1 TABLE OF CONTENTS

CHAPTER 3 GHG MITIGATION MEA SURES

................................ ................................ ...... 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 ra te 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

.. 5172 CHAPTER 3 GHG MITIGATION MEA SURES

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

" building blocks. " These proposed building blocks include d : 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 switc hing ( 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 c omments 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

• Chapte r 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

• Chapte r 10 : Rule Language Corrections

3.1 HEAT RATE IMPROV EMENT AT EXISTING CO AL

- 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 opera ting 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 improvemen ts.3 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 EG Us afforded by the rule.

3.1.1 Factors that Impact Heat Rate of C oal

- F ired EGU s

This sub section discusses a variety of factors that commenters believed should be considered when comparing the effectiveness of heat rate improvement technologies to increas e 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 c omment:

Commenters stated that power plants are designed for an optimal heat rate. Commenters stated that while that h eat 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 t he average age of operating coal

- fired power plants is 40 years. Commenters stated that o ver 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 un its 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 coal

fired fleet was explored to understand the impact on baseline CO2 emissions.4 Commenters stated that the units with the lowest CO2 em issions are the large supercritical units, which have the fewest opportunities to lower the plant heat rate. Commenter s 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 th at 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 d ocumented evidence that heat rate, and therefore GHG emissions, can increase by more than ten percent when the ir units are operated below their designed full load capacity. Commenter s 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 t hat 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 genera tion. 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 emiss ion 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 wi th 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. Commenter s stated that this ap proach 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:5 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. Com menters 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 find ings 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 plant s, 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 op eration or upgrade equipment.

Commenters urged EPA to require that generating units upgrade to the best available technologies for efficient operation. Commenter s stated that this usually means upgrades to the plants controls and electro

- mechanical au xiliary systems, as well as to the basic steam

- water cycle equipm ent 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. Commenter s 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 o ther 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 capabl e 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 t o reduce the heat input to offset the capacity reduction of 5 MW. Commenter s 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 reduced6 heat ra tes (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 wi th 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 generation

weighted average efficiency of 32.5% while the top ten percent of the fleet had an efficiency of 37.6%, five percen tage 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 flee t

- 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. Comment ers 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 tha t 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 i mprovements would not achieve their intended emission reduction effects if the EGUs were operated inefficiently to address grid reliability and integration needs. Commenter s stated that a specific BSER requirement to evaluate and address integration and re liability 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 alon e 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 a nd 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 S tates fails to develop incentives and opportunities t o 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 f orego 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 :7 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 coal

fired power plants in the region have performed such upgrades in recent years. Commenters stated that f or 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 redu cing 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 emis sions control equipment

.

Comment 3: Comments regarding efficiency gains from changes in dispatch o rder 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 imple ment 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 encourage d EPA to evaluate the opportunities for such reductions in the final rule

.

Comment 4 : Comments regarding coal rank and quality

R esponse 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 fuels8 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 i t is important to emphasize that fuel choice is dictated by numerous variables (e.g., price, availability, boiler des ign 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 t he 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

- to

combustion 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 ef ficiency gains from cleanin g 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 t o 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 po wer generation unit, among othe r factors.

Commenters stated that EPA's Block 1 a pproach f ails to c onsider the e fficiency r eductions

r esulting from s witching to l ow

- s ulfur c oals. Commenters stated that the efficiency of a coal

fired 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 the ir members. Commenter s 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 coal

fueled 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." Comme nters 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, switchi ng 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) emissions9 compared to the eastern coals. Commenters stated that in addition to these envi ronmental 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 pric e 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 ha ve gained experience in the utilization of PRB, they have been able to mitigate these constraints to the point where al l 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 ha ve developed processes to dynamically blend i ts 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 typica lly, 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 pro perties 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, l ower 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, whic h 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 f or 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 cos t 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 will10 need to be performed to determ ine 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 im pacts on the efficiency of many existing coal

- fueled EGUs in devel oping 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 pe riods. Commenters stated that however, because of physical constraints, or to mitigate operational concerns, higher PRB blends generally result in limiting the maximum generat ion of a unit. Commenter s 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. Commenter s stated that this impact is n ot 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. Commen ters 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
stat ed 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 R iver Power Plant) were designed to burn higher sulfur eastern coals and as environmental constraints tightened, switchi ng to lower sulfur western coal blends became an economical means of controlling SO2. Commenters stated that these western Powder River B asin (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 non

peak power demand periods. Comment ers 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 mitiga te 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.11 Commenters stated that typically, lower MISO market pricing results in higher PRB b lends 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 lo ading 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. Comm enters 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 hig her 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 coal

fired 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). Commenter s stated that this was done primarily as an effort to reduce SO2 emissions associated with higher

- sulfur bituminous coal. Commenter s 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 inc lude blending eastern coal at high er 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 technologies12 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 c omment :

Commenters stated that air pollution control equ ipment 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 an d, 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 req uirements, 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 commen ter, 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 pla nt 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 increa se 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 lea d 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.13 Commenters stated that a factor in the decli ne 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 Pro posed 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 fo r 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 emiss ion 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 improvem ent 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 environment al 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 consumpt ion 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 envi ronmental 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 heat14 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 F GD

- 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 w hich 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 reductio n. 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 redu ction (SCR) actually reduce plant efficiency by creating additional parasitic load. Commenter s stated Utah's affected EGUs already have environmental contr ols 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 regul ations 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 environme ntal 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. Commenter s stated that the retrofit of SCR increases auxiliary p ower by about 1.5 percent of gross output, while flue gas desulfurization ("FGD") retrofit may increase auxiliary power by 1

- 2 per cent, depending on coal type and that since 2002, about 140,000 MW of SCR and 120,000 MW of FGD have been installed on EG Us. Commenter s 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. Commenter s stated that historically each set of emissions control regulation increases auxiliary power consumption by about 1% of gross generation ( EPRI report 1024651 "P rogram 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 a ll EP RI and other referenced estimates of heat rate improvements are reported on a net basis. Commenters stated that net heat rate reflects the cost of generating15 electricity including the co st of auxiliary power consumed as part of the process and thus net h eat 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 poten tial 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. Commenter s 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. Comment ers 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 an d the sustainability of net heat rate improvements and EPA has also arbitrarily used 2012 as a baseline for net heat rates from coal

fired EGUs. Commenters stated any changes to affected units after 2012 to comply with other EPA regulations will hinder a u nit'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. Co mmenters 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 coa l

- 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

- control led 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 switchin g 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 rate16 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 su ch 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 impro vement.

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 impairmen t 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 state d 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 completio n. 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 o f the AQCS required by other EPA rules.

Comment 6 : Comment regarding a dditional 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 c omment :

Commenters made reference to a May 2014 report for the Secretary of Energy by the National Coal Council that cited an increas e 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 to17 higher heat rates (operation at reduced load, va riable 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 us ed 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 c omment:

Comm enters 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 as sumes comes fro m 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. Commen ter s 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 reduce d 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 pr eliminary review of the det ailed operating records for individual coal

- fired EGUs maintained in EPA's Air Markets Program Database ("AMPD"). Commenter s stated that AMPD data revealed a number of occasions where there was a significant and sudden u nexplained 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 obser ved 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 d etermining 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 im plemented 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

- on

investment for various performance recovery and improvement options. C ommenters 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 perform ance. 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 effi cient 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

- effe ctive 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

- r elated 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 an d fuel characteristics. Commenter s stated that operating a unit at full load at stea dy 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). Commenter s 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 techno logy and participate in the elaborate electrical grid system, they nonetheless are poor operator s who are incapable of competently managing their facilities and choose to ignore opportunities for increased efficiency and reduced costs. Commenter s stated that this false and paradoxical assumption defies logic and ignores the economic incentives for ef ficient operation. Commenter s 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 existin g control systems; or earlier replacement of worn components. 79 Fed. Reg. at 34860. Commenter s 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 measur es 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 ve ry different heat rate from one operating in the Southwest due to the differences in elevation and climate, even if operation and maintenance are simi lar, and further, a lack of available water can reduce heat rate in that dry cooling is less efficient than wet cooling. Commenter s 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 Mitigatio n Measures TSD supporting the final CPP.

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

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. Commenter s stated that th ese conditions includ e low natural gas prices, increasing renewables penetration, and limits on total carbon emitted from EGUs (for example, RGGI, AB32, and 111d). Commenter s stated that accounting for part

- load operations and cycling will lower estimates for technical, e conomic, 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 develope d 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.

Commente rs 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 equ ip ment, 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 lon ge r periods. 3) When starting up a large generating20 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) Increas in g operational cycling increases exposure to high thermal stresses and so results in increased maintenance and repair requirements with attendant tendencies toward sub

optimal performance.

Commenters stated that load

- following units experience much hi gher 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). Commenter s stated that cycling of coal power plants reduces the efficiency of coal power plants, thereby increa sing 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 hig h 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 pla nt 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 pow er 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 maint enance 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 incr ease 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 o r 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

.
Comm enters stated EPA acknowledges the possible need for a separate standard for load

following 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 generator s, 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 t o 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 1 0 : 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 1 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 CP P. As stated therein, w e 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 practi ces 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, coal

fired power plants will shift from providing baseload generation and operate more in cycling and/or in creased 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 t op 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 rene wable power and greater use of natural gas combined

- cycle (NGCC) unit s 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 th an "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 pla nt 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 i nstance, 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 is22 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 dow n, 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 Figur e 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 th e 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 Repor t 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 lower

capacity 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 promotin g 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. Comme nters 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 historical ly elevated capacity factors while accommodating renewables will cause increased cycling, part

- load operation, and more startups on the part of the existing coal

fired power plant fleet. Commenters stated that cycling coal units will negatively impact the23 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 in dustry, and particularly in the future under the Clean Power Plan, further complicate the ability to achieve and maintain heat rate improvements at affected EGUs. Commenter s stated that one of the primary reasons for this difficulty under th e Clean Power P lan 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 fol lowing unit to resp ond 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 arbitra ry and capricious

r ulemaking 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 coal

fired EGUs operate less efficiently (i.e., in creased heat rate) at lower capacity factors. Commenter s 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 b e operating at lower capacity factors an d 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 tem perature swings that occur during cold starts. Commenters stated w hen 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, resulti ng in increased maintenance and repair. Commenter s stated that load

- fo llowing 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 explaine d, 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 redi spatch applied by EPA to Arizona's goals under Building Block 2. Commenters state d 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 furthe r degrade heat rate performance of remaining coal units24 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 disp atched 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, th e 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 1 1 : Comments regarding load changes due to a combination of multiple building blocks , including comments on the unit specific impacts of low lo ad factor on net heat rate

. Response 1 1 : 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 c omment :

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, particularl y in the spring. Commenters stated that this result occurs during days with relatively low load, gas

- fired generation is often c urtailed as much as can feasibly be done (while still ensuring adequate ancillary services and reserves on the grid), necessitat ing ramping of the coal fleet in order to maintain system reliability. Commenter s stated that this ramping naturally result s in coal plants running in a less than optimally efficient manner, and consequently a higher heat rate, and that EPA's method of cal culating 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 u nits which is counter to the intent to reduce emissions. Commenters stated that, in fact, by running an existing coal

- fired25 plant at less than a 60 percent load, the heat rate of the plant increases exponentially. Commenters referred to both the NERC Initi al 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 minim um 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 secti on 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, a lthough 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 cha nges 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

- f ollowing 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 b y 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.

Commenter s 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 acceler ated 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 an d 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 Comme nters 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 con trols. 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 mor e 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 shutdow n

. 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 state d 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 availabi lity 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 efficienc y 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 equip ment. Commenter s 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 ne gative 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 complet ely elimi nate 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 mate rially 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 improve ments will no longer be effective and thus the carbon reductions will not be achieved

- in fact carbon will increase. Commenter s 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 coal

based units resulting from Building Bloc ks 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 enc ourage lower utilization of coal

- fired E GUs. 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 incr eases 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 electrici ty 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 do wn 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 rel egated 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 u pgrades. 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 a nd 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 re ducing 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 freque ntly), 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, operatin g at minimum load if care is not taken to av oid 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 ener gy supply, partially as a result of cycl ing coal plants. Commenter s 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 em issions reductions

- and could cause i ncreases 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.

C ommenters 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 dir ect, neg ative 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. Commenter s stated that a specific BSER requirement to evaluate and address integration and reliability iss ues without opera ting 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 c hanging its generation output (cycling the unit) to allow for renewable energy to enter the electric grid. Commenter s stated that Gibbons Creek runs most efficiently when it is "base

- loaded"

- running at full capacity with no cycling. Commenters stated tha t i f the unit has to be cycled down (e.g., to give preference to renewable energy sources, such as wind power) it runs less efficiently. Commenter s stated that this is clearly demonstrated for Gibbons Creek with t he 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 h as 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 un its (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 i mpacted 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 t hey 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 effi cient 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

an d 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 gener ation 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 o ptimum level is close to the rated output

Comment 1 2 : Comments regarding c oal utilization.

Response 1 2 : 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 suppor ting the final CPP

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

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 ar e 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 generatio n 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 thu s must be undertaken in co njunction 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 compa red to full utilization.

Comme nters 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&M30 improvements can lower variability an d 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 like ly have a significant impact on this important factor.

3.1.2 Technologies to improve existing coal

- fired EGU heat rate

This sub section 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. Wi th 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 acknowledg e 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 d egradation, 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 follo wing are summaries of the specific public comments under this comment:

Commenter s 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, conde nser 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 the ir 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 the ir system there are units in various stages of repair at any given time. After maintenance outages, the hea t rate improvement, however, begins to degrade as soon as the unit begins to operate. Presently, the losses are 24 BTUs/kWh.

Commenter s stated that many projects implemented to improve heat rate depend on clean, close tolerance machine parts that are s ubject to wear and corrosion. Commenter s stated that this equipment must be periodically taken out of service for maintenance to remove corrosion products and restore tolerances. Commenter s stated that EPA did not provide an efficiency range, for any heat rate improvement, to consider normal wear.

Commenter s 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 t hat h owever, 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 state d that they implemented many heat rate improvement projects while installing emission controls as part of the agreement with EPA

. Commenters stated that t hese 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 the m with appropriate credit and other utilities that have made similar accomplishments.

Commenter s stated that they already undertake significant efforts to operate efficie ntly and the goal of their business model is to provide reliable electric service to their member

- owners at the lowest reasonable cost. Commenter s stated that in addition to the extensive capital investment recently made to ensure compliance with forthcomi ng air regulations, they also expend considerable effort and resources to maintain peak boiler efficiency at all times. Commenter s stated that specific maintenance activities are scheduled on annual, three

- year, and nine

- year timelines and annual maintenan ce 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 equipme nt, burners, coal prep equipment, and electrical and instrumentation equipment. Commenter s 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. Commenter s stated32 that moreover, the plant staff continuously monitors and cont rols 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:

Commenter s 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. T he 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:

Commenter s 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. Commenter s 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.

Commenter s stated that advanced he at rate improvement strategies leverage technological improvements from new units. Commenter s stated that new steam turbine units use advanced 3D airfoil and blade technology, enh anced sealing technology to reduce leakages, and improved moisture removal fr om low pressure turbines. Commenter s stated that experience with new units indicates that these advanced technologies could offer up to an additional 2.0% gross heat rate impr ovement, where feasible in existing units.

Commenter s stated that several opt ions 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 rate33 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:

Commenter s list ed limitatio ns 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.

Commente r s presented information with regard to STATION A

- Material Handling. Commenter s 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 syste ms and have not been converted to dry handling. Commenter s 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 operat e the ash handling systems. Commenter s 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 w ith the transport of water. Commenter s 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. Commenter s stated that fly ash handling conversion would reduc e 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 evaluat ing the feasibility of this improvement from a technical and economic standpoint. Commenter s 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. Commenter s noted that additionally, CO2 emissions due to truck hauling the ash are not considered in this report. Commenter s stated that Unit A1 is currently in the process of converting a secon d 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. Commenter s 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 r ate improvement is possible. Commenter s 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. Commenter s 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.

Commenter s presented information with regard to STATION B

- BOILER ISLAND, MATERIAL HANDLING. Comm enter s 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 system s by eliminating equipment and auxiliary power loads associated with the transport of water. Commenter s stated that the bottom ash systems on Units B1 and B2 are wet sluicing systems and have not been converted to dry handling. Commenter s stated that the bottom ash is sent to hydrobins (not ponds) and finally sent offsite dewatered. Commenter s 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 co nveyor and that this provided the unit approximately an 11 Btu/kWh heat rate reduction. Commenter s stated that a similar retrofit is possible on the existing wet sluicing systems at Station B. Commenters also stated that r etrofit 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. Commenter s state d 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. Commenter s stated that all three units are equippe d with dry FA handling systems. Commenter s 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. Commenter s stated that the dry FA handling systems are already considered an efficient h andling system, and would not achieve any further heat rate reduction with improvements. Commenter s stated that only like

- kind replacements of coal mill motors have been made at Station B. Commenter s stated that the plant employs best operating and mainten ance practices with coal motors; no additional heat rate improvement is predicted. Commenter s 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

.
Commenter s stated that the inherent moisture of the ir coal is below 10% and since higher rank coal are burned, drying does not provide a significant benefit.

Commenter s stated that material handling systems include coal, bottom ash, economizer ash

, and fly ash handling. Commenter s stated that with respect to coal handling systems, the use of more efficient motors can improve overall plant efficiency. Commenter s stated that with respect to ash handling systems, heat rate improvements may often be re alized 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. Commenter s stated that the original bottom ash and e conomizer ash systems at the Springerville Units 1 & 2 were water sluiced material handling systems. Commenter s stated that the Unit 1 bottom ash handling system could potentially be converted to a submerged flight conveyor (SFC). Commenter s 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 hopp er to the SFC. Commenter s stated that the auxiliary power savings from the conversion were reviewed and used to estimate heat rate improvements. Commenter s stated that the auxiliary power consumption of the wet ash handling system was estimated to be 1.0 M W while auxiliary power consumption for the dry ash handling system was estimated to be 0.08 MW. Commenter s 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. Commenter s 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 Commenter s 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. Commen ter s 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.

Commenter s stated that as an example, they have developed a lignite fuel enhancement system, DryFiningTM, which refines lignite coal through a drying and segregation process. Commenter s stated that the drying component utilizes waste process heat to raise the heating value of the coal. Commenter s stated that the refining component segregates the lignite stream and removes the higher density compounds that contain higher levels of sulfur and mercury. Commenter s stated that their C oal Creek Station has used DryFinedTM lignite since 2009. Commenter s stated that this enhanced coal has improved efficiency and overall emissions performance, including a 4 percent reduction in CO2 emissions. Commenter s stated that DryFinedTM lignite is al so used at their Spiritwood Stat ion 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:

Commenter s stated that changes to the boiler heat absorbing surface are possible. Commenters stated that t ypically, any such changes do not elevate boiler heat absorption b eyond the initial design but restore thermal efficiency approaching the initial design state. Commenters stated that

a ctions to improve heat removal by changes to the boiler produce highly variable results, with their members citing from 20

- 40 Btu/kWh payo ff, noticeably less than the 70 Btu/kWh cited by EPA's reference study. Commenters stated that a s previously noted, in many cases these changes do not fully restore boiler performance to initial design conditions. Commenter s present ed 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 t he 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 dep osits. Commenters stated that f requently these problems are induced by firing subbituminous coals

- so at best, these systems restore heat absorption to original design values. Commenters stated that i n 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 i ntelligent or aggressive cleaning to maintain original heat rate can be high payoff particularly for boilers with slagging/foulin g issues induced by switching to PRB coals.36 Commenter s 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 f raught with potential design problems that may actually increase the heat rate. Commenter s stated that because of this, the study ironically advises EGU owners that a better approach would be to construct a new power plant. Commenter s stated that such a so lution would then make the unit subject to CAA section 111(b). Commenter s 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. Commenter s 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 f or West Virginia EGUs because the available reduction has already been achieved.

