MW can cost between $30-50 million.

Commenters stated that Air heaters have been identified as one of the prime areas in coal plants 

that can lead to improved heat rates and that there are two types of "upgrades" that EPA needs to 

evaluate in their rulemaking. Commenters stated that the first type should really be considered 

normal maintenance and repair. Commenters stated that in reading the Sargent &Lundy report 

"Coal-Fired Power Plant Heat Rate Reductions “it appears that the information and heat rate 

improvements that are presented fall into this category and in discussions with Air Heater 

manufactures and companies that rebuild and maintain air heaters they all concluded that in most 

cases replacing circumference and radial seals, and basket replacements will only bring an 

existing air heater back to its original design condition. Commenters stated that the S&L data 

indicated that the cost they used in this analysis is for bringing an existing air heater to design or 

as new condition. 

Commenters stated that to upgrade an air heater beyond its design condition is a significantly 

more challenging endeavor and not all units are candidates for an upgraded design. Commenters 

stated that there are several design criteria that need to be considered.

• Designed in concert with economizer to maximize boiler efficiency by 

minimizing flue gas outlet temperature from the boiler.

• Air outlet temperature set by coal drying requirements.

• Gas outlet temperature set high enough to avoid corrosion and plugging due to 

condensation of moisture and/or acids. Technologies such as Dry Sorbent 

Injection (DSI) could be used to reduce acid condensation by their application 

could be limited by all of the factors identified above and below.

• Pressure drop set to minimize fan power requirements.

• Gas outlet temperature needs to be high enough to support operation of Dry 

Scrubber/Baghouse if so equipped.

• What fuel was the original design based on?
489

Commenters stated that the Arvos Group - Ljungstrom Division (formally Alstom Air Preheater) 

provided an analysis of two 500 MW coal-fired units to evaluate the capabilities and cost of 

upgrading air heaters beyond their original design conditions and that unit specific issues can 

significantly affect the available results as well as the cost to upgrade any specific unit. 

Commenters noted that these comparisons are based on existing equipment in "as- new" 

condition as compared to the upgrade selection also in "as-new" condition and if degradation of 

existing assets were taken into account, the value associated with these upgrades could be even 

more pronounced. Commenters provided the Arvos analysis that shows the cost and upgrade 

opportunities in these two plants.

Commenters stated that the data indicate that a DSI system most likely would have to be added 

to the plant if it does not already have a system to control acid mist and corrosion. 

Commenters continued that Combustion Modifications A project was undertaken by the Fuels 

Delivery System Subcommittee of the ASME Research Committee on Energy, Environment, and 

Waste (RC EEW) and that they evaluated a coal fired boiler group, aged 30- to 45- year old 

units, comprised 216 GW and 63% of the total fleet capacity with an average unit capacity of 

500 MW. Commenters stated that these units will bear the burden of ensuring the usual high 

standards of electric grid performance, availability, and reliability. Commenters stated that a vital 

part of any coal-fired unit is the Fuel Delivery System (FDS), comprising feeders, pulverizers, 

classifiers, coal piping and burners and that they investigated three typical 500-MW wall-, 

tangential-, and cyclone-, fired boilers originally designed for eastern bituminous coal and now 

firing low sulfur subbituminous Powder River Basin (PRB) coals. Commenters stated that the 

subcommittee reviewed and selected retrofit upgrades to various parts of the FDS, determining 

costs and the potential value of the ensuing benefits. Commenters stated that in the case of a 500 

MW bituminous wall fired boiler they concluded that 0.34% improvement in boiler efficiency on 

a 500 MW wall fired coal boiler at a cost of $13,600,000. 

Commenters also stated that, with regards to steam turbine updates, a recent paper was published 

about a plant upgrade including modifications of all sections of the steam turbine, the condenser, 

and the boiler. Commenters stated that the upgrade was able to achieve a 6% plant efficiency 

improvement and that the owners have indicated that the cost of the entire plant upgrade was in 

excess of $50,000,000.

Commenters stated that there may be insufficient contracting capacity nationally and regionally 

to undertake too much work at once; and there can be no question that costs escalate with 

expedited schedules, or when contracting capacity is strained. Commenters stated that recent 

capital projects in Wyoming have had the advantage of occurring when pricing has been 

restrained by the financial shock of 2008 and slow growth since then, cushioning ratepayers from 

the effect of MATS and regional haze compliance. Commenters stated that this Commission has 

also observed the ratepayer benefits of being patient with implementation.

Commenters questioned what reasons account for the difference between EPA's 6% and their

estimate of 2%. Commenters stated that the first reason is EPA's unorthodox approach to cost 

estimates. Commenters stated that the Wyoming operators accepted Sargent & Lundy's 

recommendation that they conduct "site-specific evaluations and cost analyses based on actual 

market conditions for any and all required equipment, material, and labor at the time of the 
490

project." S&L report, p. 1-3; in other words, the Wyoming operators considered fuel costs as 

they normally would and do, together with other features of a normal project evaluation. 

Commenters stated that the most common reason for PacifiCorp and Black Hills to reject a 

proposed Sargent & Lundy measure was that it was not economic. 

Commenters stated that the operation of an EGU normally accounts for similarly embedded costs 

which are constantly considered as part of a balance. Commenters stated that the operation of an 

EGU typically is based on optimizing unit availability, heat rate, and expenditures (for 

operations and maintenance and for capital investment) to produce the lowest net power cost. 

Commenters stated that EPA should regard with suspicion any explanation of substantial change 

which ignores this balance. Commenters stated that for example, the average heat rate can be 

improved by increasing the frequency of turbine overhauls, but it is always a question whether 

the cost of doing so can be supported, and particularly doubtful that, for the diverse national 

fleet, fuel savings alone can cover that cost. Commenters stated that EPA should question the 

premise that it should interfere with established economically driven operating practices without 

a clear identification of benefits.

Commenters stated that the EPA's economic analysis assumed that the total six percent 

improvement in heat rate would result from capital investment of $100 per kilowatt of installed 

capacity but in reality, the improvement would have to result from both capital expenditures and 

operating and maintenance expenditures.

Commenters stated that EPA calculations applied average costs for the U.S. EGU fleet and 

concluded that heat rate improvement projects with a capital cost of $100 per kilowatt would 

break even (fuel savings would equal cost of projects) when fuel costs were approximately 

$3.25/MMBTU. Commenters stated that unlike many other areas of the country, their average 

2012 fuel costs for the units they operate, many of which are mine mouth or in close proximity to 

their supply, are significantly lower than EPA's estimates. Commenters referred to a table 

showing their average coal unit $/MMBTU 2013 costs for 6 units, ranging from 0.83-2.16 and 

explained that as shown, fuel costs for their EGUs are considerably less than the U.S. fleet-wide 

average and as a result, calculated fuel savings when compared to the economics to justify heat 

rate improvement projects to achieve EPA's proposed six percent improvement are significantly 

more challenging due to significantly lower fuel costs for their plants. 

Commenters evaluated economic factors associated with the proposed efficiency improvements. 

Commenters stated that efficiency improvements are typically justified when the cost of 

improvements would be offset by fuel cost savings or greater capacity output for the same fuel 

input. Commenters stated that for their 100 MW mine-mouth units, a one-percent efficiency 

savings equates to approximately $100,000 in fuel cost savings per year. Commenters stated that 

the estimated capital costs of the upgrades suggested in the Sargent & Lundy study vary 

significantly and by way of example, on the high end, turbine steam path upgrade/turbine 

replacement (which would improve the aerodynamic design of the turbines) would yield up to a 

two-percent efficiency improvement for an estimated capital cost of $12.5 million. Commenters 

stated that such an investment would take over 62 years' worth of fuel savings in order to cover 

the cost of the upgrade. Commenters stated that further it should be noted that some of the 

projects would have overlapping performance benefits, meaning that the total expected 

improvements of all projects would not equal the sum of the individual project improvements. 
491

Commenters stated that they also must consider that the improvements will degrade over time, 

resulting in reduced efficiency. Commenters stated that while this is just one example, the State 

of Wyoming is submitting very detailed comments on Building Block 1, with which they would 

associate themselves and concur with the state's recommendation. 

Commenters stated that EPA's capital analysis relies on a 2009 report issued by Sargent & Lundy 

("S&L"), a seller of the types of equipment and services EPA now expects its rule will require all 

coal-fueled EGUs to consider. Commenters stated that electric utilities, however, may well have 

already installed most, if not all, of the projects EPA cites, particularly if those equipment 

installations are as cost-effective as EPA claims. Commenters stated that the S&L Report upon 

which EPA relies was a 2009 study that relied on 2008 data, four years prior to the baseline EPA 

assumes in its building block formula and as that S&L report stated, "[a]ll estimated capital and 

installation costs are referenced from work in progress and vendor quotes as of the year 2008." 

Commenters stated that what this means is that the data within the S&L study is outdated, and, in 

any event, the 2009 S&L study was not designed for national rulemaking purposes generally, nor 

does it support the specific assumptions that EPA has made in the Proposed Rule. Commenters 

stated that for example, the introduction of the report explains that its cost figures are intended to 

be accurate only on an "order of magnitude" level, and those cost figures are provided only for 

"comparison purposes' when evaluating the advantages and disadvantages of one project against 

another. Commenters stated that indeed, the report specifically notes that those cost estimates 

"should not be used as a basis for project budgeting or financing purposes." Commenters stated 

that the report also notes that its calculations are based on the hypothetical "design" heat rate of 

coal units, which units can achieve (if at all) only during full load operation; the calculations are 

not based on the actual heat rate of units, which the report admits "are usually significantly 

higher than the design heat rate." Commenters stated that that EPA cannot reliably or 

appropriately use the 2009 S&L Report to assume that the types of improvements estimated by 

S&L are equally applicable and achievable at each and every coal-fueled power plant in the 

country and notably, S&L itself has recently evaluated the Proposed Rule's reliance on (and 

characterization of the 2009 S&L Report) and fundamentally rebuked EPA's mischaracterization 

of its earlier analysis.

Commenters stated that EPA's estimated capital costs are suspect. Commenters stated that EPA 

assumes a $100/kW estimate as the "representative" capital cost of achieving all possible heat 

rate improvements at an average site. Commenters stated that this estimate (1) is based on 

Sargent & Lundy's estimated capital cost range of $40-$150/kW, and (2) is intended to account 

for the wide range of EGU characteristics that affect the available heat rate improvement 

measures for each unit. Commenters stated that aside from the fact that the cost range identified 

by Sargent & Lundy is so broad that it cannot serve as a rational basis for a cost estimate, EPA's 

arbitrary choice of $100/kW - simply splitting the difference - is even less tenable. 

Commenters stated that when determining the BSER, the EPA is required to consider, among 

other things, cost. Commenters stated that the EPA asserts that the costs of the projected HRI are 

reasonable based on cost data from the 2009 S&L report and because fuel savings will offset the 

costs of HRI measures, however neither of the EPA's assertions about HRI costs are reasonable. 

Commenters stated that the EPA's cost assessment is based on information from the S&L report, 

but the cost estimates in the S&L report were based on 2008 data, which is no longer current and 
492

the EPA's assessment should use more recent data and include additional sources in order to 

better substantiate costs. 

Commenters stated that the EPA's core argument in support of the reasonable cost of the HRI 

that is part of the EPA's BSER determination and which forms part of the basis of the state 

emission rate goals is that "any heat rate improvement made for the purpose of reducing CO2 

emissions will also reduce the amount of fuel the EGU consumes to produce its electricity 

output." Commenters stated that using cost estimates from the S&L report, the EPA calculated 

an annualized cost per kilowatt hour ("kwh") of HRI measures and the EPA then calculated an 

annualized fuel cost to estimate the average fuel savings related to a 6 percent HRI. Commenters 

stated that however, Building Blocks 2, 3, and 4 are specifically designed to reduce fuel use by 

coal-fired EGUs but this was not factored into the EPA's Building Block 1 cost assessments, but 

if it had been, it would have resulted in reduced fuel savings from HRIs. 

Commenters stated that heat rate improvements will reduce fuel costs, on a per kilowatt ("kW") 

basis, but the EPA's analysis, which focuses on annualized costs, ignores the lag between capital 

expenditures and fuel cost savings. Commenters stated that immediate HRI measure capital costs 

may be financed, which spreads the costs over time and this financing is dependent on continued 

operation of the unit to create a revenue stream that allows the capital costs to be repaid over 

time. Commenters stated that the EPA's own analysis indicates that many existing coal-based 

units will be retired by 2020 and that the utilization of the remaining units will decrease as part 

of states' compliance efforts in meeting their interim and final goals. Commenters stated that this 

dramatically shortens the payback period and reduces the electricity sales available to support 

capital cost investments in HRI measures. 

Commenters stated that to some extent, the EPA recognizes this, noting that "reductions in the 

utilization rates of coal-fired EGUs anticipated from other components proposed for inclusion in 

... [BSER] would tend to reduce the fuel savings associated with [HRI], thereby raising the cost 

effectiveness of achieving the CO2 reductions," but the EPA quickly dismisses - without any 

analysis - the impact that reduced utilization would have on the reasonableness of HRI costs, 

stating "[n]evertheless, we still expect that the majority of the investment required - would be 

offset by fuel savings." Commenters stated that accordingly, the EPA has not adequately 

supported its claims that reductions associated with HRI measures can be achieved at reasonable 

cost. 

Commenters stated that EPA's capital analysis relies largely on a 2009 report by the engineering 

and consulting firm Sargent & Lundy. Commenters stated that EPA's capital analysis examines 

four of the S&L improvement projects, specifically economizer replacements, acid dew point 

control projects, combined variable frequency drive fans, and turbine overhauls. Commenters 

stated that EPA, however, made a simplifying assumption that undermines the validity of the 

analysis and that EPA assumed that half of these projects have not already been completed at 

existing generators: "We considered that a 4% reduction in heat rate might be achieved on a 

coal-steam unit by applying the four higher cost upgrade actions described in Table 2-13. 

However, because details of current actual unit configurations are unknown, and some units may 

have applied at least some of the upgrades, we conservatively estimate the heat rate improvement 

potential for upgrades at 2%." Commenters stated that EPA's stated assumptions cannot 

reasonably be said to be "conservative," because EPA does not have any identified basis to 
493

estimate, liberally or conservatively, how many coal units may already have undertaken these 

projects. 

Commenters stated that coal-fueled EGUs in North Dakota, however, have likely installed most, 

if not all, of the projects EPA cites, particularly if those equipment installations are as costeffective as EPA claims. Commenters stated that the Sargent & Lundy report on which EPA 

relies was a 2009 study that relied on 2008 data, four years prior to the baseline EPA assumes in 

its building block formula. Commenters stated as that report stated, "[a]ll estimated capital and 

installation costs are referenced from work in progress and vendor quotes as of the year 2008." 

Commenters stated that in any event, the Sargent & Lundy study was not designed for 

rulemaking purposes generally, nor does it support the specific assumptions that EPA has made 

with respect to coal fueled EGUs in North Dakota. Commenters stated that for example, the 

introduction of the 2009 report explains that its cost figures are intended to be accurate only on 

an "order of magnitude" level, and those cost figures are provided only for "comparison 

purposes" when evaluating the advantages and disadvantages of one project against another. 

Commenters stated that the 2009 Report specifically notes that those cost estimates "should not 

be used as a basis for project budgeting or financing purposes." Commenters stated that the 

report also notes that its calculations are based on the hypothetical "design" heat rate of coal 

units, which units can achieve (if at all) only during full load operation, not the actual heat rate of 

units, which the reports admits "are usually significantly higher than the design heat rate."

Commenters stated that the goal of Building Block 1, as a component of EPA's BSER, is to 

achieve carbon reduction through improved efficiency at affected coal units. Commenters stated 

that EPA assumes a 6 percent efficiency (heat rate) improvement which would translate to a 6 

percent reduction in lbs of CO2 per net MWh. Commenters stated that the 6 percent efficiency 

improvement rate was derived in part from a Sargent and Lundy study, which (according to 

EPA) shows that the total heat rate improvements would be in a range of 4 to 12 percent if all 

identified best practices and equipment upgrades at a facility were made; however, the Sargent 

and Lundy study was a generic study that did not consider the particular circumstances of each 

state. Commenters stated that the EPA also acknowledges that "[its] simplified cost 

analysis...will represent the costs for some EGUs better than others because of differences in 

EGUs' individual circumstances."

Commenters stated that many utilities have commented that a heat-rate improvement of 6% is 

unrealistic and that they too believe it would be unrealistic to attain another 6% gain over heat 

rate improvements they have already made. Commenters stated that they continuously evaluate 

options for economic improvement in heat rate efficiency and undertake those investments when 

viable and prudent. Commenters stated that in 2007, they contracted with Sigma Energy 

Solutions, Inc. to perform an energy assessment on their three (3) small older units, 31, 32 and 

33. Commenters stated that the study cost approximately $80,000 and among the 

recommendations which were implemented were to address cycle isolation (leaking valves), 

boiler performance issues including loss of ignition (LOI) and the potential for incomplete 

combustion. Commenters stated that in addition, long term recommendations regarding turbine 

performance were made that can only be addressed during turbine overhauls. Commenters stated 

that they continually replaced leaking valves during outages, improvements were made in the 

combustion of each unit and the turbines have all been through an overhaul and that they

estimate that they spent approximately $200,000 to implement the more routine 
494

recommendations, the majority of which are performed annually, while turbine overhauls cost 

over $8M. Commenters stated that Units 31 and 32 turbine overhauls were completed in 2007, 

while Unit 33's turbine overhaul was just completed this past spring, and they spent over $1.9 

million on improving turbine efficiency during this outage. Commenters estimated that the work 

to implement the recommendations to Unit 33 resulted in a 9.31% heat rate improvement, while 

the heat rate improvements to the two smallest units were less. 

Commenters stated that EPA assumes that an additional 2% heat rate improvement is available, 

on average, through equipment upgrades and that this assumption is incorrect for most of the 

industry in general and for them in particular. Commenters stated that for example, they have

spent over $26 million on turbine heat rate improvements at the Winyah and Cross facilities 

alone during a 5-year period from 1995 to 2000 and these investments yielded heat rate 

improvements of only 1.25% on average. Commenters stated that other utilities typically spend 

similar amounts on heat rate improvements.

Commenters stated that the measures implemented by their facility to date - including efficiency 

improvements to the flue gas desulfurization systems and the addition of a condenser cleaning 

system - are the lowest-hanging fruit, offering the greatest reductions in heat rate and CO2 

emissions per dollar of investment. Commenters stated that the remaining EPA-identified 

measures are either cost-prohibitive or impractical due to unit-specific considerations, such as 

equipment space limits. Commenters stated that furthermore, their baseload coal-fired EGUs 

include Cross Units 3 and 4, which are new units designed with maximum efficiency and 

emissions controls and consequently, in their case - as for many utilities around the country - the 

only options for improving heat rate would be to remove pollution control devices (which other 

EPA rules prohibit), or to radically change boiler design, which would trigger New Source 

Review (NSR) concerns. 

Commenters stated that another consideration is that the heat rate of any coal-fired EGU changes 

with the scheduled maintenance cycle and thus, any goal for heat rate improvement for coal-fired 

units should consider all of the significant variables so unit heat rate is compared to a best 

achievable heat rate. 

Commenters stated that they have the lowest CO2 emission rate for all coal-fired steam plants in 

Utah and in general the coal plants in Utah have some of the lowest heat rates of any coal-fired 

plants in the United States. Commenters stated that at their facility, monthly performance tests to 

identify and correct efficiency loss are conducted and the results of those tests are used for 

outage planning and where possible, immediate correction of equipment or operating 

deficiencies. Commenters stated that efficient operations have always been a focus of their plant 

staff so it will be difficult to identify any heat rate improvement projects which would not require 

significant capital investment, extensive modifications and environmental permit changes. 

Commenters stated that to further illustrate the implausibility of a 6% heat rate improvement, the 

EPA indirectly aims to decrease the generation levels of coal-fired power plants by increasing 

generation levels of NGCCs. Commenters stated that the capital additions necessary to make 

heat rate improvements will become even less economically feasible if the coal-fired power 

plants will be generating less power due to the uneconomic and artificially induced increases in 
495

NGCC capacity factor. Commenters stated that in addition, if coal plants are forced to cycle 

more, heat rate efficiencies could deteriorate further. 

Commenters stated that EPA also fails to appreciate the magnitude of upfront capital costs of 

retrofit equipment upon which EPA bases its 2% heat rate improvement figure. Commenters 

stated that this oversight renders the CPP patently unreasonable and unattainable for older coalfired EGUs that may be approaching retirement. Commenters stated that according to the EIA, 

the average operating heat rate for coal-fired EGUs is approximately 10,500 Btu/kwh. 

Commenters stated that the CPP calls for a reduction of 2% (210 Btu/kWh) through equipment 

upgrades. Commenters stated that based on projections from the Sargent & Lundy study, the 

capital cost for the most cost-effective combination of upgrades to attain this reduction is over 

$10 million, plus another $200,000 in annual operating costs. Commenters stated that EPA 

rationalizes these costs by maintaining that such upgrades will eventually pay for themselves 

through increases in power generation efficiency. 

Commenters stated that EPA further estimates that EGUs can achieve a 2% heat rate 

improvement by making major long-term capital improvements. Commenters stated that they

have identified major boiler improvement projects for which heat rate improvements may also be 

realized. Commenters stated that for this analysis they have bundled these projects because they 

are located adjacent to each other in the boiler gas path. Commenters stated that projects such as 

those included in this bundle have potential New Source Review application, the budgetary cost 

and heat rate penalty associated with the addition of a selective catalytic reduction (SCR) retrofit 

has also been included in a table, titled Major Holcomb 1 Boiler Improvement/SCR Project 

Bundle, which lists potential NUHR Impact and cost for various technologies. Commenters

stated that while the NUHR impact of these projects are not all additive it may be concluded that 

perhaps a net 2% NUHR (at full load) might be realized on Holcomb 1.

Commenters stated that the efficiency improvements presented in the table are not justified with 

the economic and heat rate penalties associated with SCR included in the project bundle. 

Commenters stated that this is especially relevant if the resulting improvements cannot be 

amortized over a 30-year life at traditional high output factor utilization. Commenters noted that 

a $45 million turbine improvement project was also identified to improve overall Holcomb 1 

NUHR in excess of 2%. Commenters stated that unfortunately, these projects are not 

economically justifiable in view of the re-dispatched energy production specified by EPA in 

building blocks 2 through 4. Commenters stated that accordingly, EPA must propose a way, and 

an expectation, that states and independent system operators (power pools) exclude any energyprice manipulation that directly results in the re-dispatch of any EGU undergoing such project or 

project bundling so as to enable recovering such investments over the necessary remaining useful 

life of the EGU. 

Commenters stated that facilities already face a number of incentives to maximize unit heat rate, 

the most important being profit motive. Commenters stated that if economic improvements to the 

facility are available, those improvements are accounted for in routine maintenance and capital 

investment activities. 

Commenters stated that EPA relied primarily on capital costs provided in the 2009 S&L Report 

to establish its $100/kW total capital cost, which, EPA concluded was "a representative 
496

combined HRI capital cost to achieve whatever HRI Btu reduction is possible at an average site." 

Commenters stated that to establish this number, EPA apparently divided the range of capital 

costs ($) provided in S&L's report by the boiler size range (kW) to calculate minimum and 

maximum $/kW values for each HRI method. Commenters stated that EPA then summed the 

$/kW values for each HRI method to calculate a combined Min-Max capital cost as though all 

methods were applied to a single EGU. Commenters stated that however, this methodology does

not provide an accurate estimate of the costs that will be incurred to implement HRI methods at 

any given facility, or on an average fleet-wide basis, for at least two reasons. Commenters stated 

that first, costs included in the 2009 S&L Report were not intended to serve as the basis for 

calculating the total actual costs that may be incurred to implement the HRI methods. 

Commenters stated that second, HRI costs must be evaluated on a case-by-case basis and should 

not be combined as if all HRI methods could be applied to a single unit.

Commenters stated that the 2009 S&L Report clearly states that costs "presented herein are not 

indicative of those that may be expected for a specific facility due to variables such as 

equipment, material, and labor market conditions and site specifications." Commenters stated 

that costs included in the 2009 S&L Report were intended to provide "information for 

comparative purposes when evaluating the advantages and disadvantages of the various 

concepts." Commenters stated that taking into consideration the purpose and limitations of the 

cost ranges included in S&L's 2009 Report, cost data provided in the report should not be used as 

the basis for establishing minimum or maximum fleet-wide HRI costs. Commenters stated that 

furthermore, case studies included in the 2009 S&L Report show that it is not feasible to apply 

all of the HRI methods to an individual unit, and that HRI implementation costs can vary 

significantly based on unit type, fuel type, plant design, previous equipment upgrades, retrofit 

difficulty, and many other site-specific factors. Commenters stated that cost ranges provided in 

the 2009 S&L Report represent order of magnitude costs and were provided for comparative 

purposes only. Commenters stated that the cost ranges were not intended to serve as the basis for 

calculating minimum or maximum fleet-wide HRI implementation costs.

Commenters stated that costs presented in the report were not indicative of the costs that may be 

expected to install the HRI methods at any specific facility, as HRI costs can vary significantly 

based on unit type, fuel type, plant design, previous equipment upgrades, retrofit difficulty, and 

other site-specific factors. Commenters stated that cost data from the 2009 S&L Report were 

misapplied when EPA converted the cost ranges to $/kW values and combined the costs for all 

HRI methods as though they were all applied on a single EGU. 

Commenters stated that the cumulative financial impact as a result of APH deterioration is 

staggering. Commenters stated that for example, a 500 MW coal-fired plant operating at 85% 

annual capacity would consume approximately 5000 tonnes of coal per day assuming an average 

heat rate of 10,550 kJ/kWh. Commenters stated that based upon a fuel cost estimate of $80 per 

metric tonne of coal, a 1% reduction in fuel consumption amounts to $1.5 million in annual 

savings. Commenters stated that this figure does not take into account additional costs savings 

realized through the elimination of parasitic loads related to APH damage. Commenters stated 

that a similar fuel analysis can be performed regardless of the fuel source utilized. Commenters 

also stated that the total combined cost of APH losses is generally not considered. Commenters 

stated that these losses include decreased thermal efficiency, increased parasitic loads, reduced 
497

pollution control equipment efficiency, and increased costs in fuel, chemical and ash disposal 

along with lost sales revenue due to de-rates. 

Comment 6: Comments regarding NSR requirements, EGU related investments, and impact of

controls

Response 6: For the EPA’s response to these comments, see sections V.C and X.A of the final 

rule preamble of the CPP and Chapter 2 of the GHG Mitigation Measures TSD supporting the 

final CPP. Furthermore, as discussed in section I.A of the final rule preamble, the interim 

compliance period has been adjusted to begin in 2022, and “early” emissions reductions achieved 

between 2012 and 2022 can be accounted for in demonstrating compliance.