Commenter s list ed limitations that should be accounted for and a site specific analysis may reveal additional limitations: Boiler operation/overhaul with new heat transfe r 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 trigge ring 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 pre vent sintering of SCR catalyst must frequently also raise temperatures at lower loads to prevent ammonium salt deactivation of the catalyst. These com peting goals limit the HRI at full load.

Commenter s presented information with regard to STATION A

- BOILE R ISLAND, BOILER OPERATION/OVERHAUL WITH NEW HEAT TRANSFER SURFACE

. Commenter s stated that adding heat transfer area to boiler surfaces is a possible methodology for reducing plant heat rate. Commenter s stated that a portion of the reheat surfaces were rep laced 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. Commenter s stated that th e split of surface area was completed to increase flue gas temperature at the SCR inlets, while maintaining overall steam temperatures at low load operation. Commenter s stated that due to the same heat transfer surface area being maintained, the improvemen ts 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. Commenter s stated t hat 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. Commenter s 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 not37 economical. Commenter s 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. Commenter s stated that no further improvements to the superheater or reheater tubes can be made to reduce the heat rate.

Commenter s presented information with rega rd to STATION B

- BOILER ISLAND, BOILER OPERATION/OVERHAUL WITH NEW HEAT TRANSFER SURFACE

. Commenter s stated that adding heat transfer area to boiler surfaces is a possible methodology for reducing plant heat rate. Commenter s stated that no additional heat transfer surface area has been added to any of the three units since its original design. Commenter s stated that the reheaters are still the original on all three units. Commenter s stated that some sections of the superheater have been replaced like

kind 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. Commenter s stated that adding surface to improve the steam temperat ures beyond the original design values would require a major evaluation of all affected pressure parts and typically is not economical. Commenter s stated that the units at Station B have the original heat transfer surface area that was designed for the uni ts 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.

Commenter s stated that adding heat transfer area to boiler surfaces is a possible methodology for reducing plant heat rate. Commenter s stated that the replacement of superheater and reheater tubes is part of a general maintenance practice that can recover heat trans fer performance that has been lost over time. Commenter s 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.

Co mmenter s 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 i n general, routine inspections and maintenance is performed to replace boiler compon ents in

- kind to maintain the original boiler performance. Commenter s 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 compar ed to the original design. Commenter s 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. Commenter s stated that Units 3 and 4 are on th e 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 t he response to Comment 1 in this section.

The following are summaries of the specific public comments under this comment:38 Commenter s stated that regarding economizer replacement (S&L 2.2), the Black Hills plants are generally too new for the problem de scribed by Sargent & Lundy to apply, and the issue has been deferred for a more nuanced engineering review. Commenter s 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. Commenter s stated that Naughton 3 w ill be converted to gas in 2018. Commenter s 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. Commenter s 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 pot ential for improvement by addressing existing problems with plugging and fouling. Commenter s stated that the improvement is under consideration but not budgeted. Commenter s stated that modification is planned for the four units of Jim Bridger from 2015 thr ough 2018, with an anticipated improvement of 21 Btu/kWh at each unit, that is, less than the range anticipated by S&L.

Commenter s stated that as noted in the 2009 Sargent & Lundy Report, "economizer replacements do occur during some selective catalytic reduction (SCR) retrofit projects. Commenter s 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

eco nomizer exit gas temperature , which would require a new or upgraded economizer section to lower the gas temperature for an SCR retrofit project. Commenter s stated that the temperature reduction may range from 20

- 40 degrees F...." and that they agree with this statement. Commenter s st ated 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. Commenter s stated th at 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 impro vement 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:

Commenter s addressed neural networks and stated that S&L indicates that EGUs can imp rove boiler efficiency from 0

- 1.5 percent by installing hardware and software that models and predicts EGU performance. Commenter s 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. Commenter s stated that most large EGUs in West Virginia have already installed such hardware and software during the installation of SCR39 and FGD devices, or to comply wit h 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.

Commenter s 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 ha ve generally achieved HRI through lower excess air and optimized air to fuel ratio and cannot further optimize the boiler operation for heat rate improveme nt without sacrificing NOx reduction.

• Units not already equipped with distributed control system (DCS) controls will have a harder time implementing the intricate system.

Commenter s stated that Black Hills and PacifiCorp both characterize the neural ne twork issue (S&L 2.3) as a matter of boiler controls. Commenter s stated that Black Hills agree d 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. Commente r s 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. Commenter s stated that no change is possible at Dave Johnston 1 and 2 beca use these units do not utilize a distributive control system, so a complete change of the control system would be required, which is not economical. Commenter s stated that PacifiCorp recognizes the potential for a neural network improvement on Dave Johnsto n Units 3 and 4, at Naughton Units 1, 2, and 3, and at Wyodak, although the modifications are not currently planned.

Commenter s stated that computer models, known as neural networks (NNs) simulate the power plants at various static and dynamic lo ads, 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. Commenter s 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. Commen ter s 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. Commenter s stated that the frequent tuning of the combustion system to optimize CO and fuel to air ratio also results in reduced unburn ed carbon, lower excess air, lower heat rate, and mitigates excessive slagging. Commenter s 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 automa te a portion of the work performed by the "tuning team", if necessary. Commenter s 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 he at rate benefit.40 Commenter s presented information with regard to STATION B

- BOILER ISLAND, NEURAL NETWORK. Commenter s stated that computer models, known as neural network (NNs) simulate the power plants at various static and dynamic loads, with the predi cted 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. Commenter s stated that no unit at Statio n B has NN installed but that the current group of burner/boiler engineers has OEM experience. Commenter s stated that these engineers have completed parametric testing that has helped optimize boiler operation. Commenter s stated that the boiler optimizatio n has also helped provide consistent unburned carbon levels which are required for ash sales. Commenter s stated that Unit B1 and B2 typically have only 1% unburned carbon. Commenter s stated that the frequent tuning of the combustion system to optimize CO

a nd fuel to air ratio results in these unburned carbon levels and a lower heat rate. Commenter s stated that Unit B3 does not sell fly ash. Commenter s stated that due to the station's employment of best operational and maintenance practices, it is not expect ed that any heat rate benefit would be achieved with the installation and operation of a NN system.

Commenter s 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. Commente r s stated the only thing you need to change in an internal combustion engine is the controls, electronic controls

-- we have them. Commenter s stated that they've had the space program with a lot of technology but it's not implemented and it needs to be imp lemented.

Commenter s stated that Big Stone Plant made DCS upgrades in 1996 and 2011. Commenter s 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). Commenter s 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.

Commenter s stated that combustion neural networks were installed on all the Big Bend Station coal units (mu ltiple types and manufacturers) as part of a U. S. Department of Energy NETL project during 2002 through 2004. Commenter s stated that after implementation of the automated systems, operator training was found to be more effective. Commenter s stated that

co ntrols 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.

Commenter s stated that computer models, known as neural networ ks (NN's) control the power plants' operation at various static and dynamic loads, with the performance results correlated to several real

- time process measurements. Commenter s stated that neural network control systems can be used to optimize emissions su ch as NOX and CO, as well as help optimize boiler efficiency. Commenter s 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 u p to date. Commenter s 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. Commenter s stated that the low NOx burners and secondary overfire air systems on Units 1 and41 2 a re adjusted accordingly for NOx control. Commenter s stated that TEP is currently operating their Foxboro DCS systems for optimizing their NOx and CO emissions and maintaining boiler efficiency. Commenter s stated that Units 3 and 4 are also equipped with Fo xboro DCS system but utilize SCR technology for NOx control. Commenter s 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 (ISB s)

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:

Commenter s 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. Commenter s stated that because ISB systems are used primarily wi th 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 respe ct to the installation of ISB systems is not achievable for West Virginia EGUs.

Commenter s list ed limitations that should be accounted for and a site specific analysis may reveal additional limitations:

Intelligent sootblower (ISB) system

• Many units ar e 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.

Commenter s stated that Black H ills agree d 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). Commenter s stated that PacifiCorp has scheduled this improvement at Wyodak for 202 2. Commenter s 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. Commenter s stated that intelligent soot blowers are sched uled for installation in Dave Johnston 3 in 2018 and Dave Johnston 4 in 2016. Commenter s 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. Commenter s stated that Naughton 3 will be converted to gas in 2018.42 Commenter s stated that the use of intelligent soot blower (ISB) systems for improving system effici ency 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 id entify affected areas that require soot blowing. Commenter s 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 intelligen t portion to either. Commenter s stated that the sootblowers are operated on a continuous cycle due to the heavy slagging/fouling that is experienced. Commenter s stated that Unit A2 is also equipped with sootblowers and water cannons and that Six Diamond Po wer sootblowers were added during the FGD installation. Commenter s 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 experien ced and that therefore, the addition of intelligent cleaning systems resulted in no heat rate improvement on Unit A2. Commenter s stated that the current non

- intelligent and intelligent sootblowing systems at Station A are required to operate on a consisten t 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.

Commenter s presented information with regard to STATION B

- BOILER ISLAND

- INTELLIGENT SOOTBLOWER SYSTEM. Commenter s 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. Commenter s stated that the ISB system functions by monitoring both furnace exhaust gas temperatures and steam temperatures to identify affected areas that require soot blowing. Commenter s stated that the units at Sta tion B are not equipped with ISB systems but are equipped with compressed air sootblowers, which are used almost constantly at full load. Commenter s stated that the low NOx burners (LNB) and over fire air (OFA) are the causes of heavy slagging/fouling of t he backend. Commenter s 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.

Commente r s stated that in 2011 Big Stone Plant installed an intelligent soot blower system in conjunction with a DCS upgrade. Commenter s stated that efficiency improvement from this project was small, primarily because Big Stone Plant's boiler was originally de signed for lignite coal. Commenter s 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.

Commenter s stated that Tampa Electric has implemented soot blower optimization technology on all units at Big Bend Station.

Commenter s stated that the use of intelligent soot blower (ISB) systems for improving system efficiency also enhances the performance of the furn ace and longevity of the tubing material, while minimizing cycling effects to the steam turbine. Commenter s 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. Commenter s stated that in order to attempt knowledge

- based soot blowing, they first installed strain gauges, which ultimately did not43 provide any benefit. Commenter s 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. Commenter s stated that these were taken out of service once the operators observed that the water cannon system had detrimental effects on the tubing. Commenter s stated that the current soot blowing systems are separate PLC

driven control systems, which were provided by Clyde

- Bergemann for Units 1 & 2 and Diamond Power for Units 3 & 4. Commenter s stated that attemp ts were made to implement an ISB system in addition to exploring an alternate water cannon method. Commenter s 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. Commenter s 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:

Commenter s 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 improvem ents in the APH result in substantial reductions of net fuel consumption and parasitic loads. Commenters stated that i n 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 boi ler. Commenters also stated that t he 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 w hile 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 b y increasing the temperature of combustion air through the pre

- heating process, the b oiler requires less heat and less fuel to obtain the desired combustion and production. Commenters stated that i ncreasing the temperature of the combustion air also results in higher temperatures at the top of the boiler. Commenters stated that a s a result , steam contacting the turbine contains additional energy which reduces the fuel required to achieve desired production.

Commenter s 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 t his not only improves the efficiency of the individual systems but also reduces failure rates an d 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 c omments under this comment:

Commenter s addressed Air Pre

- Heaters and stated that S&L reports that regenerative air pre

heaters 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. Commenter s 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. Commenter s 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. Commenter s stated that therefore, EGUs in West Virginia have already achieved available increases in bo iler efficiency from these heat rate reduction methods.

Commenter s 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 dow nstream 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

• Uni ts 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 applicabl e for units burning PRB and lignite.

Commenter s addressed Lower Air Pre

- Heater Outlet Temperature by Controlling Acid Dew Point. Commenter s stated that the air heater outlet temperature typically is controlled at 20

- 30 degrees F above the sulfuric acid de w 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. Commenter s 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 fue ls. Commenter s stated that because of this, both units are equipped with dry sorbent injection for sulfuric acid mist (SAM) reduction prior to the FGD. Commenter s stated that prior to 2005, some of the air heater baskets were removed from Unit A2, due to u nit performance issues. Commenter s stated that they were later reinstalled to lower the APH outlet temperature and are now back to design capacity. Commenter s stated that Unit A1 uses APH steam coils and Unit A2 uses glycol heaters45 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. Commenter s stated that air heater bask ets 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. C ommenter s 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 m ost of the baskets were eventually reinstalled before 20 12, due to having insufficient heat transfer after the economizer surface was split before 2005; the unit is now close to original design temperatures. Commenter s stated that at the high sulfuric acid dew point associated with the fuel fired, air heater ou tlet temperatures are typically controlled to stay above 305 degrees F. Commenter s 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. Commenter s s tated that there is also a cap on air heater outlet flue gas temperature due to the injection of Trona downstream of the air heater. Commenter s stated that temperatures above 350 degrees F could result in the formation of sodium bisulfate which is difficul t 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. Commenter s stated that sorbents can sometimes be injected upstream of the a ir 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 t o air heater pluggage concerns. Commenter s 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 pot ential risk of plugging the air heater baskets due to sodium bisulfate. Commenter s 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 t he potential to adversely affect operation. Commenter s stated that since Trona injection on Unit A1 and A2 occurs downstream of the APH, air heater outlet temperatures cannot be reduced further. Commenter s stated that the unit cannot take advantage of redu ced acid dew point temperatures unless the Trona was injected upstream of the APH. Commenter s stated that previous testing experience by various utilities suggests that the downstream location is preferred to avoid any APH plugging as well as provided lowe r 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. Commenter s 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.

Commenter s stated that the second method is lowering air pre

- heater outlet temperatures by controlling sulfuric acid dew point with alkali i njection, allows for recovery of additional heat into the comb ustion air with added heat transfer surface. Commenter s 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. Commenter s 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. Commenter s stated that this technology is gener ally 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%). Commenter s stated that since the46 units fire a low

- sulfur fuel and are not equipped with and SCR, very low SO3 concentrations are present at the air heater inlet. Commenter s stated that DSI equipment vendors typically do not guarantee SO3 emissions below 5 ppmvd at 3% O2; therefore, this technology is not feasible. Commenter s stated th at the potential for a future SCR retrofit would likely preclude the unit from reducing the APH outlet temperature, thereby preventing additional heat recovery.

Commenter s stated that PacifiCorp generally characterized the acid dew point control (S&L 2.5.2) issue by reference to S&L's su ggested remedy, which focuses on lowering outlet temperature by air heater modifications. Commenter s 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. Commenter s stated that for Dave Johnston 1 and 2, the change was uneconomical due to extensive changes that would be required for existing structures. Commenter s stated that heaters have a lready 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. Commenter s stated that for Naughton Units 1 and 2, and the four Black Hills plants, are alrea dy operated near the acid dew point.

Commenter s 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 th at will be used at Big Stone Plant.

Commenter s 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. Commenter s sta ted that APH gas outlet temperature data obtained from one of their members indicates that they operate within the margin to avoid sulfuric acid condensation. Commenter s stated that to enable lower air heater outlet temperatures, dry sorbent injection (DSI ) could be instal led in order to remove SO3 and lower the acid dew point temperature. Commenter s stated that this technology is generally applied to medium

- to high

- sulfur fuel applications. Commenter s stated that the ir 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. Commenter s stated that Units 1 and 2 do not have an SCR; as such, SO3 is formed only by oxidizing SO 2 in the boiler. Commenter s stated that testing conducted on Unit 1 in 2014 indicated that the SO3 levels at the APH averaged below 5 ppmvd. Commenter s stated that this data is also indicative of SO3 levels expected on Unit 2 because of identical designs o f the two units. Commenter s 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.

Commenter s stated that the oxidative properties of SCR c atalysts on Units 3 and 4 result in slightly higher SO3 concentrations due to SO2 to SO3 oxidation that occurs across the SCR catalyst. Commenter s 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. Commenter s 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.

Commenter s 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 SO247 control. Commenter s stated that as a result, the inlet temperature to the DFGD vessels should not be reduced.

Commenter s 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 ope rating efficiency of the do wnstream 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 Comme nt 1 in this section.

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

Commenter s 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. C ommenter s stated that the APH accounts for over 10% of a power plant's thermal efficiency. C ommenter s cite d studies that show that a 1% in crease in boiler heat rate results when 12% of the APH is leaking and/or blocked. C ommenter s recommend ed a rule requirement that APH leakage be restricted to less than 5%. C ommenter s also recommend ed that new boilers be required to only use recuperative (o r tubular) APH which, due to their design, inherently have no air leakage.

Commenter s listed limitations that should be accounted for and a site specific analysis may reveal additional limitations:

Air heater leakage Mitigation

• Many units already emplo y 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, uni ts 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 PRE

HEATERS . 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 of48 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 additio nal 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 le akage 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 outag e, the air heaters are washed to remove any particle pluggage. Commenters stated that the Unit A1 air pre

heater 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 mainte nance 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 general ly operated close to 40

- 50% in

- leakage at the end of a three

- year cycle. Commenters stated that

a fter 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 inspe cted 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 in

leakage 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 in

leakage.49 Commenters stated that Station B includes a compil ation 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 a ll 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 h igh air pre

- heater leakage raises auxiliary power requirements due to processing higher volumes of gas in downstream equipment, such as ID fa ns, 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 a sh 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 stat ed 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 r equired. 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 val ues; 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 mai ntain their current average in

- leakage rates.

Commenter s 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 imp rovement 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.

Commenter s stated that c oal

- fired EGUs use air heaters to pre

- heat the combustion air for improved combustion and overall unit efficiency. Commenters stated that Big Stone P lant air heater is a regenerative Ljungstrom air heater, which rotates a cylindrical shell and basket

packed 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 demonstr ates 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 that50 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.

Commenter s 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 fro m 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 lo wer 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 t he 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 estim ated 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 th at 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 dow nstream 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 com ment:51 Commenter s 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 t his technology is presently under feasibility evaluation by a source located in Waupaca County, WI. Commenters also stated that t his source is not an operation that will be affected by regulated EPA carbon emission reductions

. Commenters stated that h owever , the operation is a major CO2 emission source (300 K TPY) and that i mproved 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, retrofit s 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:

Commenter s stated that turbine overhauls are referenc ed 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 r egular 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 uni ts at peak efficiency (i.e., profit maximization and competitive advantage)

.
Commenter s stated that steam turbine upgrades are likely the most commonly deployed heat rate improving method

, b ut the existing, legacy turbine can only be upgraded once. Comm enters stated that i t 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 c onsequently, many eligible units have already received steam turbin e upgrades and further efficiency improvements for the proposed rule are unlikely.

Commenter s stated that the thermal efficiency of generating power from fossil fuel plants degrades with time, both due to component wear and cha nges in plant operation. Commenters stated that c omponent 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 d eposits 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 f or example, changes to the steam path can potentially provide high payoff in lowering heat rate. Commenters stated h owever, the magnitude of the benefits does not stay constant, with payoff decreasing with time from the "new" state , and that f ield data back up this assertion. Commenters presen ted 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 in52 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 t he 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.

Commenter s 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 syste m 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.

Commenter s 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 own ers have already deployed these retrofits to exploit state

of

- art extraction technology to lower heat rate, and thus CO2 emissions and fuel cost. Commenters also stated that a ccordingly, the efficiency gains from these deployments are already in the "basel ine" of the proposed rule.

Commenter s 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.

Commenter s 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

re placement). 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, "St eam 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 commissio ning; 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 th at 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 turbi ne 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 i ntervals, 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. Commen ters 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 th at 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

Commenter s 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 technol ogy 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 alr eady 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 custo mers 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 t hat 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 existi ng 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 re maining life in the equipment/plant will be a critical factor in determining the potential for this type of investment.

Commenter s 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 turb ines 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.

Commenter s 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 im provement.

• 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 p resented 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 compon ents 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 re heat 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. Comment ers 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 reg ain 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 i mprovement 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
p roject 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 instal led 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 com plex 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 th at 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 ach ieved 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.

Commenter s stated that as noted in the 2009 Sargent & Lundy Re port, "[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 t hese upgrades take into account the loss in performance over time (degradation)" Commenters stated that again, Otter Tail agree with the Sargent & Lundy report. Commente rs also stated that h owever, 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.

Commenter s stated that technological advancements have improved the efficiency of steam turbines compared to the turbines th at 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

co mponents installed in 2007, also with new inner blocks and rotors. Commenters stated that i n 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 additi onal 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 improvem ents 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 f or Unit 2, changes to the LP sections yielded similar he at rate improvements following changes made to the HP/IP sections. Commenters stated that i t was assumed that a similar trend would be observed following changes to turbine components on Unit 1. Commenters stated that t his 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 f eedwater h eaters

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:

Commenter s addressed Feedwater Heaters and stated that t he S&L study indicates that increasing feedwater heating surface area in feedwater heaters can i mprove boiler efficiency but that the study also notes that such modifications are cost

- prohibitive.

Commenter s listed limitations that should be accounted for and a site specific anal ysis 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 temperat ure 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. Comm enters stated that r egular 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 incre ase 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 Commen ters 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 im prove 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 inc rease 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 bu t 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.

Commenter s stated that feedwater heaters are used within a powe r 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 temperatur e 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 maint ain 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 f rom 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:

Commenter s 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 o f 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 he at rate reduction would not improve the heat rate for existing EGUs.

Commenter s 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

c onfiguration, 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 th at 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 f requently, 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 chan ges 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.

Commenter s list ed 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 pract ices 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. Commenter s 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 condenser s 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 in

leakage 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 ro utine 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 kno w 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, CONDE NSER. 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 fouling59 leads to reduced heat transfer rates, while air in

- leakage directly degrades the quality of the water, however, if a closed cooling system is us ed, 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 beca use 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 durin g 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 closel y 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, monitorin g 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.

Commenter s stated th at 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 tr acking 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 an d 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 b y 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 e rosion 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 clea ning measures.

Commenter s 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 ope rates 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 y ears in order to maintain condenser performance. Commenters stated that the condenser is cleaned with brushes as the Station has60 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 desig ned with Sea

- cure tubes. Commenters stated that they ha ve 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

corr osion, 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 orig inal 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 Comme nt 1 in this section.

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

Commenter s 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.

Commenter s stated that Pacif iCorp 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.

Commenter s 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 furt her 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 i ts 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 fea sible 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.

Commenter s stated that Big Stone Plant has two high

- pressure, steam t urbine

- 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.

Commenter s 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 efficienc y and are regularly maintained using best practices; therefore, no62 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 re sponse to Comment 1 in this section.

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

Commenter s 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, whi ch 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 Virgin ia'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.

Commenter s listed limitations that should be accounted f or and a site specific analysis may reveal additional limitations: Flue G as 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

a ssociated 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 th at 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 pressu re 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 approximately63 1MW of aux power with the speed switch; however, this is only a temporary change that
prov ides 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 t he 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

- sp eed FD fan. Commenters also stated that i t 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 lo aded, 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 w ere 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 mainte nance 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 tha t 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.

Commenter s 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 c urrently, 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 th e 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. Co mmenters 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 requir ed 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 sta ted 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 appreciabl e 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 Dri ves (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:

Commenter s 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 regardi ng 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 o f 20

- 100 BTU/kWh S&L associates with VFDs.

Commenter s 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 decr ease 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 cons idered for added improvements in heat rate.

Commenter s 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 modifie d 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.

Commenter s stated that the installation of variable fre quency 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 PacifiCor p 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 m odifications to the induced draft fans at the four Black Hills units are included in their 2% estimate.65 C ommenter s 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 retrofi tted 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 i mprovement 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 ba se 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.

Co mmenters 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 le vels of operation in the future; therefore, it is predicted that no heat rate reduction can be experienced from this potential retrofit.

Commenter s 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 fa ns 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 p rimary 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:

Commenter s 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 centrifu gal 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 P A 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 varia ble 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:

Commenter s 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 engineer ed 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.

Commenter s addressed Turning Va nes & 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 incorporate67 improved design scrubbers in engineered redesigns of flue gas systems due to recent installations of emission control devices. Commenters stated that turning vanes and p erforated 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.

Commenter s addressed Shutoff Spray Level and stated that the S&L s tudy 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.

Commenter s 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 dis tribution 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 propo sed 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).

Commenter s 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 WFGD s.

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. Comm enters 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 1 7MW increase in auxiliary power and approximately 300 Btu/kWh net heat rate increase. Commenters stated that Unit A268 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 state d 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 r eduction. 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 conditio ns 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.

Commenter s stated that all four units at Springerville Station are equipped with spray dryer absorber (SDA)

- type dry FGD systems. Commenters stated that the potent ial 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 bas e 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. Commente rs 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 addr essed by the response to Comment 1 in this section.

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

Commenter s 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 th at 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 i mprovement 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 m odifications to Naug hton 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 Commenter s listed limitations that should be accounted for and a site spec ific 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 describe d 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, th e 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 fi ring 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 t heoretically, an EMS system could be installed on Unit A1 to reduce auxiliary pow er 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 stat ed 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.

C ommenters 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 applicabl e 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 fabr ic 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 periodically70 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 e liminated 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 im provements to achieve heat rate reductions and that n o future heat reduction is deemed feasible on any of the three units at Station B.

Commenter s stated that ESP modification does not apply to Big Stone Plant because a baghouse, not an ESP, is used for control of particulate matter.

Commenter s 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 sta ted 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 take n 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 i s 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 : Comme nts regarding b aghouses

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:

Commenter s 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 membran es, 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 dr op 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 origina l 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 t his comment:

Commenter s 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.

Commenter s listed limitations that should be accounted for and a site specific analysis may reveal additional limitations:

Selective catalytic redu ction (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 w ith 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 emissio ns 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 a mmonia 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 mo dules, 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 neith er 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 EQ UIPOMENT, 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 non

catalytic reduction (SNCR) technology were to be incorporated on Unit B3, the installation would come with a h eat 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 stat ed 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 install ing 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 w ater t reatment s ystems on heat rate

Response 24 : The response to this comment is addressed by t he response to Comment 1 in this section.

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

Commenter s 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 like ly 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, B OILER WA TER 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 boi ler scale lowers heat transfer by73 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 me tal 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 a mmonia is currently used to maintain a high pH (8.8 minimum) which helps with the oxygenated system and reduces scaling. Commenters stated that t he 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 i n 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 lowerin g 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 subs equent 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 u se 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 technolog ies to reduce boiler scale and improve plant heat rate.

Commenter s 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. Commente rs 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 a nd 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 overall74 power plant efficiency. Commen ters 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 polishi ng. 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, reduc e boiler blowdown and i mprove 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 p ublic comments under this comment:

Commenter s 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. C ommenters 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, wh ich 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 coo ling 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.

Commenter s stated that Big Stone Plant uses a cooling pond rather than a cooling tower, so this option is not available.75 Commenter s 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 fr om 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 poten tial area for heat rate improvements is the upgrade of large electric motor (>450 hp) by replacing older electric motors with new, energ y efficient motors and that the primary problems with implementing more efficient motors are the cost of the materials a nd 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 maintaine d 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 t o 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 ch anges 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 discus sed, 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 t oday 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 s tated that as part of the regular maintenance plan at Station B, the large electrical76 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 expect ed 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 efficienc y to justify premature replacement. Commenters also stated that w ithin 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 hea t rate improvements that are technically feasible. Commenters stated that i n 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.

Commenter s stated that Springerville Uni ts 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 min imum 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 addi tion, they ha ve 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.

Commenter s 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 w ith 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 stat ed 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 in stall 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 Commenter s 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 i n 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 th at is recovered by an individual project cannot be recovered a second time. Commenters stated that

s mall increments of efficiency improvements in the APH result in substantial reductions of net fuel consumption and parasitic loads

.
Commenter s stated th at many available heat rate improving actions are not independent

- each is related. Commenters stated that e ach heat rate improving action affects unit efficiency in a different manner, and the payoff is not directly additive. Commenters stated a s an exam ple, the effluent heat from a boiler can only be captured once

- thus benefits from multiple boiler upgrades are not directly additive. Commenters stated that s imilarly, the individual steps within a steam turbine to improve heat rate are not additive. Com menters stated that t otaling 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 betwee n various popular heat rate actions.

Commenter s 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 upgra des, 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
p ower, 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 imp roving 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 regulation s. 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 t he 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 i t also includes a list of factors which could lead to an increase in coal power plant heat rates including more operation at part

- load, add ing more environmental control equipment, switching from

once

- through to evaporative or air cooling, and switching from bituminous to lower subbituminous coal.

Commenter s 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 the ir subsidiary company, Diamond Power, provide s 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 for78 any given plant, they are not necess arily additive (i.e. not every improvement identified in the report will be applicable to every plant). Commenters conclude d that some plants may have little or no opportunity for improvement based on their age, maintenance and operating practices, prior r etrofits or upgrades, capacity and operating mode.

Commenter s 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 pote ntial 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 addit ive 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 advance d neural network controls.

Commenter s 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 applyin g 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, i n 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, iden tifying 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.

Co mment 1: General, multi

- study comments

Response 1: For EPA’s response to the issues raised in these comment s , see Chapter 2 of the GHG Mitigation Measures TSD supporting the final CP P. 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

- refere nced 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

C ommenters asked :

1. Why did the EPA not desc ribe 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 studi es not detailed in this section but included in the bibliography factored in?

Commenter s stated that the study fails to account for upgrades that specific facilities have already made, thus, the report's conclusions of untapped technology

- ba sed heat rate improvement potential appear to be exaggerated. C ommenters 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
sup ported 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 st udy of WEPCO's "two

- phase80 efficiency program at four coal

- fired plants," similarly identified onl y 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 in adequacy 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 adeq uately 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 rat e 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 environ mental regulations such as the Mercury an d 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 Improve ments ” which summariz es the results of their recent projects focused on improving the heat rate of operating coal

- fired power plants. Commenters stated that t he study identified examples

- both demonstrated/realized and projected

- of methods to improve hea t 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. ( R eport 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. ( R eport 1023912, "Methods to Mitigate the Effect of Increased Cycling and Load Following on Heat Rate")81 • Remote Monitoring. The use of remote monitoring centers was documented to improve net heat rate 2.5 to 4%. ( R eport 1023075, "Evaluation of Remote Monitoring Heat Rate Improvement")

• Steam Turbine Steam Path Modif ications. Their members reported steam turbine steam path modifications were worth 2% to 4% net heat rate improvements. ( R eport 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. ( R eport 1024640, "Cost Benefit Assessment of Cycle Alignment")

• Capital and Maintenance Projects. A list of 57 potential actions and m odifications 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 utilit y 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.( R eport 1019002, "Capital and Maintenance Projects for Efficiency Improvements")

Commenter s su pported use of building block 1, and stated that heat rate improvements, are adequately demonstrated and cost

- effective. The commenter s cited an independent study that indicated the proposed heat rate improvement of 6 percent was achievable by the U.S. fleet of EGUs. The commenter s 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 Boile rs
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 discusse s the factors that could influence boiler's unit heat rate.

Comment 4 : EPRI, 2 011 Cycling and Load Following Effects on Heat Rate82 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:

Commenter s 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 f rom 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. Com menters 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 increas e 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

mea sured. 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, an d 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 ident ify 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 u nit 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 initia l 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 rath er, against each other.

Comment 5 : 2009 Sargent & Lundy (S&L) report83 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.

Th e 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 w ork 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 ne w 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 resu lt 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 correspo nds 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 impac t 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 cann ot 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 pollu tants). 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 dete rmination, 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 Repor t, 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 imp rovement 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 a nd that, by combining HRI methods84 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 avera ge 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 establi sh a combined fleet

- wide minimum/maximum HRI capital cost . Commenters stated that cost estimates provided in the 2009 S&L Report represent order

- of

magnitude costs and were provided for comparative purposes only and that the costs were not intended to serv e 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 represent ation 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 cost

effectiveness 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 s tudy 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 w ere not yet implemented. Commenters stated that EPD believes that many of the more feasible and cost effective HR I projects have already been accomplished and the law of diminishing returns will make achieving similar HRI targets difficult in the future. C ommenters 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 im provement 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 cont rol 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 S tandards (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 i t 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 percen t 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 h ave 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 stud y'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 b road 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.

• Commente rs 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 each86 strategy and the amount o f 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 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 verifi cation 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 achie ve 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

- r elated 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 eval uated 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 ob tained 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 s hifts 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 opera tion. 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 installatio n 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 optio ns 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 prac tices87 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 potent ial 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. coal

fired 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 simi lar 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 rang es 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 a ddition, 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 20 09 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
te chnical 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 me rely selected based on in

house 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 te chnologies. 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 su mmarizes 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 tec hnology 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 havi ng 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 achie ve 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. There fore, 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 sh ow 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 b ased 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 i mplemented 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 s tated that t he 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 a lternatives 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 ea ch 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 ach ieved 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 i ndividual 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 l ower 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 it s 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 subse quent to the 2009 Report, it appears that most of the utilities are already employing best operational and maintenance practices.

• Commenters stated that t he case studies performed in the development of this study estimate that on a weighted average, approx imately 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 al ready 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 improvemen t 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 A gency'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 sta ted that they are in general agreement with the re ferenced 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 study90 • 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 he at rate potential of the US coal

- fired EGU fleet

Com menters presented a table ( Table A

- 1 show s 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. Com menters 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 n ot 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 po tential 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

ex amples that cannot necessarily be re plicated at other facilities.

Commenter s 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 undermin ing 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.91 • Commenters stated that the results in the 2009 Report were mostly based on publicly available data, data from or iginal equipme nt 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 pl ant design, pr evious 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 coal

fired 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

- speci fic 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 aff ect, 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 economicall y 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 redu ce 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 lo wer 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 l osses 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 heat92 rate efficiency of any unit as compared to its heat rate effi ciency 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 mo st of the utilities are employing best operational and maintenance practices. Commenters stated that i n light of t his observation, it appears that significant further reduction in heat rate, such as that assumed by the EPA, may not be feasible.

Commenter s 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 coal

fired 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 st ated 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 tha t 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),

com prising 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 subb ituminous 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 that93 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 syst em 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 h eat 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 a lso 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 bu rn bituminous coals and were later converted to burn PRB. Commenters stated that most of these boilers were significantly derated to bu rn 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
state d 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 u nits 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 cas es 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 existi ng 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 co stly upgrades that can run up to $10,000,000 for a 500 MW unit not including outage time cost for94 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 m ore 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 s ystem 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 a nd 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 recyc le 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 an d 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 E S P that have already been upgraded with mode rn voltage cont rols 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 pow er 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 c annot take advantage of this power saving design

-- also other OEMs may also have used this feature since the report was written in 2009.95 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 lea ds 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.

Commenter s 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 commenter s questioned if some or all of these measures reduce heat rate variability, or just overall heat rate. The commenter s also questioned that if some reduce variability, EPA should specify which ones . The commenter s also questioned that f or those that do not reduce variability, EPA should clarify if they support a claim that improvements of 4% are available through reducing vari ability

.
Commenter s 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, de nies 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

- fi red 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 t emperature. 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 that96 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 prov ided. . . 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 Commen t 1 in this section.

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

Commenters stated that in the 52

- Unit Study, the y 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 elec tricity 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 t o 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 Microsof t 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 captu red 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 t he 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 carb on 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 likeli hood that EPA's guidelines will be based on annual average emissions. Commenters stated that to illustrate data from one facility in the study, c ommenters presented Figure 2 (titled:97 “ Cross Unit One Daily Average Emission Rate, 2001

- 2012 ”), which depicts t he daily average emission rate at Cross Unit One during the 12

- year study interval

. Commenters also provided Table 2 r esults of the 52 Unit Study.

Commenters noted that EPA proposes a single HRI target to be applied, on average, to all remaining coal

- fire d 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 s ingle 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 s et 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, the y also examined the extent to which the fleet's daily average emission performance varied with res pect 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. Comm enters 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 i n 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, w here 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 wh ether 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 upgrade s. 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 units98 that are dispatched less frequently), a conservative estimate for the averag e 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 r esults 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 i n 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 st ated 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 )

R esponse 7 : CO 2 has no bias adjustment factor. For the remainder of the issues raised in these comments, s ee 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 th is 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 pe rcent 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 a nd how these procedures are designed to overestimate emissions. Commenters stated that, however, EPA does not mention how BAFs or how BAF

- ad justed 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, add ing 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 "approx imately two thirds of the large decreases in heat rate" in its study population of 355 units99 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 c hanges 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 Abate ment 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 refe rence 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 continue d stating that it might be argued that RMB possessed "inside" information regarding the case s tudy 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 availabl e 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 facto comment r (WAF) (whether default value or calculated).

Comment ers 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 state d 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 U se of Reference Units to Select Heat Rate Reduction Targets100 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 s olely through equipment upgrade s, 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 su pporting the final CPP

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

Commenter s 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 th e Part 75 reported data were due to unrelated normal variations in continuous emissions monitoring system (CEMS)

- based hea t input values, and not the result of proactive steps to reduce heat rate. Commenters stated further that as a supplement to that rep ort, they asked RMB Consulting & Research, Inc. (RMB) to review the summaries of the owners' explanations an d 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 chang es 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 ave rages 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 the101 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 modifi cations, 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 upg raded 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 fiel d 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 th e 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 th e 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 i mprovements 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 bene fits 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.102 Comment 1 0 : Comments regarding N ETL studies and workshops in general

Response 1 0 : 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 suf ficient 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 Ene rgy 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 hea t 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 unit

specific 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 eff iciency 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 install ing 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 ma intenance 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 runnin g 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% fl eet

- 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 failed103 to consider these repor ts 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. Commente rs 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 i n 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 somethi ng 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 ent itled "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.104 Comment 1 1 : Comments regarding th e availability of the NETL report
, "Reducing CO2 Emissions by Improving the Efficiency of the Existing Coal

- Fired Power Plant Fleet ”

Response 1 1 : 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 commenter s , 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 direc tly 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 t ype 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 C oal

- 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 a nd 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 Coa l

- 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 takeaway s 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 u nits operating at lower load factors.

• NETL acknowledged that quantification of the opportunity to improve efficiency could be improved by things such as:105 − Verification of the data;

− Unit

- specific data to enable estimation of the heat rates

− Estima tes 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 variabi lity, 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 Coal

Fired 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 w ould 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 estim ates 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 RA TES OF COAL

- FIRED POWER PLANTS". Commenters stated t he article discusses research projects investigating heat rate improvements in coal

- fired power plants.106 Comment 1 4 : Comments regarding the Resources for the Future study, "Regulating Greenhouse Gases fr om 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 r ather 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 ad ditional 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 t he paper considers how market and/or regulatory impacts might influence or "force" the realization of heat rate improvements. Commenters stated that i n similar fashion to other EPA references in the TSD, the entire report i s 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 t echnical 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 foun d 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 th at 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 improvem ent 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 sam e 2009 S&L report used by EPA in the107 proposed rulemaking to characterize and support its assumptions for heat rate improvem ent. Commenters stated that NRDC provided a table in Appendix V to show that the technical heat rate improvement options addressed co nceptually 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 infor mation 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 i mprovements 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 powe r 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 a rticle 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 t o control for firing type, capacity and fuel type and found significant heterogeneity in the data. Commenters stated that the heterogeneity in the data after factor ing in these three technical features was evidence, they believed, that there was room to im prove 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 ke y 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:108 • Comment ers stated that they limited th e 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 fa miliar 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 var iability 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. Co mmenters 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 mar kets. 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, thi s 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. Comm enters 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

re gulated 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 cont rolling 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 key109 parameters that impact heat rate and are be yond 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 th ree 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 t han 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 pe riod 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 an d 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 deter mined 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 c an 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 t he article discussed power plant efficiency.110 Comment 20 : Topic Paper #4 Electric Generation Efficienc y, 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 t he 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 E GU 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 sev eral 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 bl ock 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 preamb le 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 reflec ts many of the factors highlighted by commenters.