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

Commenters stated that EPA fails to account for the fact that the capital projects that it expects 

utilities to undertake have, in the past, triggered review and enforcement under the New Source 

Review (NSR) program and these enforcement actions are detailed in the comments of the 

Utility Air Regulatory group. Commenters stated that unless EPA exempts these projects from 

NSR review, utilities will not undertake them given the additional costs they will incur to meet 

Best Available Control Technology (BACT) requirements and at a minimum, EPA's failure to 

consider these additional BACT costs in assuming that utilities can undertake the assumed 

capital improvements is arbitrary.

Commenters further stated that EPA failed to consider that NSR permitting requirements 

discourages heat rate improvements and as EPRI's comments reported, a National Energy 

Technology Laboratory workshop reported that NSR permitting requirements is one of the 

largest barriers to heat rate improvement projects. Commenters stated that the National Coal 

Council came to the same conclusion. Commenters stated that they understand that UARG's 

comments will show that many of the heat rate improvement projects that EPA cites have 

triggered NSR enforcement actions by EPA but that EPA, however, does not include in its BSER 

analysis the additional costs of NSR permitting and the very significant and costly BACT 

requirements that a unit must meet to obtain a permit. Commenters stated that EPA's failure to do 

so is arbitrary and capricious. 

Commenters stated that EPA's proposed rule does not consider the negative impact that the 

EPA's prior rule making has had on the overall heat rate of coal fired generation. Commenters 

stated that in response to prior rules, they have performed upgrades to the flue gas 

desulphurization units and installed SNCR systems to their coal fired generating units. 

Commenters stated that these two items required a $60.5 Million investment by their members 

and resulted in a 2.5% increase in plant auxiliary load thereby negatively impacting the 

efficiency of the facility and this 2.5% increase in plant auxiliary load equates to 13 MWh per 

day. Commenters stated that in fact, they are currently investigating technology to meet the 

MATS rule that will further negatively impact the heat rate efficiency of the facility.

Commenters summarized EPA's suggestion for a net heat rate improvement of 6% and agreed 

that there is an untapped potential in the fossil power sector to deploy upgrades and improve 
498

operations. Commenters stated that for the purposes of their comments, and in general, they

consider heat rate improvements from equipment and from operational improvements as part of 

one category, and their estimates reflect the total impact of both "types" of heat rate 

improvement.

Commenters stated that they are a major provider of equipment and services to the coal-fired 

power sector and in fact, around half of the existing fleet runs on their technology, and over 

three-quarters of that subset have already deployed upgraded heat rate technology. Commenters 

stated that these upgrades not only improve efficiency and lower CO2 emissions, they also drive 

better economic performance of units and plants. Commenters stated that this potential is 

restrained by costs and the regulatory burdens triggered by implementing certain measures (e.g. 

New Source Review).

Commenters stated that their analysis shows a gross 6% heat rate increase across the existing 

fleet is perhaps technically possible, but only achievable at an unreasonable cost. Commenters 

estimated the total economic potential for heat rate improvements in the existing coal fleet to 

instead be as high as ~4% gross, through a combination of operational and equipment 

improvements and because of anticipated market conditions and potential regulatory barriers to 

implementation, most of these improvements are likely to happen in a 42GW subset of the 

existing fleet. Commenters stated that as a result, they expect to see potential deployment of 

HRIs to be closer to a 1% gross, on average, across the fleet. Commenters stated that effective 

NSR reform is critical to unlock more potential from existing coal-fired power plants.

Commenters stated that EPA's formula for setting the targets includes an expected 6% 

improvement in heat rate at coal-fired power plants. Commenters stated that such investments 

are likely to require significant sums of capital 

Commenters stated that they own and operate one coal-fired power plant, the Charles R. 

Lowman Plant ("Lowman"), in Leroy, Alabama. Commenters stated that Lowman consists of 

three units, which have a net generating capacity of 556 MW. Commenters stated that their coal 

generation accounts for nearly half of its base load and load-following generation resources. 

Commenters stated that Unit 1 is an 86 MW wall-fired unit, while Units 2 and 3 are 235 MW 

Riley Turbo-fired units. Commenters stated that Unit 1 is equipped with a cold side precipitator, 

and Units 2 and 3 feature hot side precipitators and were originally equipped with Peabody spray 

type flue gas desulfurization ("FGD"), with dry stacks and 70 percent FGD bypass for reheat. 

Commenters stated that in 2008, they undertook a $350 million air quality control project to 

prepare for compliance with the Clean Air Interstate Rule. Commenters stated that this 

investment doubled the value of the Lowman Plant and more than adequately prepared Lowman 

to comply with MATS, the Cross State Air Pollution Rule ("CSAPR"), and all other air 

regulations they could reasonably foresee. Commenters stated that the project included 

construction of a jet bubbling reactor ("JBR") FGD to scrub 100 percent of the flue gas from 

Units 1 and 2, the construction of a new wet stack for Units 1 and 2, installation of a Selective 

Catalytic Reduction ("SCR") for NOx control, and 100 percent scrubbing of Unit 3 using the 

existing FGD equipment and old stack. Commenters stated that Lowman is their only native 

generation coal resource, and it is an integral part of maintaining diverse, reliable, and costeffective power generation for their members. 
499

Commenters stated that the six percent heat rate improvement EPA proposes as Building Block 1 

is unachievable for existing fossil fuel-fired EGUs, and EPA does not provide adequate technical 

justification for this Building Block. Commenters stated that there simply are no efficiency 

projects that EGUs can perform to achieve a six percent improvement in heat rate and if there 

were such projects, EGU owners would have already completed them. Commenters stated that 

the fact that EPA found past heat rate improvements at existing EGUs does not demonstrate that 

future heat rate improvements can be performed to reduce CO2 emissions and past heat rate 

improvement projects only illustrate that the utility industry has a strong economic incentive to 

perform heat rate improvements and those improvements have already been completed.

Commenters stated that remaining available plant efficiency improvement for EGUs is closer to 

1%, and the proposed CPP will force those improvements to be made. Commenters stated that 

for example, from 2005-2012, they invested $40 million dollars in efficiency projects resulting in 

a 3.1% decrease in net heat rate at Merom. Commenters stated that this heat rate improvement 

would have been more substantial, except that compliance with other environmental rules 

required further expenditures of $280 million dollars to reduce SO2 by 79% and NOx by 78% 

over the same time period and additional pollution control equipment added in this time period 

increased auxiliary power to 33.3 MWs, a 16% increase from 2005-2013. 

Commenters stated that they have been committed to energy efficiency programs, not only to 

improve efficiencies of the Dallman units, but also in programs for their customers, to reduce 

energy use through conservation. Commenters stated that for example, in 2007, an Energy 

Assessment of Dallman units 31, 32 and 33 was performed to determine ways to improve 

efficiency and reduce energy loss and they then implemented many of the recommendations, and 

continue to do so. (Having recently assessed and implemented such recommendations will make 

attaining an additional 6% heat rate improvement economically if not physically impossible.

Commenters stated that they have invested in heat rate improvements and continue to implement 

recommendations from a 2007 Energy Assessment. Commenters stated that many utilities have 

commented that a heat-rate improvement of 6% is unrealistic. Commenters stated that they too 

believe it would be unrealistic to attain another 6% gain over heat rate improvements they have

already made. Commenters stated that they continuously evaluate options for economic 

improvement in heat rate efficiency and undertake those investments when viable and prudent 

and in 2007, they contracted with Sigma Energy Solutions, Inc. to perform an energy assessment 

on the three (3) small older units, 31, 32 and 33. Commenters stated that the study cost 

approximately $80,000 and among the recommendations which were implemented were to 

address cycle isolation (leaking valves), boiler performance issues including loss of ignition 

(LOI) and the potential for incomplete combustion. Commenters stated that in addition, long 

term recommendations regarding turbine performance were made that can only be addressed 

during turbine overhauls. Commenters stated that they continually replace leaking valves during 

outages, improvements were made in the combustion of each unit and the turbines have all been 

through an overhaul. Commenters stated that they estimate that they spent approximately 

$200,000 to implement the more routine recommendations, the majority of which are performed 

annually, while turbine overhauls cost over $8M. Commenters stated that Units 31 and 32 

turbine overhauls were completed in 2007, while Unit 33's turbine overhaul was just completed 

this past spring, and they spent over $1.9 million on improving turbine efficiency during this 

outage. Commenters estimated that the work to implement the recommendations to Unit 33 
500

resulted in a 9.31% heat rate improvement, while the heat rate improvements to the two smallest 

units were less. 

Commenters stated that while they chose to make efficiency investments for the benefit of their 

community, investments in these units will not significantly impact the overall state emissions as

Unit 33 emits only 1.06% of the total carbon emitted by all fossil-fuel burning EGU's in Illinois. 

Commenters stated that Dallman Unit 4, which emits only 1.04% of Illinois' carbon emissions, 

began commercial operation in 2009, which suggests that achieving the requisite 6% 

improvement to such a new unit, or combined with their smaller older units already improved, 

would be unrealistic. Commenters stated that to show the negligible impact these units have on 

total statewide GHG, a calculation of the assumed 6% heat rate improvement on these units only 

provides for 0.0636% (Unit 33) and 0.0624% (Unit 4) reduction in statewide GHG emissions. 

Commenters stated that their two smallest units, 31 and 32, have an even smaller impact on 

Illinois' GHG emissions. Commenters stated that each have a nameplate capacity of only 90.3 

MW (under USEPA's Clean Air Market Division) and are a beneficial part of their investments 

in APC's and their 2007 efficiency assessment (and implementation) program. Commenters 

stated that because they have already paid for the best heat rate improvements, it would require 

huge expenditures to gain negligible GHG reductions under this building block. Commenters 

stated that performing another energy assessment would not be expected to result in any 

measurable improvements and since achieving another 6% heat rate improvement would not be 

feasible or economically viable for their facility, credit should be given for the improvements 

already achieved. 

Commenters stated that the New Source Review is a major factor in the consideration of a utility 

to retrofit or upgrade any plant and many utilities in the past have implemented efficiency 

improvements to their units only to be forced into New Source Performance Standards, adding 

potentially hundreds of millions of dollars to the plant cost. Commenters stated that the threat of 

New Source Review will be a disincentive for utilities to invest in efficiency improvements.

Commenters urged the EPA to consider the difference in investment behavior of their customers 

in regulated vs. merchant markets. Commenters stated that the incentive for capital expenditure 

to improve plant performance is different in each case and should be a part of evaluating each 

state's plan. 

Commenters stated that Block one allows existing plants to improve their efficiency by 

implementing new measures but this is problematic because the owners of coal-fired units in 

North Dakota have recently invested hundreds of millions of dollars to comply with the regional 

haze program. Commenters stated that EPA's requirements would shut down certain coal-fired 

units and would make new NGCC economically infeasible, raising electricity prices. 

Commenters stated that opportunities for efficiency improvements are negligible in many cases, 

as the plants are already operating in a highly efficient manner. Commenters stated that rather, 

EPA should take into account the progress already being made, give North Dakota companies 

credit for the progress, and rework the proposed rule so that these companies' innovation is not 

stifled 

Commenters stated that also of concern is that regulated units could find additional efficiencies 

with significant investment and redesign, the investment may result in additional regulation 

under 111 (b) as well as 111 (d) (as both a new and existing resource). Commenters stated that 
501

this is not a legal action and is contrary to the governing statutes. Commenters stated that any 

final emission guideline that is based in whole or in part on heat rate improvements must provide 

affected EGU's with relief from New Source Review requirements for implementing those 

measures. 

Comment 7: Comments regarding the 2009 Sargent & Lundy report and the EPA’s heat rate 

reduction economic assessment

Response 7: For the EPA’s response to these comments, see section V.C of the final rule 

preamble of the CPP and Chapter 2 of the GHG Mitigation Measures TSD supporting the final 

CPP. For example, as discussed in those documents, the EPA’s assessment of the costs of many 

heat rate improvement measures is conservative, and the overall costs are reasonable. 

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

Commenters stated that heat rate improvement estimates provided in the 2009 S&L Report were 

incorrectly applied in the GHG Abatement Measures TSD when the HRI methods were 

combined as though they were applied to a single EGU to establish a combined fleet-wide 

minimum/maximum heat rate improvement range of 415-1,205 Btu/kWh (or 4% to 12%).

Commenters stated that the 2009 S&L Report focused on HRI methods that have been 

successfully implemented by the utility industry, included brief descriptions of each HRI method 

and how each method may be applied to existing units, and provided discussion of the 

effectiveness and some of the limitations associated with each method. Commenters stated that 

the study included estimated ranges of the heat rate improvement associated with each HRI 

method, as well as estimated ranges of the associated costs. Commenters stated that two case 

studies were included in the report to illustrate how plant-specific design, operation, and other 

factors affect the availability and effectiveness of the potential HRI methods, and how these 

plant-specific factors are taken into consideration in an HRI audit.

Commenters stated that in the GHG Abatement Measures TSD, EPA combined the HRI methods 

included in the 2009 S&L Report "as though they were all applied to a single EGU" to obtain the 

following heat rate reductions and capital costs:

• Combined Min-Max HRI Btu Reduction: 415-1205 Btu

• Combined Min-Max HRI Capital Cost: $40-$150/kW

Commenters stated that by combining the HRI methods, EPA concluded that, "HRI methods 

could possibly reduce [the] average coal fleet heat rate by about 400 to 1200 Btu/kWh, or by 

about 4% to 12%, provided that all units were able to apply all of the combined HRI methods." 