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

Commenter s 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 can111 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 pl ant 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 e fficient 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 an d 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 addi tional 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.

Commenter s 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 opportuniti es 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 g enerating plants.

Commenter s 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.

Commenter s stated that there is a steady decline of heat rate for coal

- fired units during long runs of operation an d, 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 st ated that the performance of some heat rate improvement technologies degrades over time, even with best maintenance practices. Commenters stated t hus, the unit heat rate initially obtained through the implementation of new heat rate improvement technologie s will likely increase over time.

Commenter s stated that EPA ignores the adverse effect on heat rate that implementing the other Building Blocks will have

Commenter s summarized EPA's heat rate analysis and listed the following issues:

• Heat rate a ssumptions are incorrect.

• Not all EGUs are created equally112 • 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.

Commenter s stated that the proposed ESPS emission reduction goals for the states are all based on four compliance building blocks (BBs) th at 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 coa l

- 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 e xisting 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 re

dispatched to natural gas

- fired combine cycle (NG CC) units. Commenters stated that at a minimum, the Florida emission limiting standard goals should be adjusted to reflect this fact.

Commenter s stated that EPA developed building block 1 by assuming an amount of improvement identified in the Sargent a nd 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 monit or 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 turbin e 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 Wisconsi n 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 w ay 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.

Commenter s 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 any113 remaining improvemen ts 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 R ule (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 a nd 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.

Commenter s stated that under the Prop osed 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 prac tices," 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 ha ve already implemented most of the best practices and equipmen t 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

Commenter s stated that not all heat rate improvements are cumu lative, 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 improv ement 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.

Commenter s stated that the EPA has suggested that State's ad opt 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.

Commenter s 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 i nstead, 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,114 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 practi ces. 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 ar ithmetic 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 thes e 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 da ta 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 ac hieve 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 performanc e necessary to achieve the goal, as required by the D.C. Circuit

.
Commenter s 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 implem ented by them and/or would provide no meaningful incremental heat rate reduction.

Commenter s stated that i n 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 generat ing 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.115 Commenter s stated that EPA also incorrectly applies a single HRI percentage to every EGU and that this method d oes 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 f or 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.

Commenter s 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 p roposing this rule

. The c ommenter s 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

r egression 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 abou t the Agency's compliance with Clean Air Act (CAA) Section 307(d ).

Commenter s stated that EPA's assumptions are not achievable for their facility and for example, they ha ve 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 tha t 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 investme nts, 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 recommend ed that the efficiency improvement for existing coal

- fueled power plants should be reduced from 6% to 1%.

Commenter s 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 i mplemented best practices and made the equipment upgrades identified by116 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 st ated 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 s ignificantly more difficult for lignite

fired units to achieve heat rate improvements

.
Commenter s 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 exi sting 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.

Commenter s 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 f leet 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 request ed 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

.
Commenter s stated t hat 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 c ommenters were aw are 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.117 Commenters stated that few heat rate improvements are availabl e 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 a djust 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 w ere 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 stat ed 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

.
Commenter s 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, challengi ng the viability of the assumed improvements that can be achieved in building block 1. Commenters stated that w hile they do n't own or operate electric generating facilities, it seems logical to them that owners of such units (1) have already made improveme nts 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 o utput 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 t he block's assumptions are interdependent, not independent

.
Commenter s 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 opportuni ties 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.

Commenter s 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 capricio us

. Commenters stated that it also denies the states the ability to undertake considered rulemaking to evaluate the four118 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 over

stringency 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 buildi ng 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.

Commenter s stated that even if they had not incorpor ated 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 secon d, 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 o f 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 dire ctly 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.

Commenter s 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 p otential 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 expecte d remaining life of those units.

Commenter s 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

. Co mmenters 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.

Commenter s stated that they ha ve implemented heat rate imp rovements 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.

Commenter s 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 ha ve installed environmental control equipment for SO2 and NOx (FGD; LNB with SC R 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 as119 base load units to cycle as more the capacity factor of NGCC units rises. Commenters stated that cycling increases heat rate and that they ha ve 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%. Comm enters 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 a t 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.

Commenter s 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 be cause 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 pla nts 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, "site

specific engineering analyses" would be re quired 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 i mplementing Building Blocks 2, 3, and 4 will all have the effect of reducing the run time of affected coal power plants. Commenters stated that i t 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.

Commenter s stat ed 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 c ause 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.

Commenter s stated that the EPA's proposed rule is ar bitrary 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 a s 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 s tandards. Commenters120 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.

Commenter s stated that they ha ve a long history of implementing heat ra te 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

- fuel ed 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 con cerned 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 u nit 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 esta blishing 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. Commenter s 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.

Commenter s stated that EPA has used primarily two studies to determine potential heat rate improvement capability fleet wide. Commenters stated that t hese studies were from Sargent and Lundy (S&L) and National Energy Technology Lab (NETL). Commenters stated that in these

s tudies, 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 f urther discussion of these items is contained in an ASME presentation on September 25, 2014 ( https://www.asme.org/events/asme

- energy

- forum/power

plant

- efficiency ). Commenters stated that in summary, EPA chose to look at all the potential, not actual, impro vements available without accounting for the heat rate degradation from additional pollution controls, and unit cycling

.
Commenter s stated that EPA assumes that coal

- fueled plants can achieve a 6 percent heat rate improvement by 2020 through a combinat ion 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 acco unt 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 s hows no incremental heat rate improvements were possible from additional practices. Commenters stated121 that the 2 percent improvement from capital investments rests upon a single 2009 study. Commenters stated that h owever, 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.

Commenter s 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 mainte nance practices , or 3) evaluate that such practices, are cost effective

- both in a competitive and regulated market structure. Commenters stated that t he proposed rule's use of a 4% HRI for maintenance and operating practices is significantly overstated which results in a BSER that is unachievable.

Commenter s 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 effici ency 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

r egulations 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 propose d that the coal plant efficiency target of 6% be reduced to a more achie vable target.

Commenter s 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. Commenter s 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

c onsider the impact of subsequent building blocks on the emission rate reductions that could be achievable at coal

- fired steam EGUs.

Commenter s stated that to the extent that there are potential heat rate improvements, EPA must also take into account th e 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 project s. 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.122 Commenter s 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 rai sed 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 a lso 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 th at the assumed heat rate improvements across the entire coal fleet are "unlikely."

Commenter s 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 imp lemented, as well as provide relief from triggering New Source Review for efficiency programs that might be implemented after the rule is finalized.

Commenter s 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 re liability 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 regu lations, not even the proposed regulations. Commenters asked if EPA has numbers that can speak to the grid re liability 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 k nows 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 susta ining 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 rat e 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 negat ive effects and variability comes from basic unit design, fuel characteristics, operating load conditions, age/condition of equipment, maintenance and cleanliness of components.1 23 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."

Com menter s 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 at tempt 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 a ttempt 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 n o analysis
sup ports 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 fire d 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 improv ed 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.

Commenter s stated that EPA's statistical analysi s 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 n ot 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 varia tion, EPA124 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 c oncern is that because EPA did not consider enough of the factors bey ond the operator's control that impact heat rate, the approach used by EPA mistakenly considers the unexplained variation in their two

factor analysis as an opportunity for improvement in heat rate rather than the effects of other important factors that we re not considered.

Commenter s 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
commenter s also stated that EPA does not explain why a twenty

- two mile average distance (p. 2

- 19) is con sidered a good approximation to determine the temperature at an EGU, and questioned the methodology EPA used to make this determination.

Commenter s 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.

Commenter s 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 datase t 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 w hile 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 knowledg e, 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.

Commenter s 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% o f heat rate improvement can be achieved through best practices and an additional 2% can be achieved by equipment upgrades. B ut that however, there is no way to guarantee or even support that these types of improvements can be achieved at every, or even mos t, units. Commenters stated that EPA's fundamental basis outlined in its GHG Abatement Measures Technical Support125 Document ("TSD") for assuming that heat rate improvements can be attained is based on its observations that there are differences "in operatin g 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 maintenanc e 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 contrad icted 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, cool ing systems, geographic location and ambient conditions, load generation flexibility requirements, and plant components.

Commenter s stated that EPA's data and conclusions do not match. Commenters stated that EPA makes several unfounded assumptions abou t 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.

Commenter s 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 qua lity variations in moisture and ash."

Commenter s 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, cooli ng 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.

Commenter s 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 de viations 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, skew ing the results to a higher percentage value reduction.

Commenter s 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 b etween power plants that affect the efficiency of boilers, the heat and the performance of the plant as a whole. Commenters stated that b est practices cannot make boilers perform beyond their capabilities.126 Commenter s stated that EPA's assumed levels o f sustainable heat rate improvement fail to consider critical issues related to unit design, load, cycling, and degradation.

Commenter s stated that in its assumption, EPA has failed to recognize the causes of variability in heat rate efficiency that a re 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 hu midity 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 t hese are among numerous factors that make a 6% heat rate improvement infeasible.

Commenter s 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 fut ure 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 uni ts, 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 b lending. Commenters stated that i t 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.

Commenter s 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 i n 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 a ssess differences in variability based on these factors or control for these factors in its achievability analysis. Commenters stated that i n essence, EPA has failed to prepare the necessary background information for the Proposal, and has failed to demons trate 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.127 Commenter s stated that EPA's variability analys is 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 faile d 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 tha t 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 tim e, and therefore will not maintain peak efficiency improvement levels on a long

- term basis.

Commenter s 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 p inpoint 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 O hio, 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. Com menters 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, ex amine 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

r ate 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 1.128 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 bui lding 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 pub lic comments under this c omment :

Commenter s 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.

Commenter s 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 stat ed within the rule.

Commenter s asked what peer

- review th e WEPCO two

- phase efficiency program study went through

.
Commenter s 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
p ossible by identifying two categories of actions that EPA claims utilities can use to cost

effectively improve the efficiency of their generating units, namely (i) operating and maintenance ("O&M") "best practices" and (ii) capital projects.

Commenters sta ted 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 f ailed 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 asserte d that EPA’s proposed 6% heat rate improvement is not feasible, achievable, sustainable, and/or a dequately d emonstrated

. 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 achi eved

— 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, a s 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 will129 vary. The final CPP provides states the flexibility to develop plans with emission sta ndards 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, i f 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 potentia l. 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 foll owing are summaries of the specific public comments under this c omment :

Commenter s supported the use of heat rate efficiency improvement projects at existing coal

- fired EG U s (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 the ir 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 pr oposed 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 i mprovement 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 S argent & L undy (S&L) Report, the commenter s ’ 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 commenter s ’ Nine Unit Study, EPA has presented no valid study or data to justify any HRI goal for coal

- fired EGUs. Commenters stated that t he 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 mus t withdraw the HRI requirements for Building Block 1 because they are not supported by the record.

Commenter s describe d 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 at130 existing coal

- fired EGUs under building block 1. Commenters stated that t he 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.

Commenter s 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 t herefore, 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 i t 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.

Commenter s stated that because EPA failed t o 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 targ ets 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.

Commenter s 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 Reg ion 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. Co mmenters 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 w ould have difficulty in further improving their heat rate to the stated 6% goal.

Commenter s 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 attai nable 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 f urther, 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.131 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.

Commenter s stated that they commissioned a study, also conducted by S&L, rela tive 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.

Commenter s expressed concerns with m eeting Kentucky's State

- Specific Goal . Commenters stated that t he 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

o ne 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 t he 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.

Commenter s stated that improving the existing U.S. coal fleet's average heat rate by 6 percent may be difficult to achieve. Commenters stated that p ossible 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 i f 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 t his can result in some coal

- fired power plants retiring earlier than anticipated, which creates additional uncertainty in futur e generation resources.

Commenter s 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

- wid e 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 fleet

wide HRI that could result from both O&M "best practices" and equipment upgrades.

Commenter s stated that they do not agree that a 6% average heat rate improvement is feasible for all coal units. Commenters stated that m any utilities have already retired t heir 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 allo wed 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
t hose other factors should include th e adverse impacts that result from other building block132 activities that States may choose. Commenters stated that t he emission guidelines should be adjustable based on the states' analysis of achievability of Building Block 1.

Commenter s 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 flawe d. 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.

Commenter s stated that at the ir 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 current ly 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 ex tent to which such improvements have already been implemented and therefore are reflected in current plant efficiency values

Commenter s stated that as a boiler and air quality control system supplier, they ha ve participated in numerous plant retrofits a nd 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 experi ence 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 o f any significant nature.

Commenter s 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 Utilities133 Regulatory Commission opines that facilities in Indiana can only obtain heat rates improvements of 1

- 3%, far short of the 6% proposed by EPA

Commenter s stated that 6 percent heat rate imp rovement 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

.
Commenter s stated that EPA's proposed six percent heat rate improvement is simply not feasible, sustainable, or a dequately d emonstrated, and that EPA ignores industry practice and factors that negatively affect heat rate, misinterprets an expert report on the subje ct, 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.

Commenter s stated that they are concerned the analysis EPA use d 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 st udy the value allocated to set this goal and consider a revised Block #1 goal.

Commenter s stated that they ha ve 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. Comm enters 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 M easures technical document that "coal

- fired units are designed to operate mo st 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 substant ial 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 al ready 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 realist ic 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.

Commenter s 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 o perators of these facilities

. Commenters stated that taking responses received into account, the y believe a statewide heat rate improvement of 2134 percent is the best that could be achieved and with regard to North Dakota, the y believe this information is su perior 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.

Commenter s 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 d egraded 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 Wisco nsin'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 ” ) reveal s 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% improvemen t 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 p otential to improve Wisconsin's coal

- fired fleet heat rate.

Commenter s 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 coal

fired 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. Co mmenters 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.

Commenter s 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 EPA135 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 directi on, 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.

Commenter s 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

- re ducing 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

. Commenter s stated that most of the straightforward and
cost

- effective measures to improve efficiency at power plants have already been implemented.

Commenter s 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 i s 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 und ertaken 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 gen erating efficiency of facilities.

Commenter s 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 improve ments 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.

Commenter s state d 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 pos sible in order to minimize costs for their customers.

Commenter s 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 utili ties 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.

Commenter s stat ed 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 bee n accomplished by EGUs previously and they have done the steam turbine replacements and other136 heat

- rate improvement projects. Commenters stated that improvements that are remaining are those projects that are not economically justifiable.

Commenter s st ated 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.

Commenter s 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 improvement s will be in the 1 percent to 2 percent range, at most.

Commenter s 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 cost

effective heat rate efficiency in its units possible. Commente rs 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 f raction of the proposed 6%, and that is assuming a best

- case scenario.

Commenter s 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 improveme nt 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 st rongly urged EPA to reconsider the 6 percent heat improvement rate requirement.

Commenter s stated that based on the ir 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.

Commenter s stated that reducing carbon intensity of coal

- fired generation through heat r ate 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 inte nsity 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 tha t 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 co sts to customers, meet growing demand and maximize the dispatch of these units in137 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 s tates to demonstrate the investments that have directly resulted in power plant efficiencies and to include this percentage in their compliance plans.

Commenter s stated that EPA does not justify the assumptions that 6% heat rate improvements are feasib le in the administrative record.

Commenter s 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 be ing more reasonable in light of the above flaws in EPA's analysis.

Commenter s 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 th e 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.

Commenter s stated that Heat Rate Improvement is the only building block appropriate to be includ ed 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 determinati on 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 CO 2 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 engag ement 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.

Commenter s stated that IPM projects substantial HRIs at those coal

- fired power plants remaining operational in 2025. Commenters stated that these HRIs rep resent 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 t he 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 2025.138 Commenter s 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.

Commenter s 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 Uta h 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 th is 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 imp rovements could make towards meeting Utah's 2030 emissions is small. Commenters stated that i f 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 reductio ns would total 19 lbs/MWH reducing Utah's compliance gap to 372 lbs/MWH.

Commenter s 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.

Commenter s 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 eff iciency 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.

Commenter s st ated 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 fr om 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 "bes t 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.139 Commenter s 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 a nd practices are significantly lower. Commenters stated that for example, one of their member s 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.

Commenter s 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 estim ate. Commenters stated that t hese plants cannot achieve the additional six percent heat rate improvement that EPA is proposing. Commenters stated that w hile 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 f or example, frequent turbine overhauls are not practical or economical, because these procedures require the unit to be out of service for an extended period o f time.

Commenter s 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 c ompleted all economically feasible unit upgrades and improvements. Commenters stated that f urthermore, 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.

Commenter s stated that the utility industry has already performed many of the plant efficiency improvements included in the CPP's justification and c annot 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 he at rate improvement between 0 .05%

- 0 .68% and therefore they recommended modifying the heat rate improvement target in building block 1 between1%

- 2%.

Commenter s stated that EPA has proposed a 6% increase in fossil fuel efficiency based on a national ass essment of the capabilities of the industry to improve plant efficiency (~2%) and to140 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 re duction 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.

Commenter s 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.

Commenter s 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% improve ment 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.

Commenter s 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 lit tle 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 c omme nters believe d 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.

Comment er s 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 upgrad es 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 improve ments beyond current heat rates would be extremely costly

Commenter s 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
t hese units for 38 years

.141 Commenter s 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.

Commenter s 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.

Commenter s stated that EPA's proposed Building Block #1 ("BB1") is unreasonable be cause 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 throu gh 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.

Commenter s stated that EPA's selection of a 6% HRI is arbitrary and fails to pr ovide 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 gen eration. 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.

Commenter s 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 th at 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. Commenter s ' internal analys is 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 l ess than 2 percent, along with an expedited NSR permitting process.

Commenter s 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 guideli nes for building block 1.142 Commenter s 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 Blo ck 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.

Commenter s expect ed that generators will not m ove 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, orde r materials, do required engineering, and install the plant improvements, Commenters believed that the early reductions sought by Building Block 1 likely cannot be achieved.

Commenter s stated that the 6% emission rate reduction goal

- setting for coal un its is applied everywhere, but is not achievable at most units

Commenter s 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 technolo gy" 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 impro vements 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 improveme nts 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.

Commenter s stated that EPA's methodology of determining 6 per cent HRI is flawed. Commenters briefly described EPA's methodologies for HRIs

.
Commenter s stated that EPA overestimated the 6 percent heat rate improvement and a case

- by

case 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").

Commenter s stated that EPA should recalculate emission rate goals, applying technologically feasible and demonstrated heat ra te 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.

Commenter s 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 not143 possible for their units and at best, the overall heat rate impro vement 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 i nitial 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."

Commenter s stated that EP A'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 i ndeed, their unit

- specific analysis shows that such a drastic reduction in hea t rate from existing units simply is not feasible or achievable at Texas EGUs. Commenters stated that n either is EPA's "alternative" of a 4% total improvement.

Commenter s 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 long

term, 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%.

Commenter s 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 "e quipment upgrades " and stated this claim is unfounded.