Commenters stated that EPA acknowledged that the "wide ranges of estimated HRI Btu and 

costs are indicative of the wide range of real differences in the many details of site specific EGU 

designs, fuel types, age, size, ambient conditions, current physical condition, etc." Commenters 

stated that nevertheless, EPA combined all of the HRI ranges, as if they were applied to a single 

EGU, as its basis for projecting potential fleet-wide heat rate improvements.
502

Commenters stated that heat rate improvement opportunities included in the 2009 S&L Report 

cannot be combined as though they were applied to a single EGU. Commenters stated that the 

report analyzed each method independently for three boiler sizes (200 MW, 500 MW and 900 

MW) and applied a range of heat rate improvement potentials and capital costs to each size 

category and that the report also includes discussion of the applicability, effectiveness, and some 

of the limitations associated with each method. Commenters stated that additional limitations 

would also be identified when unit-specific HRI audits are performed on individual EGUs. 

Commenters stated that case studies included in the report demonstrate that it would not be 

feasible to apply all of the examined alternatives from the study to an individual generating unit 

due to a number of factors, including, but not limited to, plant design, previous equipment 

upgrades, and existing operation and maintenance practices. Commenters stated that the ability 

to apply each HRI method, and the amount of heat rate reduction that can be achieved, is sitespecific and must be evaluated on a case-by-case basis.

Commenters stated that they note that IPM projects, under the base case, CO2 emissions from 

coal-fired EGUs of 98,363,280 tons, and total generation of 94,404,769 MW-h. Commenters 

stated that under the state compliance plan policy case, these emissions are 92,687,274 tons, with 

total generation of 94,553,848 MW-h. Commenters stated that the projected increase in 

generation from coal under the policy case coupled with a significant reduction is CO2 emissions 

would seem to indicate that HRIs are strongly discounted in the IPM projections and represent 

within the model a cost-effective means for reducing the overall state emission rate. Commenters 

stated that although they believe U.S. EPA's proposed HRIs are not achievable in Ohio, using the 

example provided in the S&L Study for a 250 MW unit, they very conservatively estimate the 

capital costs to achieve the state-wide 7.7% HRI projected under the policy case would be 

approximately 751 million dollars. Commenters reiterated here two specific points; firstly, the 

751 million dollar estimate derived from this analysis is presented here only to illustrate their

contention that the true capital costs of HRIs were inadequately accounted for by U.S. EPA and 

that they believed this illustrative cost is drastically underestimated; second, the commenters

contended that the 6% HRI envisioned by U.S. EPA, let alone the 7.7% HRI modeled by IPM for 

Ohio, is unobtainable. Commenters stated that this contention is supported not only by their

analysis, but by, among others, Sargent & Lundy in their October 15, 2014 letter and NERC's 

November 2014 Initial Reliability Review.

Commenters affirmed that the cost estimate example provided in the S&L Study is not fully 

representative of individual coal-fired units in Ohio and underestimates true costs, but enables 

some scrutiny of IPM results. Commenters believed that capital costs necessary to realize a 7.7% 

HRI in Ohio's coal-fired fleet would be significantly greater than the 751 million dollar estimate 

and this number is simply a convenient reference point. Commenters stated that these same HRIs 

were projected by IPM to be approximately 150 million dollars in terms of capital costs. 

Commenters stated that U.S. EPA must consider more appropriate and realistic HRI costs in the 

IPM projections and additionally, these costs estimates should be derived from real-world HRI 

projects at coal-fired power plants, with consideration given to the feasibility of such projects in 

both vertically integrated and deregulated, competitive power markets. Commenters stated that 

U.S. EPA is relying on flawed studies or the misapplication of studies and modeling to produce a 

totally inaccurate result.
503

Commenters believed that the unrealistic price of HRIs implemented by U.S. EPA in the IPM 

projections produced very unrealistic HRIs both state-wide and at individual units. Commenters 

has selected several of these as examples; firstly, Kyger Creek Unit 2 was projected to 

experience a 30% HRI over 2012 levels by 2025 and other units at the Kyger Creek plant are 

projected to realize 15% HRIs. Commenters stated that Unit 1 at the General James M. Gavin 

plant is projected to realize an 11% HRI and Unit 2 at the same facility to realize a 9% 

improvement. Commenters understand that as a state with a deregulated power market, it is 

highly beneficial and profitable for EGUs to operate at the most efficient levels possible, thus, if 

it were technically feasible for units at Kyger Creek to improve their efficiencies by 15 to 30%, 

those units would have already done so due to market forces alone, independent of any 

rulemaking. Commenters stated that if HRIs are to be considered part of a BSERs, U.S. EPA 

must consider realistic, attainable, and available HRIs in all aspects of the rulemaking process, 

including IPM projections. Commenters stated that additionally, U.S. EPA must recognize the 

fundamental differences between vertically integrated and deregulated power markets in all 

aspects of any rulemaking, including IPM projections and cost assumptions.

Commenters stated that because EPA's technical data is lacking, its cost data is suspect, as well. 

Commenters stated that EPA estimates that a fleet-wide average heat rate net improvement of 

6% would cost only $6 to $12 per ton of CO2 removed. Commenters stated that the actual costs, 

however, are likely to be dramatically higher. Commenters stated that while they find that a 4% 

gross heat rate improvement is economically possible across the coal-fired fleet, this estimate 

does not take into account already-implemented equipment upgrades and parasitic load from 

pollution control projects. Commenters stated that moreover, the actual average, fleet-wide gain 

in efficiency that can be expected based on the high cost of heat rate improvements is closer to 

1% gross and around a 0.5% net. Commenters stated that EPA must revise its Building Block 1 

estimates to reflect current data on what is actually achievable at reasonable costs. Commenters 

stated that failure to do so would render EPA's state targets arbitrary and capricious.

Commenters stated that the Sargent & Lundy report on which EPA relies was a 2009 study that 

relied on 2008 data, four years prior to the baseline EPA assumes in its building block formula 

and as that report stated, "[a]ll estimated capital and installation costs are referenced from work 

in progress and vendor quotes as of the year 2008." 

Commenters stated that in any event, the Sargent & Lundy study was not designed for 

rulemaking purposes generally, nor does it support the specific assumptions that EPA has made. 

Commenters stated that for example, the introduction of the report explains that its cost figures 

are intended to be accurate only on an "order of magnitude" level, and those cost figures are 

provided only for "comparison purposes" when evaluating the advantages and disadvantages of 

one project against another. Commenters stated that the report specifically notes that those cost 

estimates "should not be used as a basis for project budgeting or financing purposes." 

Commenters stated that the report also notes that its calculations are based on the hypothetical 

"design" heat rate of coal units, which units can achieve (if at all) only during full load operation, 

not the actual heat rate of units, which the reports admits "are usually significantly higher than 

the design heat rate." 

Commenters stated that most, if not all, of the power companies have already invested 

significantly to increase heat rate, and realize that any new efforts to improve heat rate will be 
504

vastly more difficult to achieve. Commenters stated that all the low hanging fruit, so to speak, 

has already been picked, leaving only projects that provide small incremental improvements and 

for example, EPA states that the 6% increase in heat rate can be achieved at an average cost of 

approximately $100/k W or less. Commenters stated that according to studies by NERA 

Economic Consulting, it is more likely that measures costing $100/k W or less will improve heat 

rates by a mere 1.5%- a far cry from EPA's more rosy projections.

Commenters stated that while they chose to make efficiency investments for the benefit of their 

community, investments in these units will not significantly impact the overall state emissions. 

Commenters stated that Unit 33 emits only 1.06% of the total carbon emitted by all fossil-fuel 

burning EGU's in Illinois. Commenters stated that Dallman Unit 4, which emits only 1.04% of 

Illinois' carbon emissions, began commercial operation in 2009, which suggests that achieving 

the requisite 6% improvement to such a new unit, or combined with their smaller older units 

already improved, would be unrealistic. Commenters stated that to show the negligible impact 

these units have on total statewide GHG, a calculation of the assumed 6% heat rate improvement 

on these units only provides for 0.0636% (Unit 33) and 0.0624% (Unit 4) reduction in statewide 

GHG emissions. Commenters stated that their two smallest units, 31 and 32, have an even 

smaller impact on Illinois' GHG emissions. Commenters stated that each have a nameplate 

capacity of only 90.3 MW (under USEPA's Clean Air Market Division) and are a beneficial part 

of their investments in APC's and their 2007 efficiency assessment (and implementation) 

program. Commenters stated that because they have already paid for the best heat rate 

improvements, it would require huge expenditures to gain negligible GHG reductions under this 

building block and performing another energy assessment would not be expected to result in any 

measurable improvements. Commenters stated that since achieving another 6% heat rate 

improvement would not be feasible or economically viable for their facility, credit should be 

given for the improvements already achieved. 

Commenters stated that their analysis concludes a total heat rate improvement up to 1.5% from 

current operating parameters is the maximum attainable at an economically justifiable cost for a 

merchant unit. 

Commenters stated that because EPA's technical data are lacking, its cost data is suspect, as well. 

Commenters stated that EPA estimates a fleet-wide average 6 percent heat rate improvement will 

cost only $6 to $12 per ton of CO2 removed, but the actual costs are, however, dramatically 

higher. Commenters stated that their internal preliminary analysis suggests that heat rate 

improvements of 2 percent to 3 percent could be achieved, but at costs well in excess of $6 to 

$12 per ton of CO2 removed. Commenters stated that they are concerned that the proposed Clean 

Power Plan's impact on the market price for power means that they would be saddled with costs 

which make it permanently less economic than other Virginia Power generation options, 

resulting in greater price fluctuations, less operating time, and more cycling that will likely 

negate incremental heat rate improvements. 

Comment 8: Stakeholder provided approaches - economic potential for total HRI opportunity
505

Response 8: See section V.C of the final rule preamble of the CPP and Chapter 2 of the GHG 

Mitigation Measures TSD supporting the final CPP for EPA’s response to this comment. We 

appreciate these commenters’ comments and suggestions. For the reasons stated in the abovereferenced portions of the preamble and TSD, we believe that our final approach to calculating 

costs for building block 1 is conservative, reasonable, and appropriate given the nature of this 

rulemaking.

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

Commenters stated that building on the analysis of the technical potential for HRIs in the 

existing coal-fired steam boiler fleet, the economic potential is the subset of the technical 

potential that is cost-effective. Commenters stated that plant owners vary widely in the criteria 

used to select how efficiency projects are prioritized and how the benefits are evaluated 

financially. Commenters stated that in some cases, the products and services identified as heat 

rate improvements in their table A-1 (Appendix A) are performed as routine/required 

maintenance and the efficiency improvements are secondary or inadvertent to the decisionmaking process. Commenters stated that adding to the complexity of the economic evaluation, 

improving an EGUs heat rate will improve the units competitive position in the energy market, 

potentially altering their future sales, revenue and cost; and thus, altering the valuation of the 

project. Commenters stated that competitive gains for an individual unit could be subdued if 

some or all coal-fired EGU fleet it competes against were to implement the same changes.

Commenters decided to compare the effective cost of removing CO2 for each of the HRIs 

identified in the technical potential to the "social cost of carbon" (SCC) and limit the HRI 

options considered in the economic potential to those whose cost of CO2 removed is near to or 

below the social cost of carbon. Commenters stated that the process used to determine the cost of 

CO2 removed and ultimately determine the economic potential is outlined below:

1. Estimate costs associated with Best Practice and Upgrade HRIs

2. Convert HRI project costs to dollars per metric ton of CO2 removed

3. Determine economic potential of HRIs for generic EGUs using a subset of the technical 

potential that is less expensive than the SCC

4. Determine economic potential of HRIs for the coal-fired steam boiler fleet

1. Commenters stated that as an interim step for determining the economic potential for the HRI 

solutions, an estimated cost was associated with each of the HRIs. Commenters stated that the 

estimated costs were given a lower and upper estimate for both O&M and capital cost and the 

following areas were considered when estimated costs for HRIs from Best Practices:

(a) Performance testing to understand current plant performance or to baseline plant.

(b) Improved plant instrumentation and measurement to support better periodic 

performance testing/diagnostics, but also to support or improve monitoring programs.
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(c) Plant assessments including optimization of performance through operational 

changes, expanded or more flexible operation of the steam turbine unit supported by onsite assessments and engineering studies. Plant assessments also consider improvements 

that can be addressed with minor maintenance outages (including improvements in 

identifying and reducing system leakages). Estimated costs were considered for 

implementing typical recommendations (e.g. repair/replace leaking valves, install/replace 

critical instrumentation) and, in some cases, allowing for engineering assessments 

required to implement minor hardware and controls changes (e.g. to improve part load 

performance or expand operational envelope of ST unit).

(d) Optimized O&M through use of advanced performance monitoring systems, 

advanced software and smart sensors. This assumes improvements realized through more 

timely and better prioritized maintenance, resulting in better sustained performance over 

time. Also supports better asset management by providing more information on scope 

and needs for outage planning.

Commenters noted:

• In general, the costs considered not only the expense that may be incurred to 

baseline a plant or to assess/study the HRI opportunities, but also the expense to 

follow through on the recommendations. Estimated 'typical' scope of work was 

assumed for what the implementation scope would include.

• Costs associated with compliance or performance guarantee testing that could be 

implemented along with HRI projects to demonstrate the improvements were not 

considered.