Commenter s 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 cou nting each efficiency improvement as additive. Commenters stated that EPA's assumptions are inaccurate. Commenters stated that a chievable heat rate targets should be established by the states based upon unit specific criteria and encompass or credit prior efficiency improvements.

Commenter s 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. Commen ters 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 ava ilable 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 m ay 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.

Commenter s urged EPA to reconsi der 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 again144 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 commenter s ' power plant or the rights and obligations arising under their PPA with PREPA.

Commenter s 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 unde rstanding that such an ambitious goal is not even remotely achievable across the entire fleet of affected units in Kansas.

Commenter s stated that the assumption that a 6 percent efficiency improvement is possible with all existing units is not realisti c for their plant.

Commenter s 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

.
Commenter s stated that the y 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 ex ternal 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 experti se 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 s pecific 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 st ated 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 ow n 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 propo sal. 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.

Commenter s 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 rate145 variability and implementation of equipment upgrades at coal

- fired EGUs. [ 79 Fed. Reg. a t 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.

Commenter s 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

- f ired 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 requiremen ts; 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 improve ment 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 sou rce 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 e fficiency 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 ha ve 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 pha se 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 st ate'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 of146 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.

Commenter s stated that for Building Block 1, EPA prop osed 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 t he 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. Commenter s stated that i ndeed, 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 proj ects 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 Coal

Fired Power Plants, dated April 17, 2001, in the 1990s they undertook several projects whi ch 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 o f 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 ef forts, 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 project s. 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 achi eve 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 th at 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 than147 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.

Commenter s 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
pra ctices (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.

Commenter s stated that, with regards to proposing six percent (6%) average heat rate improvement for a ll existing coal

- fired steam generating units, they support OPC comments regarding concerns for the viability of Building Block 1. Commenters stated that b ased on third

party, 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..."

Commenter s stated that EPA fails to adequately justify or disclose its ass umptions 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 impro vement 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 i mproving 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 im prove their performance by six percent ignores the fact that many units have already completed all economically feasible unit upgrades and improvements.148 Commenter s stated support for industry comments indicating that the 6 percent coal unit heat
rate t arget is not adequately justified, with considerable variation among units and difficulty for some units to improve heat rate.

Commenter s stated that Building Block One is the first step in determining the rate

- based goals. Commenters stated that the E PA assumes that, by improving the heat rate efficiencies of coal

fired 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 h as 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.

Commenter s 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 co st

- 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.

Commenter s 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 stat ed 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 Reduct ions, 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 im provements.

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 ha ve 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 coal

fueled 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.149 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 coal

fueled 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.

Commenter s 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 t he efficiency ga ins 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

- han ging 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.

Commenter s s tated 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 especi ally 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 switc hing, 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.

Commenter s stated that EPA's assumptions of achievable HRI are based on its false interpretations of the Sargent & L undy 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.

Commenter s 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 p ower 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 buildi ng blocks will hurt coal plants

- revenue, they find it very150 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
expen ditures necessary to extend the plant lifetime. Commenters stated that t o 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 block s are in place.

Commenter s 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 regulato ry 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 pr ogram 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 maintenance151 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 consistentl y 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 pr oof that this building block is unrealistic.

Commenter s 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.

Commenter s stated that under no circumstanc e 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.

Commenter s stated that the Proposed Rule asserts that a 6 percent improvement was possible by ident ifying two categories of actions that EPA claims utilities nationwide can use to cost

effectively improve the efficiency of their generating units, namely (i) operating and maintenance (O&M) "best practices" and (ii) capital projects. Commenters stated tha t 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.

Commenter s stated that assumptions by the EPA in its BSER building blocks have been major topics of discussion within the Energy Coalition. Commenters stated that the y anticipate that other stakeholder members will provide the EPA with t he technical details related to the feasibility of the building blocks, however, the y 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 coal

fired 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 severa l utility stakeholders have also stated that without significant physical plant modification it would be impossible to achieve this improved rate.

Commenter s stated that in calculating a state's emission rate goal, EPA assumes that, in aggregate, the c oal

- 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 hour ly 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.152 Commenter s 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 potenti al 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 varie ty 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 penetrat ion 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 t o 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 fo r 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

recomm ends that EPA use a consistent approach for net heat rate estimation and accounting through the proposed rule ."

Commenter s stated that EPA requested comment on all aspects of their analyses and findings related to heat rate improvements. Commenters stat ed that after numerous consultations with stakeholders, including the KCC and utility representatives, they conclude d 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

m ay 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 the se 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 he at 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 Reducti on (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 wo uld 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 reso urces. EPA's proposal is aimed at reducing utilization of fossil

- fuel fired EGUs, particularly coal

- fired units. Increased re

dispatch to renewable energy providers, inherently variable resources, will result in coal

- fired units cycling up and down and run ning at minimum loads for which they were not designed. This will have an adverse effect on heat rate.

Commenter s stated that an improvement in heat rate is a good policy and should be encouraged in all types of energy production, however, EPA's analys is 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.

Commenter s 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 be en 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 perform154 maintenance activities. Commenters stated that thes e 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 r ate 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 ha ve 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.

Commenter s stated that numerous uncontrollable factors impact the efficiency of a coal

- fired fa cility 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 im pact of these factors in its suggestion that a further heat rate improvement of 6 percent is achievable , and the commenter s 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 the ir coal

- fired units are retired before 2018 as per EPA's Option 1, the capital investment associated with such improvements would become stranded investment.

Commenter s stated that one Io wa 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 ra te 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 improveme nt 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.

Commenter s 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 go od 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 sta ted 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.

Commenter s stated that even if permissible, it is no t 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 operatin g and maintenance best practices. Commenters stated that EPA presumes that155 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 ill ogic al and unlikely.

Co mmenters 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, w ith respect to the supplemental proposal for affected power plants in Indian Country and U.S. territories , a 6% HRI is not feasible, sustainable, or

a dequately d emonstrated

. 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 ac tual 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) tha t 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 c omment :

Commenter s 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, i ts 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 part icular 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 heat

rate 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

Commenter s 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 improvement156 requirement for building block 1 taking into consideration unit

- specific factors at NGS and FCPP.

Commenter s 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.

Commenter s 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 Colorad o. 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 rate s 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 C olorado's coal generation resources.

Commenter s 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 bee n 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 opportuniti es 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 abou t 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 E PA 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 approa ch 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 c omment :

Commenter s 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 suggesti on of 10%157 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 summar ies of the specific public comments under this c omment :

Commenter s 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 e missions 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 c omment:

Commenter s stated that greater reductions than those proposed by the EPA are possible through the application of the best system of emission reduction. C ommenter s 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 l ow cost per ton of carbon dioxide.

Commenter s 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 improve ments 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. Commenter s 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 "reasona ble 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 effi ciency and finding that "there is headroom for efficiency improvements among all plants including those that currently158 operate at below average, average, and above average efficiency levels." Commenters stated that, in addition, consultations also ident ified 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 conservativ e 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. Com menter s 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.

Commenter s 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 improveme nts 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
equ ipment 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 me asures 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 no t 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 r equiring efficiency improvements through best maintenanc e 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

ea ch 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% h eat rate improvement is adequately demonstrated based on better O&M practices alone and further, the Sierra Club comments show that plant upgrades159 can reduce emission rates by an additional 4%. Commenters stated that these comments support and amplify the r esult 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 t o be used during the rulemaking period, and EPA must ensure that they are used in the most efficient and least

- polluting manner possible.

Commenter s stated that EPA should encourage states to require individual EGUs to improve their heat rates beyond t he 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%

r ate 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 an alysis 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 perce nt to just 2 percent. Commenter s 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.

Commenter s stated that EPA should encourage states to require individual EGUs to improve their heat rates beyond th e 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%

ra te improvement attributable to equipment upgrades. Commenters stated that a s such, the y 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.

Commenter s 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 ind ependent 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 i ndeed , the flexibility afforded b y 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.

Commenter s 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 timefra me, 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 pathway s, which may160 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 comput ations. Commenters stated that the 6% HRI assumption should be retained in the final CPP.

Commenter s 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 me et 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 cl eanup 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.

Commenter s believed that based on their assessment of the current fleet, and with currently available technologies and products (including those reasonably anticipated):

• Commenters stated t hat 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 improveme nt 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 co st 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 red uced 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.

Commenter s believed greater overall carbon emission reduc tions 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,161 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 imp rovement 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 t urbine 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 Monticel lo 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 wi thin 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 s tate'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 co ntrols, 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 cleani ng, 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.

Commenter s 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 the y strongly believe that inv estments 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, the y also recognize that transitioning from coal to natural gas is a compli ance pathway that will be pursued. Commenters stated that moreover, the y 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 mer cury, NOx, SOx, and particulates

.
Commenter s 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,162 the y recomme nd 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.

Commenter s stated that the Proposal essentially requires that any coal plants that will continu e 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 c ertainly not be enough to eliminate the political objections from states with substantial coal production and use. Commenters stated that it is a good start.

Commenter s recommended that EPA modify Building Block 1 by increasing to 10%, the average

amou nt of heat rate improvements that should be achievable by individual EGUs.

Commenter s stated that based on the ir 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.

Commenter s support ed the 6 percent coal fleet heat rate improvement assumption and recommend that it be maintained.

Commenter s stated that all the goals that EPA is looking for are very achievable. Commenters believe d they can be even better.

Commenter s 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.

Commenter s stated that while EPA data shows that th e 6% improvement rate is a moderate assumption compared to reductions that have already been demonstrated, a few other
comment er s argue d 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. Comme nters 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.163 Commenter s stated that EPA assumes that coa l 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

- benefi ts 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.

Commenter s 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 ana lysis 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.

Commenter s stated that the draft rule 's Bui lding 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 gr eater than 6 percent.

Commenter s 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 o f 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 tha t 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 uti lization 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.164 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 f or 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 strin gent 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

- w hich 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 re sults 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. Comment ers 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 state d that for example, investments such as major overhaul165 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.

Commente r s 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 th at 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 bloc k 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 conside ration 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 considerin g 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 compl iance 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 particula r 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

- firi ng 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 world166 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 p ublic comments under this comment:

Commenter s stated that excessive carbon dioxide emissions compromise the health and well

being 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 Bonan za 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 av erage, 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 t hat 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.

Commenter s 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 emissio ns 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 the y 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 determin ing the HRI component of the BSER.167 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 E PA 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:

Commenter s stated that the Proposal underestimates emissions reductions achievable through HRI at Coal

- Fired EGUs, and should i nstead require poorer

- performing units to meet emi ssions 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 e missions) 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% improv ement 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
t he 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 p oorer

- 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 si x 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 C O2 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 t his amounts to a ful l 41 million fewer tons of CO2 emissions than under the
commenter s ’ proposed approach

.168 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 wha t could be achieved without anticipating any improvement in the top performing sources. Commenters stated that the commenter s ’ analysis is based on annualized data, and thus does not capture heat rate improvements that can be achieved at top performing sou rces 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 Na tional 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% f or 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 woul d 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, stat es 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 co st, 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 C ement 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 underestimat es 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 poorer

performing sources approach the levels of emi ssions reduction demonstrated by better

performing 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 t o 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 anal ysis 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 th at 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 pla nts 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 uni t'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 emis sions 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 best

performing, 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 impro ved 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 ca rbon 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 achi evable 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.

Comm enters 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 va st 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 demo nstrate 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.170 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 procedur es, 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 penaliz e 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 improvem ents 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). Comme nters 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 rat es 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 c omparable 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 co al

- 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 capaci ty 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 t he 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 fact ors 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 Unit171 Net Generation Time Series File for years 2009 thro ugh 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 b y 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 C arbon 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 val ues. ((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.

Commenter s 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 ren dering 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 calculati ng 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. C ommenters 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 the y recognize that a unit

- by

- unit analysis would be a significant undertaking for EPA and require the commitment of significant resources and the commenter s recommend ed 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 a nalysis 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 or172 another number based on the median of the heat rate data underlying EPA's calculation of the

n ational 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 feasibilit y 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

.
Commenter s 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 indiv idual 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 do es 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 wh ich EGUs have implemented (specific) HRIs, or which HRIs have deteriorated over time due to lack of ongoing maintenance, the commenter s chose to use a generalized approach to assess the technical potential, utilizing a three

- stage process.

Fleet

- wide Asses sment 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 fle et

- 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 impleme nted 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 eff iciency 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 that173 t heir 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

a ssumed 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 cla ss 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 implement ed ~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 th at 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 reporte d 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 rep resents 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 h ave 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 v ariation 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 potent ial for some plants that are closer to the174 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 he at 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 2 013 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 f or each coal

fired 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 he at 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 201 3 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 like ly 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) con tains a summary of the fleet

- wide heat rates before and after the technical potential analysis.

Commenter s stated that an implied assumption made by EPA is that power plant owners are not sufficiently motivated to utilize "best practices" to reduce hea t 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 alrea dy 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 fact ors 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 rulema king 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 Commenter s state d 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 capri cious 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 eff iciencies. 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 Bl ock 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 recomm endations 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

Commenter s stated that heat rate improvements can be cost

- effective ways to redu ce 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 a bout 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 practic e 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.

Commenter s stated that EPA established the Block 1 generating unit efficie ncy 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. Comment ers 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 be176 compelling units owned or operated by different utilities to outlay additional funds to compensate for EPA BSER cost effectiveness or feasibility assessment errors.

Commenter s 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 tec hnical 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 implem ented 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 imp rovements 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 suppor t 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.

Commenter s 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 optimi zing 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 b est 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

- fuele d 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 e fficiency improvements were available for the least efficient units (i.e. 3%

- 4%), and lower efficiency improvements were available for the most177 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

.
Commenter s proposed a new methodology and time period for determining BSER for Building Block 1. Commenters stated that t his 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 CO 2 rate. 4. Allow a state to tak e 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)

Commenter s 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.

Commenter s stated that though they do not operate coal

- fired steam EGUs, they recognize the importance of these units to maintain system reliability and their contrib ution 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 s uggested modifications include an incremental approach stipula ting 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 und ergone 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 f or local reliability needs.178 Commenter s recommended reevaluating this 6% heat rate reduction potential on a smokestack

by

- 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.

Commenter s stated that the ir 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, E PA 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.

Commenter s stated that they do not agree that a 6% average heat rate improvement is feasible for all coal units and that many utilities have al ready 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 sh ould 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.

Commenter s 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 defaul t heat rate improvement applied through Building Block 1.

Commenter s 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.

Commenter s 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 h owever, 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 a dding 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 a s 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.179 Commenter s stated that they would like to propose the following recommendations to the EPA as it considers all o f 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 i n the heat rating assumptions formulated in building block 1.

Commenter s 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 pr ojects 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 a t 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 o f 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

co mplicated 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 na meplate output be specifically exempted from inclusion in the Building Block #1 calculations or alternatively, the Rule could exempt all units from entities with portfolio capaciti es less than 1,000 MW.

Commenter s 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.

Commenter s 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 unit

specific designs. Commenters stated that before U.S. EPA sets an efficiency goal for coal

- fired units under Building Block 1 or state CO2 targets, Indi ana recommends U.S. EPA issue an information collection request (ICR) to all fossil

- fuel fired EGUs and Load Serving Ent ities (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.180 • If the coal

- fired EGU uses some of its fuel to supply steam to other customers.

• If the c oal

- 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 purch ased 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 CO 2 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 Indi ana 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.

Commen ter s recommend ed 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 d emonstrating 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.

Commenter s 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 bas is to determine the heat rate improvement that is181 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 wha t 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. Commenter s 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.

Commenter s stated that under the Acid Rain Pr ogram, 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 perce nt 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 pr iority, 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 regul ated 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, al ong 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 adop ted 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 sai d EPA has taken a simplistic "one size fits all" approach to a complicated case

by

- case engineering analysis.

Commenters stated EPA should adopt a bottom

- u p 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 dat e 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 differen t 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" a nd therefore have less they can reasonably achieve when compared to those that have done little.182 Commenters stated that forcing units to operate at sub

- optimal levels and shut down for pe riods 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 ESP S Guidelines came into place. Commenters continued that EPA's proposal to curtail or cease emissions from existing plants should be incremental, as o pposed to t he proposed method

.

Comment 10 : Applicable to the supplemental proposal for Tribal and Territor ial

- Alternative approaches to determin ing 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 comment s. 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 summ aries of the specific public comments under this comment:

Commenter s 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 ca rbon 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 practice s" 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, s ee 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:

Commenter s stated that "the utilities may confuse a relative increase in efficiency with an absolute increase in efficiency". Commenters provided the example th at 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 requir es only a relative 6% improvement and an absolute improvement of slightly over 2%. Commenters stated Associating Building Block 1 with an183 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".

Commenter s 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 e mission 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 un der 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. A dditionally, 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:

Commenter s stated that EPA's building block one would require a significant improvement in the effic iency of coal

- fired electric generating units by requiring those units, on average, to reduce their heat rate by 6 percent

. A s 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.

Commenter s 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 co nstrained 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.184 Commenter s 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 c apacity 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 inherentl y 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 dif ficult 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 reconst ruct 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 u nits 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 choosi ng 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 complian ce 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:

Commenter s 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 conclude d that EPA employs purely arbitrary assumptions r egarding 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.

Commenter s stated that after the review of the thirteen S&L measures, C ommenters agree d 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 urge d 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's185 heavy reliance on its existing datasets

- the 61,848,580 hourly records for 884 EGUs

- seems to have di stracted 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.

Commenter s 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 become s 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. Commen ters 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 w hich 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 q uality. 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.

Commenter s stated concerns about the accuracy of data used in studies EPA relied upon to make assumptions across a port folio of affected coal

- fired units at the national level.

Commenter s 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

ca use 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 i n 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 improvement186 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 sup porting the final CPP

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

Commenter s 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. Commente rs 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 CO 2 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 CO 2 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 Propo sed 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/MWh

should be included when calc ulating Alaska's 2012 baseline and targets if the Proposed Rule is applied to Alaska.

Commenter s 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 t hat 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 repor ted 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 d atabase fuel consumption values, which are reported for purposes of compliance and undergo a quality assurance and certification process.

Commenter s stated that EPA's data set is inappropriate, as it includes units that are not among those that would b e 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 v ariability in187 hourly heat input or gross heat rate at units that will not be subject to the Propose d Rule is not indicative of an opportunity for heat rate improvement at coal

- fired EGUs that would be subject to the Proposed Rule

.
Commenter s 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 ha ve calculated the annual heat rate for Brame Energy Center Unit 2 over the years 2002

- 2012 using measured fuel input and measured g enerated electricity (gross).

Commenters stated that none of the changes in heat rate from one year to the next involve a chang e 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 lev el, 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.

Commenter s sta ted 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 ite m 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 a s 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 s pecifically, the EPA evaluated the consistency with which individual EGUs maintained their hourly heat rates over time. 79 Fed. Reg. at p. 34,860.188 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, doc ket 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 ra te 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 fa ctor 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 /MW h, 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 i nput 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, improv ing 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 substa ntially 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 var iability 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 tha t 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 25th189 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 p oint 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 i f the analysis is performed using distribution and varia bility 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, whi ch 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 stat ed 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 st ated 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 as sumption 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 s tep 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 fo ur.

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 par t 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. Commenters190 stated that measurement error in either or bot h 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 electrica l 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 ga s 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 e ach 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 appr oximately 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. Commente rs 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 prop osed 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 re porting of CEMS stack gas volumetric flow data.... 40 CFR Part 75 specifies that these alternative methodologies are optional. Therefore,191 there may be inconsistencies between emissions or heat input values when a unit changes the reference method used duri ng 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 Reportin g 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.

Com menters 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 inferen ce 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 EPA

HQOAR

- 2013

- 0602

- 17180, "GHG Abate ment 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 ha ving 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 opportuniti es 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 a t 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. C ommenters 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 f or 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 eliminate d 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 anal ysis, 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 l oad 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, base d 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 E PA

HQ

- 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 percen t, 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, caus es an increase in heat rate which can be reversed by switching to a low

moisture 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 a t 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 imp roving 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 S tate 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 Commenter s stated that the s econd 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 CO 2 reported data. Commenters stated that it is interesting to no te that RPS

- 2, a unit that EPA' s IPM model has desig nated for retirement, was one of only sixteen units selected in an attempt to justify a 6% reduction target for heat rate and CO 2 emissions in Building Block 1 of the proposed limit on CO 2 emissions. Commenters stated that whil e 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 CO 2 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 o f what regional populations of EGUs are capable of achieving on average.

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

Commenter s stated that the CPP should include in its evaluation of heat rate improvements the variab ility 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 t he 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 f low 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

.
Commenter s 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:194 • Continuous Emissions Monitoring Systems (CEMS) Flow monitor changes/upgrades. Allowable switching between redundant monitors and acceptable calibration r anges 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 emissi on 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 recali bration 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 det ermine 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 improvemen t at coal

- fired power plants.

Commenter s stated that i n 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 h owever, i n 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 t he actual heat rates did not improve and that r ather, a more accurate assessment of air flow through the stack caused the units to report an apparent improved heat rate.

Commente r s 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 hea t 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 me asures to partially counteract the heat rate penalty resulting from concurrently installing emission control technologies with parasitic loads. C ommenters stated that the changes in heat rate that EPA identified were, apparently, associated with normal var iations in the CEMS measurement/calculation of the gross heat rate from the units

. Commenters stated that t he unit owners all confirmed that there is little195 or nothing at the plants that would support the conclusion EPA reached regarding the heat rate impr ovement that EPA reached based on the emissions data alone.

Commenter s 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 analys is 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
gr oss heat rate reduction was due to a change in CEMS operation

.
Commenter s 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 sug gests 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 performa nce 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 hea t rate improvement had occurred, improvements were later offset by installation of pollution control equipment required by subsequent regulations, like CSAPR and MATS.

Commenter s 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 s ystems, 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.

Commenter s stated that EPA's heat rate ana lysis is flawed. Commenters explain ed that to maintain Continuous Emission Measurement System (CEMS) certification, a Relative Accuracy Testing Audit (RATA) must be completed periodically. Commenters stated that i f the stack flow reading differs from the r eference method by more than 10%, then the stack flow meter must be recalibrated and another RATA must be completed. Commenters stated that e ven 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 t he application of the BAF offset presents an issue concerning the accuracy of the Heat Input rate calculations. Commen ters stated that t he reported Heat Input rate could be significantly larger than the measured Heat Input rate, which could196 falsely indicate potential for improvement. Commenters stated the EPA should revise its heat rate analysis to account for this positi ve 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 f or 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 improvement s ). Commenters stated that p rorating 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 conden ser, etc.). Commenters stated that n et heat rate accounts for the auxiliary power consumption required to operate the machinery in the plant. Commenters stated that t his 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.

Commenter s 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 a ccording 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 f or two of the sixteen units, the Agency claims to have identified "equipmen t 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, contact ed 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 u se of r eference u nits t o s elect h eat r ate

r ed uction t argets" (Nov. 25, 2014) ("Cichanowicz Reference Unit Report") ]. Commenters also stated that b ased on discussions with the owners of these units, in virtually every case the EPA

calculated heat rate improvement was due to a change in stack flow moni tor 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 report ed heat rate improvements do not reflect actual changes197 in unit efficiency or reductions in unit CO2 emission rates. Commenters stated t he owners of eleven units report that all changes are due to unrelated variability in the CEMS

- based measurements. Cicha nowicz Reference Unit Report at 1. Commenters stated that s ome 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.

Commenter s 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 a dequately 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
t he 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 characteri stics, 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 i n 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 admittedl y difficult to generalize over the national inventory.

Commenter s 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 conclude d that EPA's claim that it eliminated other possible explanations for the calculated heat rate improvements in its 16 reference units is both

un substantiated, and directly contradicted by the very real sources of variability identified by the units' owners and the information they report to Part 75. Commenters assert ed 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.

Commenter s 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 heat198 rate vs. load for these units are examined despite concerns for the suitability of the CEMS data from w hich the heat rate trends are inferred.

Commenter s 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.

Commenter s 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 measurem ents 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 det ermining 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 varia bility. Commenters stated that EPA's analysis is not measuring a real change in heat rate and certainly not an improvement in heat rate.

Commenter s stated that by calculating unit

- specific heat rates using CEMS data, post

combustion controls including selective catalytic controls and flue gas desulfurization do not appear to have been considered

.
Commenter s stated that EPA should also take notice that under Part 75 (the Acid Rain Program); the accuracy reading for flow monitor is +/

- 7.5%. Commente rs stated that w ith 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

Commenter s stated that they believe that the methodology used in Block 1 to determine heat rate improvement goal assumptions is faulty. Commenters stated that i n 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 t he 40 CFR, Part 75 methodology determines heat input by multipl ying the CEMS measured stack flue

- gas flow rate, times a fuel199 specific carbon

- based factor, times the CEMS measured CO2 concentration. Commenters stated that i t is likely that most of the 900 EGUs used in the EPA Block 1 analysis began using a more
accurat e 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 f or example, their Ra whide Unit 101 began utilizing the more accurate RATA flow monitor (EPA Reference Method 2F/H) during the October 2006 RATA. Commenters stated that t he 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 state d that t he Craig EGUs began using the more accurate RATA flow monitor reference methods (EPA Method 2G/H) in 2003. Commenters stated that t he change in RATA reference methods also resulted in lower Part 75 reported stack gas flow rates and Part 75 calculat ed unit heat inputs and heat rates. Commenters stated that c onsequently, 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 measuremen ts resulting from the change in RATA reference method. Commenters stated that d epending 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%.

Com menter s noted facility specific data with regards to variability in CEMS

- derived reported gross heat rate.

Commenters report ed that in two instances

- for Colbert Units 1

- 3 and Gibson Unit 1

- EPA computed unit

- level gross heat rate from reported commo n 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 use ful 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 measur ement uncertainty.)

Commenters further list ed 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 upgrad ing 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 r ate due to retrofit of environmental controls and an increase in auxiliary power consumption; specifically, AES observed a net heat rate increase for200 Petersburg Unit 2 in 2005, following retrofit of SCR in 2004. Commenters also reported that Duke Energy in curred 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, associ ated 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, upgrade d 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 low ered 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 conducte d 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.

Commenter s 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 na tional inventory and reported a single year

over

- 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 state d 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 var iability 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 Rodemac her 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 actio n 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.201 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 Pl ant 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 pr ocedure changes than occurred with efficiency improvement projects which coincided with the FGD installation.

Commenter s 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 appear s 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 regul ations 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 C EMS 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 CEMS

based 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 resu lted 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.

Co mmenter s 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 2008202 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 imp rovement 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 t he 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,

s tack 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 u tilities generally measure generating unit performance wit h 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 tha t 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. Commente rs 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 GU HI being203 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 correspond ing 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. Commen ters 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 Co mmenters 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 abo ut 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 approxim ately 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 measur ed 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 follow ing the204 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.

Commenter s 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 investor

owned 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 t his report solicited experience from four owners and reported experience from seven units that corroborate UARG's cla ims 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 da ta 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 elaborate d 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 s e lective 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 rela tively 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 tot al 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 o wner reports the CEMS flow monitor was re

- char acterized (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 co

incident with a decrease

- this time of almost 8% and following a 4% increase in 2004, the b oiler 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 t he most significa nt 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 sta ted 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 o wner has deployed heat rate improvi ng actions on both units but external to the period evaluated.

Commenter s 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. Co mmenters 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 i n 2008, after the o wner 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 simil ar 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 d ue 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 o wner reported recharacterizing the flow monitor. Commenters stated that the o wner 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 signi ficant CEMS

reported 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 two206 largest changes in reported gross heat rate all coin cided with work on CEMS equipment or the flow monitor

.
Commenter s 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

o wner 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 boi ler 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

a nd 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. Co mmenters 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 unchang ed 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 fo r 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 e ventually gross heat rate increases so that by 2012 the fuel

- derived values exceed those determined by CEMS.

Commenter s stated that Seminole Electric Units 1 and 2 exhibit highly variable C EMS

- 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 o wner 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 mo nitor were implemented in 2003 and identified by the Owner as another key source of gross heat rate variation. Commenters stated that Seminole implemented207 several actions to lower heat rate

- in 2006 low NOx burners were retrofit, and at the same time

meas urement 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 20 10 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 E PA 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.

Commen ters 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 t he change in g ross heat rate using CAMS data is either

over

- reported or not recognized.

Commenter s 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 config ured 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 200 5, 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 furthe r stated that Figure 9 also depicts the range of net heat rate recorded by the

o wner 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 o wner 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 H olcomb 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.

Commenter s 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 the20 8 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 o wner supplied net he at rate. Commenters stated that i n all three cases the o wner

- 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 observatio ns 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. Com menters 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 investm ents is through thermal performance monitoring.

Commenter s 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 i ndustry 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 hea t 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 EP A'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 exclusivel y to changes in CEMS reporting209 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 Un it Study on which it can rationally justify any of the proposed options for HRI across the coal

- fired EGU fleet.

Commenter s stated that EPA has also derived incorrect conclusions from the continuous emission monitoring system ("CEMS") data to support it s 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 project s, 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 cont rols. 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 yea r

- 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 suc h 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, du e to these changes to the plan, and put simply, A.S. King is now a far cleaner plant, but its heat rate is slightl y 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.

Commenter s 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") con tacted 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 recali bration 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.210 Commenter s 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 thi s 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 repres entative 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 F all 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 pr otocol 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, chan ges 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 with in 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 s ince the EPA's analysis is only (and inappropriately) relying on gross generation and h eat 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.

Commenter s stated that EPA's analysis of heat rate improvement relies on CEMS data for hourly heat input data. G HG 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 fl ue 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 Commenter s 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 improvem ents 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
st ated 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 fluc tuations 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.

Commenter s 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 changin g 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 oc curred. 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 on e 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 tra nsponders 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 da ta have evolved over the
years. Commenters stated that d ata 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 allow able Relative Accuracy Test Audit (RATA)212 flow instrument recalibration is typically less than +/

- 7.5 percent, but can be +/

- 10 percent or

more. Commenters stated that t his will factor into the variability in heat rate measurements.

Commenter s stated t hat 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.

Commenter s stated that EPA's e xplanation 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 o bservations 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 an y 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 dat a." Commenters stated that obviously, a change in reporting does nothing to actually improve heat rate or decrease CO2 emissions.

Commenter s 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 d ata 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

- on

year heat rate improvement of between 3 and 8% and that these types of impro vements 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

.
Commenter s 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 n ot be a routinely calibrated device. Commenters stated that they ha ve 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 ha ve 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 varia nce in accuracy. Commenters compared the ir annual heat input date213 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%. Commente rs 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 basi s. 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 t he 4% improvement based on fictitious best practices is an overreach by EPA and should be removed from the rule.

Commenter s 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 Utilit y 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 EP A'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 stud y 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 200 6 (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 r eview 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 accur acy 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.

Commenter s stated that with regard to EPA's study of 16 plants that appear to have demonstrated significant efficiency improvemen ts 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 e quipment replacements. Commenters stated that this result is consistent with their own214 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 a nd 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 poss ible 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.

Commenter s 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 continuo us 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 environme ntal upgrades, rather than assumptions based on an analysis of heat rates calculated using stack flow data from CEMS.

Commenter s 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 ASM E 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

o f 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 th eir 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 basi s 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 reductio ns 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 determin e 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.

Comme nter s 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. C ommenters 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 b ased 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 rep orted 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.

Commenter s 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 ba se 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.

Commente r s stated that in Building Block #1

- Coal Plant Efficiency Improvements

- the EPA proposes a 6% reduction target for heat rate and CO 2 emissions. Commenters stated that the notion of improving the efficiency of coal

- fired plants that will be asked to opera te 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 t he year

- to

- year reported gross heat rate is highly variable and characterized by large changes; the annual reductions usually coincide with changes in the sta ck 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 investments216 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 conclu de 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 over

estimated 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.

Commenter s 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 inpu t 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. Com menters 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 a llocated 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 retrofi tted 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 bet ween 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,

an d 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 rat e, 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 Clea n 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

us ed to establish BSER for Building Block 1 as this may not be the only instance where such an important technical oversight was made.

Commenter s stated that the EPA, in a Technical Support Document related to 111d regulation for which their review indi cated 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 further217 review it was determined that NPPD's Sheldon Station Unit 1 was one of those 16 EGU's. Commenters stated that th e report documents their review of EPA 's information and analysis and the findings detailed in th e 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% impro vement 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 a nnual 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, c ommenters presented another chart t hat 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 reductio n (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 CEM S

- based and GADS

based 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 rela ted 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: Com menters 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 ra nge 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 improve ment 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.218 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, 2 006 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 stat ed 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 approximat e 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 tes t 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 thro ughout 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.

Commenter s stated that finally, EPA's analysis of hourly heat rate data assumes that facility
rep orting 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, especi ally 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.

Commenter s 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 these219 units, where equipment upgrades resulted in 2

- 3% HRI, further demonstrates its faulty ap proach 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 eq uipment 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.

Commenter s stated that i n EPA's GHG Abatement Measures Technical Support Document, EPA points to large heat rate improvements via equipm ent upgrades that could be replicated on other EGUs. Commenters also stated that h owever, 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 chan ge in continuous emission monitoring system reporting methodology and not the result of an equipment or operational change to lower heat rate. Commenters stated that t he actual heat rates did not improve and that r ather, a more accurate assessment of air f low through the stack caused the units to report an apparent improved heat
rate.

Commenter s 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 syste ms (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 p rovided 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 CEMS

based gross heat rate data from any g enerating 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

co ntinued cost of compliance with other EPA regulations.

Commenter s 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 i nput 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.

Commenter s stated that EPA has proposed to entirely abandon its traditi onal 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 significantl y larger than the calibration requirements for the continuous monitors. Commenters stated that in addition, EPA's different220 data sets contain unexplained and, at times, technically incredible emission data reported by utilities. Commenters stated that by w ay 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 neit her 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. Co mmenters 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 pursu ant 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 base d 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 CO 2 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" th e 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 res ult 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 refer ence 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.

Commenter s stated that EPA should use fuel consumption data from the CAMD database to calculate real gross and net heat rates for individual EGUs.

Commenter s stated that changes in an EGU's flue gas handling system (i.e., duct work, fans, or stack) can significa ntly 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 metho ds (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 that221 therefore reference method velocity measurements are taken at the ce ntroid of several equal area segments within the cross

- section of the stack. Commenters stated that EPA's velocity reference method assumes the flow de termined 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 z ero 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 mo re 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., t he 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 chan ged.

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 h eat 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 a ssociated 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 use d to calculate state goals.

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

Commenter s stated that the use of any single year as a baseline for heat rate is not feasible or practical considering the vast array of variable s 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 meanin gful. Commenters presented a graph that shows one particular unit's average gross annual heat rate from 1999

- 2013. Commenters point ed out that operation in 2012 happened to be anomalous for this particular unit, as equipment outages and maintenance issues kept the unit out222 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 hea t 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 i t also demo nstrates why it is impractical to design, implement, and enforce heat rate limitations. Commenters stated that i n fact, a review of recent air permits for fossil fuel

- fired electric generating units nationwide revealed not a single example of a heat rate l imit.

Commenter s 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 variabi lity 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 utilit ies 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 i n 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 singl e 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 bec ause 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:

Commenter s referred to unrealistic assumptions underlying Block 1 heat rate improvements and emission goals . Commenters stated that they implemented a number of pre

- 2012 heat ra te improvement projects (collectively the High Pressure, Intermediate Pressure and Low Pressure Turbine Steam Path Modernization Projects). Commenters stated that t hese 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 t hese 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 i n total over the life of the Rawhide plant, the net heat rate has improved223 7.6%

- from 10,692 Btu/kW

- hr in 1985 to 9,884 in 2012. Commenters stated that s imilar 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 a n additional 6% improvement from the 2012 baseline is not technically possible with existing
tec hnology. Commenters stated that i n effect, their company and Colorado are being penalized for their proactive adoption of efficiency improvements. Commenters stated that t he 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.

Commenter s stated that HRI projects affect a limited number of large coal

- fired units that have, in some cases, already undertaken equipment upgrades and operational i mprovements. 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. Comment ers stated that t he 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 h igh

- cost equipment upgrades including steam turbine overhauls,
too k place at Bowen Unit 1, Scherer Unit 1 and Scherer Unit 4 as recently as 2010. Commenters stated that a ccording to EPA's GHG Abatement Measures TSD (TSD page 2

- 12, Table 2

- 2) steam turbine overhauls achieve the highest reported efficiency increases, yet G eorgia 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 Plan t 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 unl ikely.

Commenter s 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. C ommenters 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 ene rgy 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, includi ng 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 a s 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 imple ments best practices and efficiency projects across224 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. Comme nters 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 improvement s on top of such efforts is impractical, if not infeasible, and would penalize utilities for longstanding best practice programs already in place.

Commenter s 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.

Commenter s 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 s ite

- 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 G enerating Units" (79 FR 34960; June 18, 2014).

Commenter s 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

- fenc e 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 assum ed 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 po wer 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 sta ted 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 cost

effective options available to achieve the hypothetical 6% from Building Block #1 a nd 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 Commenter s stat ed that first and foremost, the plants in which they ha ve 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, t he 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 implemente d 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 th erefore, 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 Buildin g Block, and reduce these states' emissions reduction targets accordingly.

Commenter s note d that reductions may not be achievable due to EPA's basis of determination for heat rate improvements being 2012. Commenters stated that s ince those calculations w ere 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 e ach of these compli ance 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 imposs ibility and certainly not contemplated by EPA.

Commenter s 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 B uilding 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 Amere n 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 Em pire 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.

Commenter s 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 sti ll need to meet the six percent heat rate improvements to comply with the BSER for Building Block 1. Commenters stated that226 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 the ir 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 addit ional 6% HRI difficult or impossible to achieve

Commenter s 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 m any 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

.
Commenter s 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 cite d 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 m ultiple 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 heat

rate improvement.

Commenter s 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 stan dard 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 cost

effective and technically feasi ble practices. Commenters stated that a lternatively, 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 f inally, EPA should account for the impacts of i ncreased 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.

Commenter s stated that many units have already undertaken equipmen t 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 generatin g capacity that will still be in service in 2020 and beyond undertook steam turbine upgrades prior to 2012. Commenters concluded that these units227 would receive no credit for these upgrades, and have limited options for additional heat rate improvements sin ce turbine upgrades are generally the most effective heat rate improvement option available to reduce emissions.

Commenter s stated that EPA seems to assume that all coal

- fired EGUs across the country operate in a persistently degraded and inefficient s tate. 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, the ir 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 acro ss 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 Co mpany 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 proce sses 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 fe asible given their longstanding implementation of best practices and equipment upgrades.

Commenter s believed that EPA's analytical assumptions for heat rate improvement projects are not practicable and in some cases technically infeasible because effic iency 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 addit ional 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.

Commenter s sta ted that they ha ve 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, ha ve 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 imp rove heat rate at a coal

- fueled facility. Commenters stated that

o ther efficiency improvement projects, such as cooling system heat loss recovery, flue gas heat228 recovery, low

- rank coal drying, expanded use of energy efficiency equipment and combined heat

a nd 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 ("BAC T") reviews subsequent to the issuance of the GHG BACT requirements; these BACT reviews affirmed that these measures were not feasible.