2. Commenters stated that in order to determine the economic potential for both current and new 

heat rate improvement technology several assumptions were made to assess the estimated costs 

for each HRI and the following areas were considered when estimating costs for HRIs from 

turbine upgrades:

(a) Performance testing to understand current plant performance or to baseline plant

(b) Nominal plant performance based on expected turbine losses following 5-10 years of 

normal plant operation

(c) Installation costs associated with removing existing hardware and implementing the 

upgraded heat rate improvement technology

(d) Maintenance and warranty costs were included as well as for the current heat rate 

improvement technology

Commenters stated that to convert the project costs for the HRIs into dollars per metric ton of 

CO2 removed, an estimate of the tonnes of CO2 removed per year was divided by the levelized 

cost of each HRI. Commenters stated that the CO2 removed was calculated assuming a 

representative steam-coal unit that had the following attributes:
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• CO2 Rate = 205 lbs/MMBtu

• Capacity Factor = 70%

• Net Heat Rate = 10,460 Btu/kWh, Generation weighted avg. of US coal fleet in 

'13, excluding anticipated retirements and cogen units

The levelized costs for each HRI was calculated using the following assumptions:

• Capital expense

o Fixed and variable operations and maintenance costs

o Fixed charge rate of 16%

• Table A-4 summarizes the $/tonne of CO2 removed per HRI for a 500 MW coalfired steam boiler unit. A similar analysis was completed for the 200 and 900 MW 

size classes used in the technical potential. 

The Social Cost of Carbon - Commenters stated that there are a variety of studies 

that assess the social cost of carbon (SCC) and for consistency, they used the 

same study EPA referenced in their technical support document (TSD) for the 

final target year of 2030. Commenters chose the middle value (3% discount rate) 

of $32.8/tonne in 2007 which they escalated to ~$36/tonne in 2013.

3. Commenters stated that to determine economic potential of HRIs for generic EGUs, the HRIs 

were ranked in order from least to most expensive (per tonne of CO2 removed). HRIs with 

$/tonne of CO2 removed less than the social cost of carbon were assumed to be part of the 

economic potential. Commenters stated that HRIs that were more expensive than the social cost 

of carbon were excluded from the economic potential. Commenters referred to Figure A-3 which 

summarizes the cost curves created for the economic potential analysis. Commenters stated that 

5.3% of the HRIs in the technical potential were determined to be less expensive than the social 

cost of carbon, for the small and medium sized EGUs (less than 650 MW). Commenters stated 

that an additional 1% of HRI potential may exist for the large EGUs, due to economies of scale 

that move the advanced steam turbine technologies below the social cost of carbon.

4. Commenters stated that to determine economic potential of HRIs for the coal-fired steam 

boiler fleet, the same three phased approach from the fleet wide technical potential analysis, 

which caps HRIs for each EGU at the best in class 9,400 Btu/kWh FLHR, was used to assess the 

economic potential of the coal fleet. Commenters stated that for stage 1, their estimated range of 

HRIs available to generic EGUs that are lower than the social cost of carbon are summarized in 

table A-5. Commenters stated that the values in table A-5 also assume the EGU has not 

implemented any of the best practice or upgrade HRIs and thus, has the full economic potential 

available.

Commenters stated that in stage 2, they estimated the economic potential for each EGU in the 

fleet using the best in class FLHR assumption and then the fleet-wide fuel burn in stage 3 was 

recalculated using each units economic potential identified in stage 2.
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Commenters stated that for the economic potential, commenters made a final adjustment 

downward to the resulting fleet-wide % improvements in stage 3 to account for cycling and partload operations. Commenters believed that a significant portion of the coal fired EGU fleet will 

run at part load in the future and the majority of the HRIs have lower efficiency benefits at part 

load. Commenters stated that the final estimate for economic potential is summarized in figure 

A-4 (bar chart of MMBtus Coal Burn in 2013 vs. Full Load Heat Rate), where ~4% is the 

assumed economic potential. Commenters stated that this is still not a net fleet average as it does 

not take into account increased parasitic load from scrubbers, SCR, ACI, etc., installed post 2013 

in response to CSPAR and Mercury MATS. 

Comment 9: Comments regarding EPA’s conclusions regarding the effect of fuel costs

Response 9: For the EPA’s response to these comments, see section V.C of the final rule 

preamble of the CPP and Chapter 2 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 HRI reduces fuel costs, on a per kW basis, but EPA's analysis, which 

focuses on annualized costs, ignores the lag between capital expenditures and fuel cost savings. 

Commenters stated that HRI capital costs may be financed, which spreads the costs over time. 

Commenters stated this financing is dependent on continued operation of the unit to create a 

revenue stream that allows the capital costs to be repaid over time. Commenters stated that 

EPA's own analysis indicates that many existing coal-based units will be retired by 2020 and that 

the utilization of the remaining units will decrease as part of states' compliance efforts. See 

Regulatory Impact Analysis (RIA) at 3-32. Commenters stated that this dramatically shortens the 

payback period, and therefore, reduces the electricity sales that are necessary to support capital 

costs investments in HRI measures. Commenters further stated that to some extent, EPA 

recognizes this, noting that "reductions in the utilization rates of coal-fired EGUs anticipated 

from other components proposed for inclusion in ... [BSER] would tend to reduce the fuel 

savings associated with [HRI], thereby raising the effective cost of achieving the CO2 emission 

reductions." 79 Fed. Reg. at 34,861. Commenters stated that EPA quickly dismisses - without 

any analysis - the impact that reduced utilization would have on the reasonableness of HRI costs, 

stating "[n]evertheless, we still expect that the majority of the investment required... would be 

offset by fuel savings." Id. at 34,861. Commenters stated that EPA does not address at all the 

potential impact of early retirement on its cost estimates. 

Commenters stated that in 2010, in collaboration with one of their members utilities, they issued 

the results of a year-long study titled "Methodology for Fleet-wide Energy Efficiency Analysis". 

Commenters stated that the focus of the research was the evaluation of power plant projects that 

would reduce CO2 emissions by improving plant efficiency. Commenters stated that a team of 

experts, including assistance from the commenters, developed a list of potential projects to 

improve power plant efficiency. Commenters stated the team developed estimates for each 

project including the cost to implement and the potential heat rate improvement. Commenters 

stated that then they determined which projects were applicable to each of their operating units. 
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Commenters stated that those 174 capital projects were studied in detail to determine accurate, 

unit-specific costs and heat rate improvement values. Commenters stated that of those 174 

projects, 58 "top priority" projects were deemed as "no cost," since fuel savings would 

eventually offset capital costs after 30 years. Commenters stated the initial cost to implement the 

58 projects across this fleet was $61 million and the expected improvement in the heat rate of 

those plants was 2.5%. Commenters stated the remainder of the identified projects were 

estimated to cost $740 million to achieve an additional heat rate improvement of 2.5%.

Commenters stated that cost data provided in the 2009 S&L Report were incorrectly applied in 

the GHG Abatement Measures TSD when EPA combined HRI costs as though they were all 

applied on a single EGU to establish a combined fleet-wide minimum/maximum HRI capital 

cost. Commenters stated that EPA in the "Heat Rate Improvement Breakeven Analysis" relied 

primarily on capital costs provided in the 2009 S&L Report to establish its $100/kW total capital 

cost, which, EPA concluded was "a representative combined HRI capital cost to achieve 

whatever HRI Btu reduction is possible at an average site." Commenters stated that to establish 

this number, EPA apparently divided the range of capital costs ($) provided in S&L's report by 

the boiler size range (kW) to calculate minimum and maximum $/kW values for each HRI 

method. Commenters stated that EPA then summed the $/kW values for each HRI method to 

calculate a combined Min-Max capital cost as though all methods were applied to a single EGU. 

Commenters stated this methodology does not provide an accurate estimate of the costs that will 

be incurred to implement HRI methods at any given facility, or on an average fleet-wide basis, 

for at least two reasons; first, costs included in the 2009 S&L Report were not intended to serve 

as the basis for calculating the total actual costs that may be incurred to implement the HRI 

methods, and second, HRI costs must be evaluated on a case-by-case basis and should not be 

combined as if all HRI methods could be applied to a single unit.

Commenters stated that the 2009 S&L Report clearly states that costs "presented herein are not 

indicative of those that may be expected for a specific facility due to variables such as 

equipment, material, and labor market conditions and site specifications." and continues that 

costs included in the 2009 S&L Report were intended to provide "information for comparative 

purposes when evaluating the advantages and disadvantages of the various 

concepts.". Commenters stated that taking into consideration the purpose and limitations of the 

cost ranges included in S&L's 2009 Report, cost data provided in the report should not be used as 

the basis for establishing minimum or maximum fleet-wide HRI costs, and furthermore, case 

studies included in the 2009 S&L Report show that it is not feasible to apply all of the HRI 

methods to an individual unit, and that HRI implementation costs can vary significantly based on 

unit type, fuel type, plant design, previous equipment upgrades, retrofit difficulty, and many 

other site-specific factors. Commenters stated that cost ranges provided in the 2009 S&L Report 

represent order-of-magnitude costs and were provided for comparative purposes only, and that 

the cost ranges were not intended to serve as the basis for calculating minimum or maximum 

fleet-wide HRI implementation costs.

Commenters stated that HRI cost ranges included in the 2009 S&L Report show that, in general, 

HRI methods will be more costly on a $/kW basis on smaller units. Commenters stated that, for 

example, based on heat rate improvement ranges and capital costs included in the S&L report, 

turbine overhaul projects could cost between $5.6 and $27.8/kW on larger units, but cost 

between $10 and $60/kW on smaller units. Commenters stated that EPA acknowledged in the 
510

GHG Abatement Measures TSD that "the economy of scale of larger units allows the use of 

higher cost improvements to be more economic" and "economy of scale causes most HRI 

methods to be more costly ($/kW) on smaller units," yet, the economic impact analysis included 

in the GHG Abatement Measures TSD is based on average values that do not account for any 

unit-specific feasibility issues or costs, including economy of scale, and results in the erroneous 

conclusion that HRI methods are generally more cost-effective on smaller units.

Commenters stated that all of the HRI methods evaluated in the 2009 S&L Report showed 

significant variability in both the potential heat rate improvement and costs, for example, the 

combined overall heat rate improvement associated with upgrading a plant with new centrifugal 

fans with VFD ranged from 10 to 150 Btu/kWh for all boiler size categories (200 MW, 500 MW 

and 900 MW), with costs ranging from $6 to $16 million depending on unit size and retrofit 

difficulty. Commenters stated that the cost-effectiveness of this potential HRI method will vary 

significantly from plant to plant and must be evaluated on a case-by-case basis taking into 

consideration technical feasibility, effectiveness, and costs. Commenters stated that the same 

result applies to all HRI methods with wide ranges of both HRI improvement and HRI costs and 

applying an assumed total capital cost to an average heat rate improvement masks the wide range 

of HRI improvement and costs presented in the 2009 S&L Report.

Commenters stated that in determining the capital cost of equipment upgrades, EPA again relies 

exclusively on the S&L Report, although the Agency acknowledges that S&L only includes 

estimated minimum/maximum ranges of heat rate improvements and associated capital cost for 

each equipment upgrade for units ranging in size from 200 to 900 MW. Commenters stated that 

the proposed guidelines impact coal-fired EGUs less than 200 MW and economies of scale, as 

stated by EPA, cause most equipment upgrades to be more costly on smaller units. Commenters 

stated that, to meet its regulatory obligation, EPA must appropriately evaluate the cost of 

equipment upgrades for all affected size classes.

Commenters stated that EPA has also not considered the impact of its four Building Block BSER 

determination on the cost of best practices and equipment upgrades. Commenters stated that 

EPA's proposal is intended to lower the utilization of coal-fired EGUs. Commenters further 

stated that EPA's equipment upgrade cost analysis, however, is based upon an average coal-fired 

EGU capacity factor of 78 percent in 2012 and that lower net capacity factors, due to Building 

Blocks 2, 3, and 4, will result in significantly less fuel savings from equipment upgrades. 

Commenters further stated that lower capacity factors reduce the opportunities for plants to 

recoup the costs of capital expenditures (or require a correlated rise in prices to compensate for 

those costs) and that equipment upgrades would not be economic at lower net capacity factors. 

Commenters also stated that it also appears that EPA did not correctly consider the cost of heat 

rate improvements on a net output basis, and therefore must reassess its cost analysis to include 

costs for all potentially affected EGUs on a net output basis.

Commenters stated that significant HRIs beyond those already accomplished cannot be 

economically justified at lignite coal fueled EGUs. Commenters stated that EPA calculates that a 

6% HRI is economically feasible "if/when coal prices rise above $3.25/MMBtu" and that even at 

a "projected 2020 coal price of $2.62/MMBtu, the fleet-wide cost of CO2 reduction via 6% HRI 

would be a relatively low $7.7/tonne." Commenters stated that through August 2014, delivered 

lignite fuel costs for coal-fired plants supplied by NA Coal mines (Falkirk Mine, Freedom Mine, 
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Sabine South Hallsville Mine and Red Hills Mine) average only $1.57/MMBtu. Commenters 

stated that using EPA's methodology and with these lower fuel costs, the NA Coal customer 

fleet-wide cost of CO2 reduction was more than four times higher than EPA's estimate.