Commenter s 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.

Commenter s 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 meth ods". 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 t o allow the top

performing 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 o n inadequate analysis.

Commenter s 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 improveme nts 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

e ssentially 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. Comment ers 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 net229 emission accounting m ethod used in computing state goals. Commenters stated that i nconsistent calculations cause confusion and inaccuracies.

Commenter s 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 c onsidered 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.

Commenter s stated that as th e 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. Commen ters 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 pr ior 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 st ated that the model should use data from the years around 2005 to better account for early emissions reductions that were achieved prior to 2012.

Commenter s stated that while they agree that many efficiency improvement measures have the potential to pa y 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.

Commenter s 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 competiti on 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 stat ed 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 ye ars of heat rate data. Commenters stated that these shutdowns also represent substantial reductions in CO2 emissions

.
Commenter s stated that a review of pertinent data for Units 1 and 2 at SRP's Coronado Generating Station illustrates the type of inform ation that EPA would have collected if it had230 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 St udy at Coronado Generating Station (SL

- 012487), November 13, 2014. Sargent & Lundy.

Commenter s stated that it is standard practice in the utility industry to utilize preventative maintenance and routine cleaning practices that promote and sustain effic ient 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 electrici ty, 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.

Commenter s 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 s till 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 ar e generally the most effective heat rate improvement option available to reduce emissions.

Commenter s stated that approaches are flawed, resulting in overly optimistic projections for fleet

- wide HRI that may result in state emission rate targets that a re 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 fleet

wide HRI that could result from both O&M "best pr actices" and equipment upgrades. Commenter s 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 a s EPA notes, there is an apparent trend of improving (decreasing) heat rates over time. See Abatement Measures TSD at 2

- 18. Commenters stated that o ne cause of such a decrease could be implementation of the very "best practices" measures that EPA recommends to improve heat
rates. Commenter s stated that i n 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 or231 largely achieved. Commenters stated that EPA notes that the fleet heat rate in 2 008 was three percent less (improved) than in 2002. See I d. at 2

- 29. Commenters stated t his improvement may be related to improved O&M and other efforts to decrease heat rates. Commenters stated that

m oreover, electric utilities have strong financial incentives to deploy measures that improve heat rate because of fuel savings. Commenters stated that t hese measures often provide greater reliability and fuel supply certainty as well, thus providing additi onal economic incentives. Commenters stated that t hese 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 ef fort to determine if these measures have already been implemented and to adjust the analysis accordingly.

Commenter s 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 ann ouncement 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 ene rgy

- 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 E PA's Regional Haze and MATS rules.

Commenter s 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 alread y 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 incenti ve 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 o wners 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.

Commenter s 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

.232 Commenter s 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 o ther 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 Propose d Rule would penalize them for being proactive in reducing emissions through heat rate improvements

.
Commenter s 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 th at have borne the costs of early retirements, natural gas conversions and emissions controls.

Commenter s 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.

Commenter s 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 provide d t he 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 Statio n. 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 utiliz ing 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 typ e 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.

Co mmenter s stated that EPA's assumptions are unrealistic and unachievable for most, if not all, fossil

- fueled EGUs. Commenters stated that most electric utilities

- including the ir members

- have already implemented most of the best practices and equipment up grades 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

.233 Commenter s stated that as a rural electric generation and transmission cooperative, they are constantly invest igating, 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 fi red generating facility, they ha ve 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 i mprovements when adjusting the state's CO2 emission rate nor considers whether an additional 6% on top of the previous achievements is even possible.

Commenter s 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 t hat 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 effic iency projects that EGUs can perform to achieve a 6% improvement in heat rate.

Commenter s 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 hea t

- 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 em ission rates that EPA proposes.

Commenter s 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.

Co mmenter s 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 stat es without recognition of investments firms may have recently made to improve the heat rate of existing coal

- fired fleets. Commenters stated that i n a number of states where member companies operate, investments have been made to improve the heat rate of s ome units. Commenters stated that EPA could provide a mechanism to recognize recent investments that have resulted in improved power plant efficiency. Commenters stated that t o that end, they would support a standardized process for states to demonstrate t hat owners or operators of specific, in

- state units have made recent investments that resulted in clear efficiency improvements within a timeframe defined by EPA.234 Commenters stated that i f states were to make such a public demonstration, EPA would adjust
t he assumed availability of heat rate improvements in that state.

Commenter s stated that Block 1 allows existing plants to improve their efficiency by implementing new measures. Commenters stated that t he problem arises when most plants, such as the pl ants in North Dakota, have already done all of the things EPA thinks can be done

.
Commenter s 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

- fire d 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 eco nomically.

Commenter s 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 fin ancial 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 t he FGD modifications do not apply to the type of FGDs they ha ve 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.

Commenter s stated that HRI projects would have significant impact on the older, less efficient units. Commenters stated that in the ir system, most of these units are either being retired or have been converted to natural gas and the remaining units in the system (tot al 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 aff ected coal

- fired units, they request that EPA recalculate state emission rate goals accordingly.

Commenter s 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 diffi culty improving its heat rate. Commenters believe d 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.

Commenter s sta ted 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 imp ossible.

Commenter s stated that many fossil units have already performed the proposed improvement options, making it impossible to achieve further improvements.235 Commenter s stated that many coal plants have already made investments in many of the he at rate improvements EPA relies on as incrementally available, which means they are no longer available as broadly as EPA assumes

Commenter s 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. Co mmenters 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 ot her equipment changes. Commenters urged that these factors be considered in USEPA's analysis of achievable heat rates.

Commenter s stated that cost effective early deployment of turbine generator efficiency improvements on Minnesota coal units have alre ady 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 reg ulators 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 improve ment 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 pres ervation 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 i ntegrated 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.

Commenter s further stated that i t 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 Tech nical 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 effi ciency 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.

Commenter s stated that U.S. EPA made no attempt to identify and correct fo r 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 st atistical 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 o f the coal

- fired fleet and rely on measured HRI data.236 Commenter s stated that despite having been proactive in reducing CO 2 emissions from the State's electric generating fleet, the electric cooperatives and other electricity providers in South Carolina ar e 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 l bs/MWh by 2030. Commenters stated that EPA assigned one state which has a similar CO 2 emission rate of 1,552 lbs/MWh a target reduction of just 16 percent. Commenters stated that a ssignments 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 pro posal should not place additional burdens on particular states as to other generation options due to inconsistent results when applying EPA's model.

Commenter s stated that EPA's assumption fails to consider the efforts companies have already undertaken to improve heat rate

Commenter s 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 subst antial 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.

Commenter s 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

- ra te improvement projects

.
Commenter s 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 t he efficiency.

Commenter s 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.

Commenter s 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 syste m of emission reduction.

Commenter s 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.237 Commenter s 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

Commenter s 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 up grades 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 frui t," 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.

Commenter s 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 efficient ly 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 o r would not meaningfully reduce heat rates at their EGUs.

Commenter s 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 a s 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 flee t has already applied some or many of the available [heat rate improvement] methods."

Commenter s stated that EGU operators have a financial incentive to improve heat rate at their facilities. Commenters stated that c onsidering 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 im provements 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 unrecog nized 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 coal

burning EGU fleet.

Commenter s stated that the eff iciency 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 and238 achievable efficiency gains based on the operational limitations of existing coal

- fueled power plants and take into account the efficiency improvements already implemented.

Commenter s 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 du plicated. 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 impr ovements 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.

Commenter s stated that using a national average heat r ate 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 mad e 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 thes e improvements were made before 2010 and were not considered when EPA looked at national average heat rate improvement opportunities.

Commenter s 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.

Commenter s asked how is a ta rget achievable if it i s ask ing units to duplicate reductions that ha ve already been achieved

.
Commenter s 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 an d other reports to suggest that additional improvements of 2 percent are possible. Commenters stated that by a dding the two together, EPA established Building Block 1 and its mandate of an annual 6 percent heat

- rate improvement.

Commenters stated that in p rinciple, 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
oper ating 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 t o improve heat

- rate performance have been subject to enforcement actions or threats of enforcement actions by EPA.239 Commenters stated that these challenges often take years to resolve, achieve mixed results in the courts, and leave operators reluctant to at tempt 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 improvement s, 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 mee t their targets.

Commenter s 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 efficien cy 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.

Commenter s stated that because t heir 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 l ikely 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 determinatio n to build and maintain the plant to maximize their operational efficiency.

Commenter s 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 ma kes 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 upgrad es and improvements.

Commenter s 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 stan dards 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.240 Commenter s stated that generally, they sup port 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 c osts. 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 o f 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 im provement 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.

Commenter s 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 realisti c expectation of power plant efficiency for Colorado's coal generation resources

.
Commenter s 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 ha ve 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 efficie nt than most others in the industry and with those investments already made, very little additional improvement is available.

Commenter s stated that there is nothing in the docket or the proposal that allows the commenter s 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.

Commenter s stated that E PA 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 s cenario where additional plant241 efficiencies cannot be gained and will result in the forced closure of beneficial and efficient

resources.

Commenter s stated that some U.S. utilities, including their plant , have been leaders in taking action to reduce gr eenhouse 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 st ated 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.

Commenter s stated that in addition to installing DryFiningTM at Coal Creek S tation, over the past decade commenters ha ve 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.

Commenter s stated that proactive efforts should be recognized by EPA through regulation that supports a policy to encourage early vo luntary 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 red uction 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.

Commenter s stated that EPA erroneously assumes that all coal

- fired units, in cluding 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 long

since been accomplished because every marginal improvement in the heat rate lowers fuel costs, which lowers rates.

Commenters stated that they ha ve 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 st ated 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 con cluded that improving heat rate by 6 percent may not be achievable.242 Commenter s 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 sta ted 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 proces s 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 discuss ed 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:

Commenter s 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

.
Commenter s 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 the ir facility, either in the initial design phase or through best practices already implemented at the facility. ( R eviewing 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 EP A 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 c an 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 frequent243 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.

Commenter s stated t hat 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 i ncentive 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 doe s not demonstrate that future heat rate improvements can be performed to reduce CO 2 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

- specif ic, 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 EG Us can perform to achieve a 6% improvement in heat rate.

Commenter s stated that EPA has made no effort to determine if best practice measures have already been implemented and to adjust the analysis accordingly.

Commenter s 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 tha t 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.

Commenter s stated that EPA's finding of a 2% heat impr ovement 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. Commenter s stated that for instance, EPA's TS D 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 tou ted 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 wit h 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.

Commenter s 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 coa l units are unimproved. Commenters stated that further, many utilities have already implemented ongoing heat rate improvement programs to244 capture the efficiency gains that EPA is assuming would be possible in the "best practices" portion of the Building Bl ock 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. Comment ers propose d that instead of assuming across

the

- 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. C ommenters 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 go al

- 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 C hapter 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 w hole.

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

Commenter s 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 operatio nal 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 variabili ty, cycling, and annual capacity factor, it will be difficult to monitor and measure improvements to plant heat rate on a consistent basis.

Commenter s stated that the State of Arizona cannot meet EPA's improvement ranges because it has a relatively you ng 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 E nergy Mix in the Context245 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 a bout 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 c oal 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 o lder 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 d ue to the improvements that Arizona coal

- fired units have already made, 1% improvements, at most, are realistic.

Commenter s 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 an d 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 i ndicates 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.

Commenter s 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.

Commenter s 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 Toxi cs 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% red uction even more unreasonable and unachievable.

Commenter s stated that Wygen Three in Wyoming which came on line in 2010, is a newer power plant. Commenters stated that e ven 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 reduct ion from its 2012 emission rate that just246 doesn't make sense to us. Commenters stated that EPA should exclude newer plants from bloc k one productions.

Commenter s stated that new plants that have just been built that have been built to state

- of

- the

art standards can't get 6 percent overnight.

Commenter s stated that for instance, in Louisiana, Cleco recently noted in formal comm ents 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 alr eady installed HRI measures at these plants.

Commenter s 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 tha t are already more efficient, EPA should evaluate heat rate improvement capability at individual coal

fired units.

Commenter s 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 fac ilities 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 facili ty could provide total heat rate improvements in a range of approximately 4 to 12 percent..." [ 79 Fed. Reg. at 34,359 (emphasis added) ]

.
Commenter s stated that Arizona's coal

- fired EGU fleet is the sixth youngest in the nation and as discussed in the ir 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 h eat 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 Arizo na electric customers.

Commenter s 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 member s 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 air247 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 ar e 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.

Commenter s 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 ha ve no t 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 th at they ha ve 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 o riginal 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 P uerto R ico E lectric P ower A uthority 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.

Commenter s stated that EPA's assumption that coal

- fired power plants can reduce their emissions by 6% from heat rate impr ovements 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 it s 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, im provement 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 proposed248 rule as "no cost" or "low cost" measures for b est 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 u nits, 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.

Commenter s 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 gen erating fleet already employs nearly all of the cost effective heat rate improvements that are available.

Commenter s stated that even if the EPA had calculated an appropriate fleet

- wide HRI, such an average should not be applied to all states. Commente rs 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 ach ievable 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, commi ssioned in 2006 and 2009 respectively. Commenters stated that SGS represents 42 percent of Arizona's total coal

- fired generation capacity.

Commenter s 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 the ir Unit 4 at Springerville Generatin g 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 ach ievable 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 coal

fired EGU's which commenced operation in or after 2009, these units must be excluded from coverage under the proposed regulation.

Commenter s stated that EPA has proposed and modeled into its proposal an average six percent heat rate improvement for all existing coal plants in Bu ilding 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 operation249 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 pollut ion control measures. Commenters stated that an additional six percent improvement would be exceedingly difficult to achieve.

Commenter s 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 instal led 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 the re 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 b in a nalyses are adjusted for the impact of SCR and/or FGD i nstallations on heat rate

Response 20 : See C hapter 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:

Commenter s stated that EPA's "Best Practices" analysis used for the 4% heat rate improvement calculation is flawed. Commenters stated that s everal units included in EPA's analysis installed SCRs and/or FGDs within the 2002

- 2012 time period. Commenters stated that i n 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 r eplacing a wet FGD with a dry FGD can improve heat rate, but this is a unique situation a nd not an appropriate example of a typical heat rate improvement measure. Commenters stated that s ince 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 t he "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 o f 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 section s 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:250 Commenter s stated that EPA incorrectly used gross heat rates instead of net heat rates when determining heat rate improvement potential. Commenters stated t here 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 wi th 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 n et heat rate accounts for the auxiliary power consump tion required to operate the machinery in the plant. Commenters stated
t his 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

s hould 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.

Commenter s provided a definit ion 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 therma l efficiency opportunities (heat rate improvements or "HRI") at power generation facilities utilize net heat rate measurements, not gross heat rate

, A nd 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. Commenter s stated that i t 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 use s 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 appl icable 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. Comm enters 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 assumption s 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 likel y 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 propose d 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 exclud ed 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 w hen 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 th at most coal

- fired251 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. "

Commenter s stated that given the lack of heat rate improvement p rojects 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 account ing method used in computing state goals. Commenters stated that i nconsistent calculations cause confusion and inaccuracies.

Commenter s 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 i nconsistent calculations lead to confusion and inac curacies.

Commenter s stated that 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 which leads to i nconsistencies, confusion, and possible overestimation of the heat rate improvement

- related mitigation potential. Commenters recommend ed that EPA use a consistent approach for net heat rate estimation and accounting through the proposed rule.

Commenter s 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

- unit s, which is an incorrect assumption for power plants where controls such as scrubbers have been constructed since 2012. Commenter s stated that for example, they ha ve or will have installed dry scrubbers at the following power plants: Columbia Energy Cente r, Edgewater Generating Station, Ottumwa Generating Station, and Lansing Generating Station.

Commenter s stated that EPA's analysis of heat rate improvements only considers potential for improving gross heat rates "the HRI potential on a net output basi s 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 encourage d EPA to look more carefully at opportunities to improve the efficiency of auxiliary or parasitic loads, such as pumps, fans, motors, and pollutio n 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.

Commenter s stated that the proposed rule should b e 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 that252 increase the facilities o nsite 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 a uxiliary 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
pena lizes 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 impact ful 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.

Commenter s 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.

Commenter s stated that EPA's use of gross heat rate data for estimating heat rate improvement CO2 reductions for Build ing Block 1 is inconsistent with the use of the net emission accounting used in the state goals computation. Commenters stated that t he use of gross heat rate data leads to inconsistencies and possible overestimation of the heat rate improvement

- related CO 2 reduction potential.

Commenter s 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 beyon d, will be well controlled and that these controls impose an auxiliary load that degrades the net heat rate of a unit.

Commenter s stated that, in its statistical analysis, EPA looked at gross heat rate, when what matters for the proposed rule is net he at rate.

Commenter s asked why the EPA did not use net output instead of gross output

Commenter s 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 a nd 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 b ut 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 d id 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 d uring the study period, all of North Carolina's coal units operated w ith controls for NOx, SO2 and PM.

Commenter s 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 ba sis. Commenters stated that the use of gross heat generation data for determination of HRI

related 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 the y recommend the EPA use a consistent approach for net heat rate estimation and for emissions accounting in the final rule.

Commenter s 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

.
Commenter s requested that EPA restate Building Block 1 heat rate requirement in terms of net generation instead of gross generation

.
Commenter s 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, tra nslating 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, u nit 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 he at rate improvement and related CO2 mitigation potential in Building Block 1 which may lead to inconsistencies, confusion, and possible overestimation of the mitigation potential.

Commenter s stated that the proposed unit of measurement in Building Bloc ks 1 and 2, pounds of carbon dioxide per net megawatt

- hours, is of particular concern to c ommenters 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 abl e to quantify its parasitic load now, and then predict it for the future for compliance purposes, however this is further complicated with254 the additional regulations recently finalized or proposed. Commenters stated that for instance, the recently finalize d 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

- h our 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.

Commenter s 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 th e EPA based its performance target on statistical analysis of its own data of existing coal

fired 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) loss es. 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 wo uld 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 r ate 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 transferrabl e 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 pla nts 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 impro vement 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 cont rols. 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.

Commenter s 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 S O 2 and ozone NAAQS requirements. Commenters stated that as255 noted by UARG, similar compliance measures taken by other generating unit owners that would negatively impact heat rate, and thus increase CO 2 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 gr oss 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:

Commenter s 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:

Commenter s stated that EPA did not compare units against one another nor do any sort of sub

categorization and that each unit is only compared against itself over that eleven year period, and in that respect, sub

- categorizat ion is avoided.

Commenter s 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 emitte d 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 refu se piles is diminishing as the higher quality piles have been remined and that accordingly, limestone usage to control acid gas emissions has256 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. Comm enters 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 i n 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 sho uld not be included in the BSER program used to calculate the average s tatewide 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 exi sting 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 fo r a boiler tune

- up to maintain efficiency in accordance with good engineering practice. Commenters stated that this sub

categorization 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.

Commenter s stated 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 ava ilable, 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 t hat 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 tha t 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, an d it will not do so if employed as EPA
proposes

.257 Commenter s 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, t he 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 ]

.
Commenter s 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 uni ts 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.

Commenter s 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 i ts 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 stat ed 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 u nder 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 complia nce 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 regul ation, 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 pecu liar 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 achie vable 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 desp ite 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 197 9, 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 t o 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 famil iar with its duty to subcategorize when appropriate, and it must at least examine appropriate subcategories for its proposed standards here.

Commenter s stated that all available data and experience indicate that subcategories for coal

fueled 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 f or example, EPA's utilization of a subcatego ry 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 differin g 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 devel op 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 east ern 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 (usin g 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 utiliza tion 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.