Commenters stated that there is also inconsistency between the Building Blocks that creates 

illogical results. Commenters stated that facilities like theirs would not invest in significant 

projects to chase heat rate improvements that cost hundreds of thousands or millions of dollars 

(as expected in Building Block #1) only to be dispatched less often in favor of other types of 

power plants. Commenters stated that the opportunity for return on investment with the heat rate 

improvements is lost if the improved units are dispatched less often due to artificial market 

constraints created under Building Block #2 

Commenters stated that EPA's economic analysis of heat rate improvements is unreasonable 

given its flawed assumptions. Commenters stated that for example, EPA's analysis indicates a 

66% industry average capacity factor for 2002-2012 and a decreasing trend since 2008 (GHG 

Abatement Measures TSD at Section 2.5.3, Table 2-5) which conflicts with EPA's costeffectiveness analysis of EGU heat rate improvements in GHG Abatement Measures TSD 

Section 2.6.4 in which a 78% capacity factor is assumed. Commenters stated that assuming a 

higher capacity factor artificially improves the economics of any heat rate improvements. 

Commenters stated that a 78% capacity factor for the U.S. coal-fired fleet is unrealistic given 

current trends (as shown in Table 2.5 of the GHG Abatement Measures TSD) and lower natural 

gas prices, even allowing for retirements of existing coal capacity. Commenters stated that 

further, EPA's heat rate improvement breakeven analysis (GHG Abatement Measures TSD at 

Sections 2.6.3-2.6.5) is unrealistic using a 78% capacity factor. Commenters stated that EPA's 

heat rate improvement breakeven economic analysis also fails to consider an important factor, 

namely the duration of the payback period. Commenters stated that for a typical 500 MW plant, 

based on GHG Abatement Measures TSD Section 2.6.4 the simple payback period is almost 9 

years. Commenters stated that while a 9-year payback period may be an acceptable return for 

regulated electric utilities, it is not acceptable for independent power producers. Commenters 

stated that moreover, if a more reasonable 65% capacity factor were used, the payback period 

would extend even longer to almost 11 years and finally, almost every heat rate improvement 

project identified by EPA will likely require additional expenditure to maintain the level of heat 

rate improvement, which would further increase the duration of the payback period. 

Commenters stated that furthermore, utility companies have expressed concerns about the 

difficulty in obtaining financing for these heat rate improvement projects. Commenters stated 

that because the essence of the GHG ESPS is to shift more baseload electricity production from 

coal-fired units to natural gas-fired turbines and renewable energy sources, the investment in 

coal-fired facility becomes less attractive because it will be more difficult to recover the cost of 

the investment if the facility generates less electricity. 

Commenters stated that the 6 percent goal is even less workable when taking costs into account, 

as EPA is legally required to do. Commenters has identified two potential heat-rate improvement 

projects outside of the scope of the S&L Study that are uneconomic and would then only provide 

temporary heat rate improvements and moreover, even these temporary improvements would not 

approach 6 percent. Commenters stated that as evidenced by their $350 million investment to 

ensure that Lowman functions as cleanly and efficiently as possible, they are willing to 
512

implement any economically realistic measure, particularly to improve operating efficiency. 

Commenters stated that however the proposed heat rate improvement expected under EPA's 

BSER determination is simply not realistic. Commenters stated that the tortured analysis EPA 

used to establish a 6 percent heat rate improvement goal for every coal-fired unit in the country 

is neither legal nor achievable.

Commenters stated that in sum, although potential heat rate improvements are technically 

feasible for Lowman, no "best practices" are available and the results of implementing the two 

equipment upgrades would be impermanent and would fall significantly below EPA's 6 percent 

assumption. Commenters stated that additionally, the high capital costs and regulatory 

uncertainties, such as triggering NSR that would accompany these undertakings also make the 

improvements unrealistic for Lowman in any event. 

Commenters stated that the first proposed component requires coal units to achieve a 6% 

efficiency improvement over current levels. Commenters stated that the EPA based this level of 

achievement on an analysis of aggregated national information with little applicability to 

individual coal units. Commenters stated that Wyoming coal units have routinely invested in new 

technologies to run more efficiently. Commenters stated that the EPA proposes a level of 

additional improvement not possible or practical given the cost. Commenters stated that the 

Agency asserts that cost increases will be offset by reduced fuel cost needs. Commenters stated 

that in Wyoming, many coal units are mine-to-mouth with fuel costs significantly lower than the 

national average. Commenters stated that the promised savings are much smaller than projected 

by the EPA. 

Commenters stated that the other three building blocks move the coal plants lower in the 

dispatch order and that increases the amount of time that the coal plant operates at part load, with 

the accompanying less favorable heat rate. Commenters stated that effect is a disincentive for a 

utility to spend money to improve the heat rate of an existing plant. Commenters stated that the 

incentive for heat rate improvements for most utilities is the opportunity to generate electricity at 

a lower cost, or more electricity at the same cost, that can then be sold to recover the investment 

but pushing coal plants down in the dispatch order forces them to operate at lower capacity 

factors or in cycling mode that provide little or no opportunity to recover the investment in 

efficiency improvements. Commenters presented a chart ("Effect of part load operation on heat 

rate", showing the increasing heat rate as operating load decreases for sub- and supercritical 

units.) and stated that improving full load heat rate does improve part load heat rate. Commenters 

stated that however, part load operation and the resulting lower capacity factor and lower 

revenue mean that the improvement pays back over a much longer period if ever. Commenters 

stated that the prospect of long term part load operation offers little incentive for coal plant 

operators to spend the money on heat rate improvement. 

Commenters stated that for power plants that operate significantly at part load and have lower 

capacity factors, it will increase the time it will take for any investment in HRI to pay for itself. 

Commenters stated that EPA included a "Heat Rate Improvement Breakeven Analysis" in the 

GHG Abatement Measures TSD to conclude that HRI is an available low-cost approach to CO2 

reduction for existing coal-fired EGUs. Commenters stated that the breakeven analysis compared 

the total annualized capital cost of all HRI methods to the projected fuel savings associated with 
513

implementing the HRI methods. Commenters stated that the analysis assumed a total HRI capital 

cost of $100/kW and a fleet-wide average heat rate reduction of 6%. 

Commenters stated that EPA's breakeven analysis compared the total annualized capital cost of 

all HRI methods to the projected fuel savings associated with implementing the HRI methods. 

Commenters stated that the analysis assumed a total HRI capital cost of $100/kW and an average 

fleet-wide heat rate reduction of 6%. Commenters stated that both the assumed cost of capital 

and the assumed heat rate reduction used in the breakeven analysis were based, in part, on 

information provided in the 2009 S&L Report. Commenters stated that EPA used the breakeven 

analysis to conclude that HRI is an available low-cost approach to CO2 reduction for existing 

coal-fired EGUs. 

Commenters stated that information in the 2009 S&L Report was incorrectly applied in the GHG 

Abatement Measures TSD to determine potential heat rate reductions and total HRI capital costs. 

Commenters stated that the 2009 S&L Report does not support the conclusion that any individual 

coal-fired EGU, or any aggregation of coal-fired EGUs, can achieve 6% heat rate improvement 

through implementation of best practices and equipment upgrades, nor does the 2009 S&L 

Report support the conclusion that $100/kW is a representative combined HRI capital cost that 

would achieve an average heat rate improvement of 6%, rather, the report supports the 

conclusion that a site-specific HRI study is required to evaluate the availability, technical 

feasibility, effectiveness, and costs of potential HRI methods.

Commenters stated that by combining an assumed total HRI capital cost with an average 

expected heat rate improvement, the GHG Abatement Measures TSD failed to take into 

consideration any site-specific feasibility, effectiveness, and cost issues associated with the 

various HRI methods. Commenters stated that furthermore, site-specific factors that can 

significantly affect HRI costs, including unit size, retrofit difficulty, and economy of scale, were 

not taken into consideration in the TSD, leading to the erroneous conclusion that HRI methods 

are, in general, more cost effective on smaller EGUs.

Commenters stated that HRI cost ranges included in the 2009 S&L Report show that, in general, 

HRI methods will be more costly on a $/kW basis on smaller units. Commenters stated that for 

example, based on heat rate improvement ranges and capital costs included in the S&L report, 

turbine overhaul projects could cost between $5.6 and $27.8/kW on larger units, but cost 

between $10 and $60/kW on smaller units. Commenters stated that EPA acknowledged in the 

GHG Abatement Measures TSD that "the economy of scale of larger units allows the use of 

higher cost improvements to be more economic" and "economy of scale causes most HRI 

methods to be more costly ($/kW) on smaller units," yet, the economic impact analysis included 

in the GHG Abatement Measures TSD is based on average values that do not account for any 

unit-specific feasibility issues or costs, including economy of scale, and results in the erroneous 

conclusion that HRI methods are generally more cost-effective on smaller units.

Commenters stated that all of the HRI methods evaluated in the 2009 S&L Report showed 

significant variability in both the potential heat rate improvement and costs. Commenters stated 

that for example, the combined overall heat rate improvement associated with upgrading a plant 

with new centrifugal fans with VFD ranged from 10 to 150 Btu/kWh for all boiler size categories 

(200 MW, 500 MW and 900 MW), with costs ranging from $6 to $16 million depending on unit 
514

size and retrofit difficulty. Commenters stated that the cost-effectiveness of this potential HRI 

method will vary significantly from plant to plant and must be evaluated on a case-by-case basis 

taking into consideration technical feasibility, effectiveness, and costs. Commenters stated that 

the same result applies to all HRI methods with wide ranges of both HRI improvement and HRI 

costs. Commenters stated that applying an assumed total capital cost to an average heat rate 

improvement masks the wide range of HRI improvement and costs presented in the 2009 S&L 

Report.

Commenters stated that the approach used in the GHG Abatement Measures TSD to evaluate the 

economic impact of the HRI methods (i.e., applying an assumed total HRI cost of $100/kW to 

achieve an average fleet-wide heat rate improvement of 6%) does not accurately evaluate the 

economic impact of potential HRI methods at any given facility, and fails to take into 

consideration any site-specific feasibility, effectiveness, and cost issues associated with the 

various HRI methods. Commenters stated that the wide range of heat rate improvement and HRI 

costs included in the 2009 S&L Report support the conclusion that the cost-effectiveness of the 

available HRI methods must be evaluated on a case-by-case basis. 

Commenters stated that EPA gives a nod to conventional cost evaluation by computing a 

supposed breakeven cost for heat rate improvement measures, TSD, p. 2-37 to 2-38, but this is 

only a nod. Commenters stated that EPA argues that the carrying cost of heat rate improvements 

can largely be met through fuel cost savings, and what is unmet should be small enough for the 

utility to absorb. Commenters stated that EPA illustrates its argument mathematically with 

calculations in the text associated with footnote 119 to the Federal Register notice. Commenters 

stated that the key is EPA's calculation and use of a national average coal price of $2.62 per 

MMBtu. Footnote 119 and TSD, p. 2-39. Commenters stated that using this average price, and 

assuming a capital cost rate of 14.3%, EPA calculates that its 6% heat rate improvement would 

produce fuel savings of $11.20 per kW-year for a capital investment of $100 per kW, leaving 

"approximately $3.10" per kW-year not covered by fuel costs. Federal Register notice, p. 52. 

Commenters stated that by a further calculation, EPA concludes that the average cost of carbon 

dioxide reductions not covered by fuel cost savings would be approximately $7.75 per metric 

ton. Id. 

Commenters stated that EPA's approach heavily discriminates against western utilities, as EPA's 

own modeling suggests and consider these results for 2016 coal prices from EPA's Integrated 

Planning Model, EPA Base Case v.5.13.

Commenters stated that it immediately becomes apparent that a western mine mouth EGU has 

far lower fuel costs than EPA assumes and that this has a dramatic impact on EPA's calculations, 

an impact that EPA cannot gloss over by recognizing that its simplified cost analysis "will 

represent costs for some EGUs better than others because of differences in EGUs' individual 

circumstances." Federal Register notice, p. 52. 

Commenters stated that when substituting an actual 2012 fuel cost for the Wyodak mine from 

FERC Form 1, $0.804 per MMBtu, into EPA's calculation, fuel costs cover only $3.44 of the 

$14.30 carrying cost, leaving $10.86 not recovered. Commenters stated that EPA's unrecovered 

cost of $7.75 per metric ton rises to $27.13 per ton, or an increase of three and a half times EPA's 

value. Commenters stated that, in the chart presented, using the calculation explained in footnote 
515

119 of the Federal Register notice, p. 194, the fuel cost per kW-year is the product of the six 

items which precede it. Commenters stated that the carrying cost reflects EPA's assumed capital 

cost rate, referenced above. Commenters stated that the 0.4 metric tons of reduced emissions are 

calculated by EPA, and the price of a metric ton of carbon dioxide is the result of dividing 

unrecovered cost by metric tons of reduced emissions as explained in the Federal Register 

Notice, p. 52. 

Commenters stated that this irrationally discriminates against western mine mouth EGUs and 

contradicts EPA's expectation that "the majority of the investment required to capture the 

technical potential for CO2 emission reductions from heat rate improvements would be offset by 

fuel savings." Federal Register notice, p. 52. 

Commenters stated that this is more than just another statistic. Commenters stated that the design 

of every generating unit was originally based on a balance of such factors as the required output, 

available fuel quality and cost, site conditions, and water supply. Commenters stated that mine 

mouth EGUs located near Gillette, Wyoming, depended on low cost fuel to offset the expense of 

air cooling. Commenters stated that measures which undermine an original cost advantage 

undermine the economics of the entire plant. Commenters stated that to a greater or lesser 

degree, EPA's economic analysis undermines the economics of every plant with a fuel cost more 

favorable than EPA's calculated average.

Comment 10: Comments regarding US - fleet wide CO2 reduction and cost via HRI 

Response 10: See section V.C. 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 first building block addresses the heat rate improvement for coal 

fired electricity generating units, or EGUs. Commenters stated that with the EPA estimating a 6 

percent reduction in CO2 emissions, these investments come to a great cost and are shouldered 

by the consumers and the customers of the utility. Commenters stated that utilities within their

state have spent hundreds of millions of dollars within the last few years just to comply with 

various regulations and the costs associated with controlling the CO2 emissions and can 

potentially have an exponential amount of increase. 

Commenters stated that the EPA identifies the average capacity factor over the 11 year study 

population as 67% (p.2-23). Commenters asked why didn't the EPA provide the projected 

average capacity factor after the application of all BBs and why was a 78% capacity factor used 

for the economic analysis? (p.2-37) 

Commenters stated that a net 6% heat rate improvement is arbitrary in several other respects. 

Commenters stated that EPA concedes that over 40% of units observed have a positive heat rate 

slope, meaning "equipment maintenance and upgrades at a significant fraction of the study 

population have not been sufficient even to maintain the status quo." Commenters stated that 

EPA nevertheless assumed that efficiency improvements would remain static, but to be accurate, 
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EPA must account for the fact that maintaining a 6% heat rate improvement will require periodic 

and expensive upgrades. 

Commenters stated that EPA concludes that the "vast majority of existing coal boilers" would 

undertake heat rate improvements at capital costs of $100 per Kw, " and specifically, EPA 

"projects that 176 to 179 GW of existing coal steam capacity (greater than 25 MW) will improve 

operating efficiency (i.e., reduce the average net heat rate) under Option 1 in 2020." Commenters 

stated that these estimates overstate the extent to which existing EGUs will make heat rate 

improvements, and EPA's analysis does not recognize the rapidly escalating incremental costs 

per ton of CO2 removed past 2-3% in efficiency gains. Commenters stated that modeling 

undertaken by GE suggests that only approximately GW of the approximately 220 GW coalfired units expected to be in existence in 2030 would find it economical to undertake efficiency 

projects and this amounts to a less than 1% average heat rate improvement across the fleet. 

Commenters stated that the incremental costs of a 6% HRI, or even a 2 or 3% HRI, could 

seriously threaten the commercial viability of coal-fired facilities like their facility. 

Commenters did not believe that the cost of HRI at any plant should be considered reasonable, as 

every plant will have its own physical, operational, and economic limitations which will put a 

financial burden on the rate payers. 

Commenters stated that in its proposal EPA states: "Building block 1- reducing the carbon 

intensity of generation at individual affected coal-fired steam EGUs through heat rate 

improvements - is a component of the BSER because the measures the affected sources may 

undertake to achieve heat rate improvements are technically feasible and of reasonable cost, and 

meet the other requirements to qualify as a component of the "best system of emission reduction" 

... adequately demonstrated." 79 Fed. Reg. at 34,881-82. Commenters stated that EPA states 

further: "We estimated that CO2 reductions of between four and six percent from overall heat 

rate improvements could be achieved on average across the nation's fleet of coal-fired steam 

EGUs for net costs in a range of $6 to dollar 12 per metric ton." Id. at 34,856. Commenters stated 

that EPA relied on a 2009 report by the engineering firm Sargent & Lundy for both the projected 

efficiency improvements and costs. Commenters stated that however, Sargent & Lundy clearly 

acknowledges that this report was based upon a literature survey, original manufacturer data, and 

an in-house database to be used for conceptual purposes. Commenters stated that further, the 

report clearly shows that all the possible heat rate improvement options cannot be uniformly 

applied to all the existing coal EGUs. Commenters stated that they believe EPA has taken the 

Sargent & Lundy report out of context and, therefore, miscalculated the feasibility and the cost to 

Virginia's existing EGUs to undertake new measures to increase their heat efficiency. 

Commenters asked what sensitivity analysis did the EPA run on the inputs referenced on p. 2-39 

of the GHG TSD. 

Commenters stated that they continuously work to maintain and reduce their units' heat rate, 

including through the performance of routine maintenance and replacements of existing 

equipment. Commenters stated that the following types of projects have resulted in heat rate 

improvements at their coal-fired facilities since 2005: condenser replacement, condenser 

cleaning systems, turbine replacements, cooling tower replacement, and ID fan replacement. 
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Commenters stated that since 2005, they have expent over $100 million on projects that have 

helped maintain and improve heat rates at its coal-fired facilities. 

Commenters stated that within regulated utilities any fuel cost savings which might be created 

through efficiency improvements would have to be returned to the power consumer, otherwise 

known as the rate base. Commenters stated that this makes any efficiency improvement project 

have an automatic negative return on investment, and such projects never see the light of day. 

Commenters wanted the EPA encourage the states to allow some or all the financial benefits 

from efficiency improvements and CO2 reductions to remain with the utilities so that a positive 

ROI is possible and could then be used as a justification for the necessary capital projects which 

will have to be undertaken. 

3.1.6 Miscellaneous Issues about Heat Rate Improvement at Existing Coal-fired EGUs

This subsection discusses general issues about heat rate improvement at existing coal-fired EGUs 

not otherwise covered in the more specific subsections for Section 3.1 discussed below this 

subsection. 

Commenters have raised a number of issues related to this subsection which are organized by 

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

Comment 1: Alternative approaches – BSER, Unit Specific Measures, and Bundling of BB1 

components

Response 1: We appreciate commenters’ suggestions of these alternative approaches. For the 

reasons stated in sections V.A and V.C of the final rule preamble of the CPP and the GHG 

Mitigation Measures TSD, we believe that the building block 1 component of the BSER is best 

focused on heat rate improvements. However, states may allow sources to use many of the 

techniques described by commenters as compliance options. For further responses to comments 

regarding co-firing, see section 3.2.7.

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

Commenters described, as currently configured by EPA, building block 1 is solely focused on 

Heat Rate Improvements ("HRI"). Commenters stated that however, HRI is just one element of a 

larger group of measures they refer to as Unit Specific Measures ("USM") - those control options 

that can be applied directly to an affected source to reduce CO2 emissions, including (in addition 

to HRI), retrofit carbon capture and sequestration ("CCS"), natural gas co-firing in coal units, 

and affected unit retirements. Commenters stated that reconceiving building block 1 as a bundle 

of potentially available Unit Specific Measures, and determining the potential CO2 reductions 

available state by state not only achieves the maximum practicable reductions directly from 

affected sources, but also even satisfies EPA's stated interest that the building blocks be "broadly 

applicable" to existing fossil-fueled power plants. Commenters stated that for example, even if 
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one particular option cannot be applied to a specific unit or group of units within a state, the 

target rate would be supported by other options within the basket. Commenters also stated that 

for example, a Massachusetts-based plant might not have access to enhanced oil recovery 

("EOR") sequestration and so CCS might not be a reasonable option for use in deriving the USM 

building block 1 portion of Massachusetts' target rate. Commenters stated that co-firing with 

natural gas is potentially available to existing designated facilities in Massachusetts. Commenters 

stated that while EPA's proposed approach to the BSER nowhere precludes states from doing 

this analysis as they plan their compliance, the state-specific targets can be strengthened if they 

are based on a BSER that more accurately reflects the suite of compliance options available to 

reduce CO2 directly from existing affected sources. Commenters stated that this "bundling" 

approach to building block 1 moreover is consistent with the approach EPA is already taking in 

building block 3 (renewables). Commenters stated that it is consistent with EPA's longstanding 

regulations - as EPA appreciated in 1975, section 111(d) performance standards or "guidelines" 

necessarily reflect differences in controls based on location. Commenters stated that EPA in the 

CPP proposal described building block 3 renewables as including a portfolio of particular 

technologies showing clear dominance in specific regions.

Commenters further stated that by bundling these options together as "renewables" and not as 

separate building blocks for geothermal, off-shore wind, on-shore wind, landfill gas combustors, 

etc., EPA avoids having to decide whether a single technology option is "broadly available" (as 

the Agency puts it) for application at all affected units. Commenters stated that regardless 

whether "broad availability" is in fact a relevant factor in EPA's determination as to what 

constitutes the BSER for existing sources (and they assert it is not), it is inconsistent with the 

position EPA has taken on renewables. Commenters stated that EPA's building block 3 category 

"renewables" contains a number of technologies that the Agency includes in the BSER 

determination are not everywhere available. Commenters stated that at a minimum, building 

block 1 should include the following components:

• Heat Rate Improvements at Affected Units;

• Natural Gas Co-firing in Affected Coal Units;

• Retirements of Affected Sources, after 2012 and as of the Date of State Plan 

Submittal; and

• Carbon Capture and Sequestration Retrofits.

Commenters concluded that careful weighing of the statutory criteria and other considerations 

EPA raised in the CPP proposal and NODA should lead EPA to the conclusion that gas co-firing 

should be included in the BSER analysis and state goal calculation formula as a unit specific 

measure under building block 1. Commenters stated that excluding this option on the sole basis 

that its cost per ton of CO2 avoided is higher than for heat rate improvements is an 

impermissibly narrow basis for decision - and indeed cuts against the argument that a variety of 

measures (with varying costs) are available to states for use in compliance. Commenters stated 

that in sum, EPA has ample basis to include increased natural gas co-firing and conversion 

measures to achieve CO2 emissions reductions in its state target setting exercise. Commenters 

stated that inclusion of gas co-firing in building block 1 would direct greater reductions than unit 
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heat rate improvements alone, and at reasonable cost. Commenters stated that the inclusion of 

gas co-firing will have important non-air health and environmental benefits and reduce 

dangerous co-pollutant emissions.

Commenters stated that in ACSF's suggested building block approach, EPA should start with 

building blocks 1 and 2, which include inside the fence heat rate improvements and NGCC 

dispatch changes. Commenters stated that Building blocks 1 and 2 can result in 22% emission 

reductions by 2020, at lower overall program costs than the currently proposed four building 

block approach. Commenters stated that these initial two building blocks are also practical, 

common sense solutions that are legally defensible.

Comment 2: Alternative approaches - Develop a work practice standard for heat rate 

improvements at designated facilities

Response 2: We appreciate these suggestions for a work practice-based approach to determining 

heat rate improvement. See section V.B of the final rule preamble of the CPP for the EPA’s 

explanation of why we do not believe CAA section 111(h) is applicable here. Furthermore, both 

CO2 rate and heat rate can be measured at affected EGUs.

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

Commenters stated that there is a wide range of inherent limitations on the potential for heat rate 

improvements, including original design, geographic location, availability of space, emission 

controls, and prior improvement efforts; that unit efficiency naturally degrades over time; that 

there is no accurate method to measure heat rate in real time; that heat rate improvements may be 

masked by control technology installations or changes in duty cycle; and that remaining useful 

life will affect the economic feasibility of continued efficiency investments. Commenters stated 

that therefore there is no single emission standard or limitation that is achievable by or 

adequately demonstrated for the fossil fleet, however that there is a long history of successful 

advancement and adaptation of new technologies, operating procedures, materials, and 

equipment upgrades that have allowed the existing fleet to maintain and improve efficiency 

through adoption of best practices. Commenters stated that Section 111(h)(1) of the CAA 

authorizes the Administrator to identify design, equipment, work practice, or operational 

standards, or a combination thereof when it is not feasible to establish a standard of performance. 

Commenters stated that the phrase "not feasible to prescribe or enforce a standard of 

performance" means, for purposes of section 111(h)(1), that the "application of measurement 

methodology to a particular class of sources is not practical due to technological or economic 

limitations." Commenters stated that as applied to heat rate improvement opportunities, the 

Administrator could collect information on actual unit experiences associated with 

implementation of the suite of measures described in the S&L report and elsewhere, and develop 

a standard assessment for heat rate improvements that could be evaluated during regular planned 

outage cycles and that unit operators could submit a report and recommendation to the state that 

describes the measures evaluated, the lead time necessary to implement the project(s), and the 

relative cost-effectiveness of the recommended measures, based on the unit's remaining useful 

life. Commenters stated that a reasonable cost effectiveness threshold could be established, 
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above which measures would not be required and that reports could be submitted to the state 

agency regarding implementation. Commenters stated that then available and cost-effective 

opportunities could be identified and implemented throughout the remainder of the existing units' 

operating lives and actions taken to implement the CPP under such a work practice standard 

could be classified as "routine maintenance, repair and replacement," and thereby not expose unit 

operators to the risk of NSR enforcement. Commenters stated that such a standard would allow 

the greatest possible incorporation of efficiency improvements without disruption to the 

operation of the existing fleet, protecting electricity reliability and encouraging the development 

of new technologies. Commenters respectfully requested that the Administrator considers the 

benefits of such an approach in finalizing the CPP proposal.

Comment 3: Alternative approaches - Minimum efficiency requirement or old unit replacements 

Response 3: We appreciate these suggestions. The Agency has received numerous comments 

asserting that decisions regarding equipment and/or operational changes or retirement are 

typically made on a site-specific basis. The final rule provides flexibility to states in developing 

emission standards, and to affected EGUs in complying with those emission standards—thereby 

allowing for individualized circumstances to be taken into account. The alternatives suggested by 

these commenters would undermine that flexibility, and thus we are not adopting them.

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

Commenters recommended that there be a minimum efficiency requirement or a schedule for 

replacing older units for each Electrical Generating Unit (EGU) in addition to the portfolio of 

programs developed and submitted by states. Commenters stated that this would ensure 

greenhouse gas emission reductions as well as criteria pollutant co-benefits from this sector. 

Comment 4: General comments in favor of BB1

Response 4: The EPA thanks the commenters for their support. The EPA’s response to 

comments regarding co-firing are in section 3.2.7. Furthermore, the EPA has purposefully 

provided states the flexibility to develop plans with emission standards that more precisely take 

into account the potential heat rate improvement of individual EGUs—should states desire to 

consider potential heat rate improvement at all.

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

Commenters stated that EPA's analysis demonstrates that the existing fleet of power plants is 

capable of reducing emissions considerably through onsite efficiency improvements resulting 

from cost-effective equipment upgrades and increased deployment of best operating practices. 

Commenters stated that EPA's analysis and other industry and academic studies also find 

significant variation in the heat rate of comparable existing steam EGUs, strongly indicating that 

many existing steam EGUs have not yet implemented all cost-effective heat rate improvement 

measures. Commenters listed the following reasons why even cost-effective coal plant efficiency 
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improvements have not been implemented. Commenters stated that these include the fact that, in 

some rate-regulated markets, power plants are allowed to pass fuel costs on to consumers, 

reducing the financial incentive for onsite efficiency improvements. Commenters stated that in 

addition, coal plants in competitive markets seldom set the clearing price for electricity, and so 

may not face competitive pressure to look internally for all cost saving measures. Commenters 

stated that at some plants, there are institutional barriers to making such changes, or a lack of 

onsite engineering personnel focused on increasing efficiency. Commenters stated that finally, 

many plants are old, with more than 30 percent of plants over 50 years of age. Commenters 

stated that the operators of a number of these plants, and younger plants as well, may have 

deferred significant upgrades until the future regulatory environment for a range of air pollutants, 

including mercury and carbon dioxide, became clearer. Commenters stated that EPA's Building 

Block 1 analysis represents a highly conservative evaluation of the potential opportunities for 

coal plant efficiency improvements. Commenters stated that moreover, EPA's Building Block 1 

analysis does not include any of the substantial opportunities to reduce emissions by co-firing 

with natural gas. Commenters stated that in the final rule, EPA should strengthen Building Block 

1 to reflect the full range of opportunities for onsite emission reductions at steam EGUs, 

including use of lower-carbon fuels. 

Commenters stated that they support this Building Block 1 and find that Building Block 1 is the 

only such building block that focuses on the reduction of CO2 emissions from EGUs. 

Commenters stated that EPA must do more to promote use of this building block if the real intent 

of the Proposed Rule is to help reduce these emissions and as such, the Commenters 

recommended that EPA work closely with states in order to get them to place a greater emphasis 

on Building Block 1 in their state implementation plans for reducing the CO2 emissions of 

existing EGUs within their borders. Commenters stated that this should help spur a technology 

innovation among the EGUs to meet their emission reduction requirements in accordance with 

Building Block 1, and in turn, help reduce the co-pollutants of such EGUs (e.g., sulfur dioxide 

(SO2), nitrogen oxides, and toxic air pollutants).

Comment 5: Only Building Block 1 should be included in the BSER determination

Response 5: EPA disagrees with these comments for the reasons discussed in section 1.10 

regarding the determination of the BSER. 

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

Commenters stated that EPA solicited comments on different combinations of building blocks 

and different levels of stringency for each block. Commenters stated that of the four proposed 

building blocks, the commenters believe that only Building Block 1, which relates to heat rate 

improvements of existing coal-fired EGUs, should be included in the BSER determination. 

Commenters stated that this is the only component of BSER which directly reduces emissions 

from existing Section 111 (b)-affected sources without attempting to redefine the source.

Comment 6: Miscellaneous criticism of BB1
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Response 6: As described in section II.K of the final rule preamble, the EPA engaged in 

extensive and vigorous outreach to stakeholders at every stage of development of this rule, 

including to industry and electric utility representatives. Additionally, far from micromanaging 

plant operations, neither the BSER as a whole nor its building block 1 component require any 

affected EGUs to take specific measures to improve heat rate—or require any heat rate 

improvements at all. Rather, states have significant flexibility to develop plans with emission 

standards that more precisely take into the individual circumstances of specific EGUs, and the 

EGUs themselves has flexibility in how to comply with those emission standards. 

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

Commenters urged EPA to consider whether it should re-conceive Block 1 from the bottom up, 

with an emphasis on engaging the utility industry to articulate a practical technical objective, and 

to arrive at more complete understanding of how that objective can be achieved without undue 

detriment to ratepayers. Commenters stated that specifically, EPA may wish to consider whether 

it is desirable to micromanage plant operations by insisting on immediate implementation of the 

technologies assessed by Sargent & Lundy that have already been scheduled reasonably and with 

care. Commenters stated that accelerated schedules will increase costs to be passed on to 

ratepayers, and will likely strain the capacity of the utility industry for no compelling purpose, 

particularly if EPA anticipates continued displacement of coal fired generation by action of the 

other three Blocks. Commenters stated that with so many moving parts in play, EPA should 

create a mechanism to reconsider the practical value of the portion of the overall target related to 

Block 1, once experience provides more insight into whether it can or will remain desirable as 

currently conceived. Commenters also expressed there is an ambiguity in whether EPA would 

eventually intend independently measurable reductions in coal fired EGU dispatch based on 

reductions to Block 1 generation. Commenters stated that they do not believe this would be 

desirable, or consistent with the proposed rule as it has been articulated to date.

Comment 7: Alternative approach – algae-based capture of CO2 emissions

Response 7: We appreciate the commenters’ suggestion. For the reasons stated in sections V.A 

and V.C of the final rule preamble of the CPP and the GHG Mitigation Measures TSD, we 

believe that the building block 1 component of the BSER is best focused on heat rate 

improvements. However, states may allow affected EGUs to use other emission reduction 

techniques as means of complying with emission standards.

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

Commenters stated that EPA's proposal suggests that the primary method for reducing emissions 

"inside the fence" (i.e. at the site) of the EGU under Building Block 1 would be heat rate 

improvements at coal-fired power plants but unfortunately, this option is largely unavailable to 

Arizona if significant portions of its coal fleet are retired. Commenters stated that believe there 

may be other ways to reduce emissions inside the fence that should be considered under Building 

Block 1, more specifically, they believe that algae-based fuel production and other CO2 

recycling approaches holds great promise for capturing carbon emissions at fossil-fuel power 
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plants, thereby reducing the overall emissions rate. Commenters stated that since these 

reductions have the potential to occur on the same site as an EGU, they might logically be 

considered as part of Building Block 1 under EPA's proposed framework as an "inside the fence" 

measure. Commenters stated that while the EPA has suggested that states could implement 

additional emissions reduction measures beyond those explicitly outlined in the proposal, they 

urge ADEQ to request EPA's clarification on this position and whether such measures might be 

considered under Building Block 1, or approved at all under a State Implementation Plan.

Commenters believed that Arizona is a prime location for using sunlight in CO2 recycling 

technologies creating an industry that can flourish and could benefit greatly from using it as an 

option for meeting compliance. Commenters stated for example, they are home to the Arizona 

Center for Algae Technology and Innovation (AzCATI), which serves as a national test bed for 

research, testing, and commercialization of algae-based products such as biofuels, 

pharmaceuticals, nutraceuticals, waste water treatment, and other algae co-products. 

Commenters stated that from the time of its inception in 2010 with a grant from Science 

Foundation Arizona, AzCATI has grown a research funding portfolio of more than $22 million. 

Commenters stated that AzCATI currently leads several sponsored projects, including Salt River 

Project's microalgae carbon capture at Navajo Generating Station. Commenters stated that 

believe algae based capture of CO2 emissions could be expanded to other EGUs in the state and 

across the country and additionally, ASU's experience at AzCATI has produced a wealth of data 

and practices that will enable precise measurement of carbon emissions captured at a facility.

Commenters believed, as a general principle, the EPA could be more explicit about the role that 

future technologies might play in achieving emissions reductions and by explicitly allowing 

algae-based and other carbon capture and utilization technologies as a means for achieving Block 

1 emissions reductions, EPA will be embracing the necessary role of emerging technologies in 

achieving meaningful climate change mitigation and carbon management. Commenters stated 

that this could also be achieved by giving states special consideration in approving their State 

Implementation Plans if they sufficiently support clean power R&D activities.

Comment 8: National average heat rate improvement goal is unfair to states with primarily gasfired EGUs

Response 8: The EPA disagrees. At proposal, the heat rate improvement was assumed to be 

uniform across all states. That did not unfairly penalize states with a large gas generation 

portfolio because the state goal was a product of expected coal generation and heat rate 

improvement at those coal-fired facilities, so the less that coal generation factored into a state's 

generation mix (i.e., gas-intensive states), the smaller the impact that heat rate improvement had 

on that state’s goal. In this final rule, the EPA takes a regionalized approach in defining heat rate 

improvement expectations, and a uniform technology-specific rate approach for quantifying 

BSER. Both of these changes also work to obviate the commenters' concern.

The following are summaries of the specific public comments under this comment:
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Some commenters asserted that the EPA’s proposed national average heat rate improvement 

goal, derived from an analysis of only coal-fired EGUs for building block 1, is unfair for states 

that have primarily gas-fired EGUs and therefore already have a significantly lower CO2 

emission rate than states with primarily coal-fired EGUs.

Comment 9: Commenters stated that while building block 1 addresses measures at the affected 

facility, it still includes measures outside the boundaries of an affected facility. Commenters said 

building block 1 is legally impermissible as a basis for BSER determination and is thus legally 

flawed because it is not technically feasible nor adequately demonstrated.

Response 9: For the EPA’s response to this comment, see section 1.9.4

Comment 10: Comments suggesting an alternative to the CPP in which states determine massbased emission limits based on unit-specific heat rate information, and existing units are phased 

out in 2030 or 2050

Response 10: The agency has concluded that the BSER includes implementing heat rate 

improvements, switching generation from higher-emitting affected sources to lower-emitting 

affected sources, and avoiding generation at affected sources by increasing renewable electricity 

generation. The commenters’ suggestion does not include the latter two emission reduction 

methods.

The commenter implicitly suggests that the BSER includes retirement of pre-1978 affected 

EGUs by 2030, and retirement of post-1978 affected EGUs by 2050, unless they meet new 

source standards. The commenter does not explain the legal authority for this suggestion.

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

Commenters stated that Congress expects states to consider factors such as remaining useful life 

and stranded investments in determining the standard of performance to apply to each generating 

unit. Commenters said, the following alternative to the Clean Power Plan does just that:

Commenters stated that states would determine unit-by-unit CO2 emission limits based upon 

heat rate improvements that are achievable for each unit, taking into account investments in 

efficiency improvements that have already been made. Commenters said, based on all unitspecific information, states would determine the mass-based emission limit applicable to the 

existing units. Commenters said, CO2 emissions would be measured on a gross basis, which is 

consistent with all previous EPA rules.

Commenters stated that on a unit-by-unit basis, states would use the highest of three years (2010, 

2011 or 2012) to determine a CO2 emissions baseline. Commenters said, this acknowledges that 

utilities were performing significant scheduled outages during this time-frame to install 

equipment for compliance with other EPA regulations and is consistent with prior EPA 

rulemakings. Commenters said, natural gas prices were also at historical lows in 2012 which 
525

distorts normal coal generation capacity factors and, therefore, makes the use of 2012 as the sole 

baseline-year inappropriate.

Commenters stated that units which came on line prior to 1978 would be phased out in 2030 

unless they can meet a valid new source performance standard by that time.

Commenters stated that units brought on line in 1978 or thereafter would be allowed to operate 

to 2050 unless they can meet a valid new source performance standard prior to or by that time. 

Commenters said, a 2050 timeframe recognizes a remaining useful life of 337 years for these 

existing coal units. Commenters said, the timeframe is also consistent with the Department of 

Energy's timeline that a second generation of carbon capture technology might be developed by 

2025 and more advanced and cost effective technologies could be developed beyond 2035.

Commenters stated that while the alternative should provide sufficient time for an orderly and 

cost-effective transition to a less carbon intensive energy portfolio, FERC, NERC, regional 

transmission organizations and independent system operators would retain their authority to 

determine which facilities are needed for grid reliability and to declare facilities that cannot close 

for that reason, if necessary.

Commenters stated, based on a review of the nation's existing coal units and using a conservative 

assumption that pre-1978 coal units would be replaced with NGCC units, CO2 emissions under 

the alternative are essentially equivalent to the CPP in 2030.

Commenters stated, at a minimum, EPA should recognize this alternative as a sub-categorization 

for small fossil electric power generation utilities as defined by the Small Business 

Administration. Commenters also proposed that the CPP or any alternative have language which 

allows NERC to declare an energy emergency and utilize units as needed to insure reliability.

Comment 11: Commenters recommended that if the EPA's BSER definition is not limited to the 

conventional narrower meaning, then the states should have the power to define BSER, make 

changes to the definition, and apply BSER so that broader cost and reliability issues can be 

incorporated, as long as EPA's emission reduction targets will be met. If building Blocks 3 and 4 

remain part of BSER as defined by EPA, commenters recommended that any changes to the 

allocation of RE across state lines for compliance purposes should be accompanied by a 

corresponding change in the emission baseline and goal. Commenters also recommended, that 

states with an established RPS be allowed to use the RPS to define Block 3, rather than regional 

averages, to help simplify compliance. 

Response 11: The EPA disagrees. We believe that the approach taken to the BSER in the 111(d) 

final rule is appropriate, and is different from the BSER at proposal, which is what this comment 

addresses. Moreover, we believe that the flexibility provided to the states in the final rule makes 

the commenter’s concerns about the BSER unnecessary. In addition, the EPA has decided not to 

proceed with Building Block 4. See section V of the final CPP.
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Comment 12: 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. [17 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 12: The EPA has changed the definition of the BSER since proposal. It is now based 

on regional performance, and the EPA believes that it is not necessary to designate inside the 

fence natural gas measures.