Com menters 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. Commente rs stated that EPA must recognize the differences in emissions from these three subcategories and adjust the performance standard259 accordingly. Commenters stated that as a legal matter, they believe standards for existing coal

fueled EGUs must be subcategor ized 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 ca lls 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 c onsistent 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 shou ld 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 s ubcategorization

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:

Commenter s stated that EPA did not compare units against on e 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 s tartup s and s hutdowns

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:

Commenter s 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, f uel type and quality, weather, and operating characteristics (e.g., number of startup and shutdown events and low NOx combustion). Commenters stated that260 Georgia Power's Plant Hammond Unit 3 serves as an example of the impact startup and shutdown events co uld have on a unit's emission rate referring to three startup events in 2005 compared to 46 in 2012. Commenters stated that t he 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 wi th 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 implem entation 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.

Commenter s stated that it is impo rtant 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 sta ted 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 t hat moreover, the parasitic load is a higher percent of the net output at lower loads, thereby negatively impacting efficiency calculations based on net output.

Commenter s recommended work practice standards that are periodically reviewed and implemen ted 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 o f 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 "con sistent 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.

Commenter s 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 co al

- 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 coa l

- fired power plant in question; startups could result in a shorter useful life for air quality control system components as a result of damage due261 to more exposure of acid gas condensation. Commenters stated that other operational challenges may result fo r air quality control systems due to more frequent startups and shutdowns.

Commenter s 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:

Commenter s 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 ge neration or improving demand

- side energy efficiency. Commenters stated that t herefore 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

.
Commenter s 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 contributi ng 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 o perating 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 i mpact s of capacity fac tor and ambient temp erature

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 specifi c public comments under this comment:262 Commenter s 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 proces s 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 app roach, 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 tha t 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 tempe rature condition over this eleven

- year period, EPA considers that scatter to be a sign that more consistent process control can improve heat rate

.
Commenter s stated that the statistical approach used by EPA does not consider any technical aspects of t he facility.

Commenter s 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 as sumed 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 av erage, 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 temp erature 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 st ated 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 system s, 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 w hat 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.

Commenter s 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 relativel y constant. Commenters stated that this was despite installation of advanced pollution control equipment like Flue gas desulfurization ("FGD") and263 selective catalytic reduction that is known to adversely impact heat rates. From 2009 through 2012, with lowe r 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 i s 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 d emonstrates, 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.

Commenter s 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 algo rithms 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, part

l oad 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 chapt er 2 of the GHG Mitigation Measures TSD, the economic downturn was not accompanied by a significant fleet

wide effect on heat rate.

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

Commenter s question if the correlations b etween 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) hea t 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 accepted264 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 tempera ture affect predicted heat rate. Commenters add ed 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 t emperature 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 a mbient temperature affect heat rate.

Commenter s 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 th ese 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 uni t 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, ag e, 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 requ irements. 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 "be st 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 improvem ent.

Commenter s 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 efficien cies. 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 by265 2 percent from 2008. Commenters stated th at 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 reduc ed and sub

- optimal levels which in turn will also m ake them less efficient.

Commenter s 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 operati on 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 re duced 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 re sults defy known technical relationships between heat rate, operating duty, and ambient temperature (id. at 3

- 6).

Commenter s stated that EPA's heat rate assessment analyzed gross data for 884 coal

- fired electric generating units (EGUs) during a 10

- yea r period. GHG Abatement Measures (EPA June 2014) (EPA

- HQ

- OAR

- 2013

- 0602) pg. 2

- 18. Commenters stated that t he 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 t he EPA's assessment concluded that in

state coal units can achieve up to a 4 percent rate of improvement through the use of best operational practices. Commenters stated that a n 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., e very 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 lower

capacity factors are due to the cycling of th e coal units. Commenters stated 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 w hile recognizing capacity effects in the re gression analysis, the EPA did not evaluate the effects of lower

- capacity factors resulting from the dispatching of natural gas generation before coal generation.

Commenter s stated that the EPA performed 3 regression analyses: (1) heat rate onto capac ity 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 ho urly heat rate values outside of +/

- 2.6266 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 simpl y 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 no t 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 expres sed 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 ambie nt 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 represent ing the degree to which the unit is load

following. 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 th e 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

conce rns 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, th en 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 ba sed 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 t hat 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 statisti cal 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 imp act 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 that267 the re sults 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 ad mits 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 exampl e, 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 emp irical 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.

Commenter s 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. Commente rs 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 E PA 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 e verywhere and overinflates CO2 emission reduction potentials under Building Block 1.

Commenter s 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.

Commenter s stated that to assess the impact of capacity fa ctor and ambient temperature on heat rate, EPA performed regression analyses for “each unit year.” Commenters questioned how the268 EPA select ed this methodology . Commenters also questioned wh y the EPA did not calculate a
separ ate regression for each unit, for each year from 2002 to 2012 . Commenters also questioned wh y the EPA did not have this statistical analysis peer

- reviewed

.
Commenter s stated that EPA's finding that 26 percent of the variability in heat rate could be explained by load factor and t emperature 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 state d 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.

C ommenters 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 r easonable 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 decr ease 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 a rbitrary 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 t he fleet.

Commenter s 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 a nd 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 i s precisely what EPA has done.269 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.

Commenter s stated that India na'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. Comm enters 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 appropriaten ess 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.

Commenter s 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. Comm enters 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 operatin g practices.

Commenter s 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 stat ed 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 com position 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 point ed out that differences in boiler design can account for variability of heat rate, particularly when comparing "supercritical" and "subc ritical" 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 st ated 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 su bject to frequent cycling. In addition Commenters stated that EPA oversimplified the analysis of ambient270 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.

Commenter s stated that EPA ignores a numbe r 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 ass umptions 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 an alysis 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 f or example, the type of coal used can significan tly 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 importan tly 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 c oal

- fired power plant may undergo.

Commenter s 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 gen erating 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

va riability 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 Pr oposed 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.

Commenter s summarized EPA's variability analysis . Commenters concluded that EPA's assumption ignores num erous 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 qualit y can271 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 c an 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 barometri c 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 o f 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 la rge 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 ha ve 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 t he 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 s ize 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 possibl e 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 rate s can be eliminated through the implementation of improved O&M practices.

Commenter s 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 stated272 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 well

controlled facility using "best practices" should have a very repeatable heat rate u nder any given ambient temperature or hourly average load condition is incorrect. Commenters believe d the latter explanation for the low explanatory power of temperature and load because other important factors that impact heat rate, including changes to t he 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 th ese 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 optimizati on 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, sa fety, 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 sophis ticated systems that were tailor made to optimize that plant's operations while monitoring hundreds of sensory inputs.

Commenter s stated that EPA associates heat rate variability with potential for heat rate improvement, stating "results display a wid e 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 he at 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 produc ed 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 supercritic al 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 fr om 433 MW in the first quartile to 291 MW in the fourth quartile)

. Commenters stated that th e figure shows

- without exception

- each design or operating trait exhibits a stepwise change from the first through the fourth quartile. Commenters then demonstr ate d 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 first

quartile units and that almost 2/3 of units in the fourth quartile fire bituminous coal, compared to les s 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 continue d stating that differences in boiler design

- supercritical vs. subcritical s team conditions

- are notable and could273 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 th erefore 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.

Commenter s stated that EPA based its analysis on variability in hourly heat in put, 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 th at 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 "po tential 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.

Commenter s 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 meth odologies, 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 argu ments 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 a dditional 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 f or 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

w ay 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 i t is difficult for them to reconcile that U.S. EPA has proposed HRI goals for a mature coal fleet without considering274 what projects and best

- practice measures have already taken place with the "demonstrated technology" aspect of setting BSER.

Commenter s 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 s pecifically, 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 ce rtain 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 factor s 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 o f 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 im provement 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 he at 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 tim e 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 th is 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 assu med that any variability in heat rate not associated with load and ambient temperature could be mitigated through capital investments and275 best practice operational methods without further justification. Commenters stated that it also ignores that variabili ty, 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

an y 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 progra ms, and a variety of other factors not directly attributable to equipment upgrades.

Commenter s 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. C ommenters 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 maintena nce 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

Commenter s 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 s upplemental 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:

Commenter s stated that EPA's view that a 4% improvement in heat rate is possible through no

or lo w

- cost "best practices" was based upon a statistical analysis that overlooked important sources of variability in heat rates

.

C omment 30 : Comments regarding heat rate variability and performance276 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:

Commenter s stated that EPA's inferences with respect to a causal relationship between high variability in calculated hourly g ross 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 he at 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 v ariability 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 r elationship 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 downt urn, a drop in natural gas prices which affected dispatch of coal fired

EGU s , 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 r ate was an assumption that 50 percent of the variability observed in bin data was caused by deficient O&M practices. Commenters stated that i n 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 b asis 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 fact ors, 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 va riable 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 ca pacity 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.

Commenter s stated that the analysis supporting the Proposed Rule does demonstrate that, even after attempts to control for load factor via th e 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, a s stated therein, w e 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 EGU s, 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:

Commenter s stated that wind power

- induced variable load contributed to heat rate varia bility. Commenters stated that starting in 2010, the o wner 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.

Commenter s 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.

Commenter s 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.

Commenter s summarized the EPA's use of the Sixteen Unit study as justification for the proposed 6% HRI. Comment ers 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 fuel

fired EGU heat rates, and that i n short, NRECA's Nine Uni t 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.

Comment er s 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 re main 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 t he 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 mor e 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 emiss ions rates for coal plants that continue to operate.

Commenter s 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 effic iency 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 illustrates279 that the heat rate increases by six percent as a result of the plant reduc ing 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 improveme nt opportunity associated with coal fueled generation will be offset by the reduction in efficiency associated with lower load operation.

Commenter s stated that with the incorporation of other Building Blocks, certain heat rate improvements will be los t due to increased cycling and changes in unit dispatch needs.

Commenter s 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.

Commenter s stated that Building Block 1 is not achievable on a national basis because any gains in efficiency implementing Building Block 1 will be si gnificantly 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 imp rovements 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 generati on.

Commenter s 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 re duces 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. Comment ers 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
capa city factors are reduced due to the system interactive effects from the displacement of coal

fired generation by dispatch of NGCC units, increased use of renewable power (likely an erratic280 supply), and growth in end

- use energy efficiencies as proposed unde r 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 worsen ing heat rate trends in general.

Commenter s 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 s tated 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 seve ral 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 r ates 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 t han 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 otherwise281 ensuring any presumptive HRI percentage is calculated based on the offsetting nature of buil ding blocks 2 and 3.

Commenter s stated that EPA's assessment that plant operational efficiency can be improved b y 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 increase d 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] wo rld 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 effic iency 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 plan ts 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 no t "technically feasible" and therefore cannot be a component of the final Rule.

Commenter s 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 amo unt 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 Sec tion 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 st ated 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

.
Commenter s 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. C ommenters 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 d ispatch 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 remain282 operati onal 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 wi ll 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 no t 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.

Commenter s 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.

Commenter s 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 regard ing 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 lo wer capacity

.
Commenter s stated that EPA ignores the adverse effect on heat rate that implementing the other Building Blocks will have

.
Commenter s 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 t he 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

.
Commenter s stated that a detrimental impact to the coal

- fired EGUs' heat rate is increased cyclic and part

- load ope ration 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

- dispatch able 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 heat283 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 plo t, 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

.
Commenter s 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 acknow ledges that EGUs have higher heat rates (and thus higher CO 2 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 coal

fired 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 pro posed 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 re

dispatch of generation from existing coal

- fired EGUs to existing NGCC units, whi ch 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 sign ificantly 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.

Com menter s 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 b enefits 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 impact ed 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, typical ly 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 i mprovements 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. Commenter s stated that i n 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 unit284 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, existin g 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 a n 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. Comm enters 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 gen erating 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

aver age 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, th is 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, b ut this analysis points out the fact that the building blocks must be evaluated in total, not independently. Commenters stated that i f the goal of building block 1 is to improve heat rate by 6%, a hurdle imposed by building block 2 increases this 6% to som ewhere 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 deploy ment 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 implementatio n 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 imp rovements that are realistically achievable by coal

- fired EGUs under building block 1.

Commenter s 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 change285 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.

Commenter s 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 addres s 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.

Commenter s 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 capa city, 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 propos al, 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 nec essarily significantly reduce the CF at their plant

. Commenters stated that the reduced output and resulting cycling of the ir facility would be expected to offset if not exceed any theoretical improvements in heat rate.

Commenter s 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 i n 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 loadcycl ing," as EPA projects under its proposal. Commenters stated that i ndeed, EPA's own assessment demonstrates this reality. Commenters provided a Figure showing Generic Pulverized Coal Net Heat Rate vs. Percent Load

.
Commenter s stated that Building Bloc k 1 strives to improve the thermal efficiency of each coal

fired 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 co al 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 to286 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 complian ce 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

.
Commenter s stated that a technical challenge not acc ounted 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 re

dispatch of natural gas units to 70% on a very short timetab le, 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 demo nstrate that coal

- fired units operate at an average capacity of 52%, with many of the larger units operating between 70 and 80%.

Commenter s stated that similarly, EPA's evaluation of heat rate improvements did not take into consideration the load profi le 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

s tated 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 consid eration load changes or load profile.

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]pe rating 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

ev aluation 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 ave rage 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 suf ficiently 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.287 Commenter s stated that Building block #1 incorrectly assumes that upgrade and operatio nal 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 coal

fired generators such as their plant to adopt state

- of

- the

- art technolo gies 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 3 1, 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 USE PA 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 achievi ng 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% he at 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) ]

.
Commenter s 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 increasin g by 6 percent, essentially eliminating any heat rate improvements.

Commenter s 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 implem entation 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 capaci ty. 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 t hus any heat rate improvement projects are moot.

Commenter s 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 gas288 combined cycle plants. Commenters stated that EPA's proposed building block 3 increases renewable energy but reduces demand from co al

- 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 o f 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 th e 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 operatin g 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 ra tes, 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 ele ctricity 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 gene ration due to weather.

Commenter s 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 improvem ents 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.

Commenter s 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 of289 2008, and from August through th e 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 gener ation 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 pe rformance;

• 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

- load ed unit. Commenters stated that h owever, 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.

Commenter s 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 t he 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 f urther, boiler thermal efficiency is typically penalized as the airflow is increased (e.g., higher exc ess air concentration) to maintain optimal conditions at the burner. Commenters stated that t he penalty to heat rate on a net basis can be even greater. Commenters stated that o perating 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 t here are additional impacts of part load operation. Commenters stated t hese include having to take feedwater heaters out of service, transferring "feedpump" turbine steam to higher pressure sources, etc.

Commenters stated that t he mandate to maintain minimum gas flows through equipment for safety and opera ting 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 Int ernational290 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 i n 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 d espite this concession, EPA does not consider this operating characteristic in developing its strategy. Commenters stated that t he heat rate penalties are not theoretical but actual detriments to operation incurred by power plants, particularly those equipped with state

- of

- art environmental controls.

Commenter s 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 deg rade 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 uni ts 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 th at 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 inv estment 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 impr ovement 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.

Commenter s 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. Commenters291 stated that the results show the plant heat rate penalty (gross basis) incurred at 50% load is 7% fo r 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.

Commenter s 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 Sal e 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
gene ration 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, w hen 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 bet ween 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 show s 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 schedulin g.

Commenter s 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 low er capacities with intermittent increases to meet peak demand. Commenters stated that l oad

- 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 non

lin ear 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 per cent 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. Commenters292 pointed to a table that shows the average heat rate for varying load scenarios a t 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)

.
Commenter s 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 w ithout any real

- world validation, EPA's statistical approach cannot be considered to be "adequately demonstrated." Commenters stated that from 2 015 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 t herefore are operating at design load with peak efficiencies on a nearly constant basis.

Commenter s stated that, similarly, EPA's evaluation of heat rate improvements did not take into consideration the load profile of coal

- fired units. Commenters stat ed 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 profil e

Commenter s 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 les s efficiently, which makes achievement of the Building Block #1 targets all the more unrealistic.

Commenter s stated that EPA also expressly recognizes its Proposed Rule Building Block 2

- increased natural gas generation

- will displace coal

- fueled EGU s: "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 sh ifting 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 i s 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.

Commenter s stated that heat rate improvement assumes a unit operating at capacity to calculate the benefits of reduced emissions, however, build ing 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 bu ilding blocks are implemented. Commenters stated that reductions293 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.

Commenter s stated that because the generation and sale of electrici ty 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 a s a result, achieving an increment al 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 e stimated 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 par asitic 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 propose d guidelines be based on gross output, rather than on net energy output.

Commenter s 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 th at would result from the displacement of coal

- fired generation from Building Blocks 2, 3, & 4

.
Commenter s 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. ] Commenter s 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. Commenter s stated that lower capacity factors (CF) or increased cycling increase heat rates and increase heat rate variability. Commenter s stated that in the integrated electric system, units are dispatched to respond to load and unit owners and operators, therefore, canno t control load factor to address concerns about heat rate. Commenter s 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. Commenter s 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 t he state implementation plans.

Commenter s 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 being294 implemented, they ha ve no plans to retire units 31 and 32 at this time since they ha ve already inves ted 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 renew able 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 the ir 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 ha ve 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 demon strates. Commenters stated that the benefit of these units to the community is outsized and their impact on GHG emissions is negligible.

Commenter s 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 s tated 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.

Commenter s stated in its CAA section 111(d) analysis, EPA mentions a number of heat rate improvements that are less efficient at part load. Commenters stat ed 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 stat ed 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, a nd market potential for heat rate improvements. Commenters stated that most coal

fired 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.

Commenter s 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 generation295 displaces existing coal fired generation. Commenters stated that displacing existing coal generation will reduce overall coal plant capacity factors. Commenters stated that c oal plants were designed to achieve greatest efficiency when producing high output around the clock. Commenters stated that t he goal of improving plant efficiencies while shifting away from high capacity factors is contradictory.

Commenter s 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 th at 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 possi ble due to Building Block #3 (renewable energy) and #4 (energy efficiency).

Commenter s 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 b lock 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 decr ease 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 coal

fired units in setting the efficiency improvements under building block 1.

Commenter s 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 recov er 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. Comment ers stated that the final rule needs to recognize this fact and allow for these inevitable heat rate losses caused by increased cycling.

Commenter s 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 w ithout any real

- world validation, EPA's statistical a pproach cannot be considered to be "adequately demonstrated." Commenters stated that from 2015 on, all296 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.

Commenter s 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 lo ads would therefore reduce any heat rate benefits realized from implementing operating and maintenance best practices.

Commenter s 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.

Commenter s 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 compli ance 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.

Commenter s 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 CO 2 emission rates) when operating as load

- following units and during periods of startup and shutdown. Commenters stated that likewise, in its proposed NS PS rulemaking for modified and reconstructed EGUs, the Agency recognizes that operating at 50 percent load increases the heat rate of subcritical coal

fired units by 10 percent. Commenters stated that efficiency decreases even more dramatically at lower ca pacity 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, g iven 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 ex isting 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 for ced to operate at significantly lower capacity factors (if not forced to retire297 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 B uilding Block 1.

Commenter s stated that the drop in natural gas prices has impacted the operation of their coal

fired 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 p rices 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 coal

fired units that typically operate as load following units. Commenters stated that their coal

- fired units typically ramp up and down to different loads throug hout 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 peak ing plants versus typical baseload power plants and therefore, the opportunities, as EPA has indicated, for heat rate improvements are greatly diminished.

Commenter s stated that Building Block 1 fails to account for the fact that reduced utilization o f 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 feasib ility

.
Commenter s 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 oper ating 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. Comme nters 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

an d 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. Commen ters 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 modi fying operating practices.

Commenter s 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 performance298 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 e xplain 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.

Commenter s stated that EPA's building block 2 adds yet another barri er 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 factor s 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 shu tdowns 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 t han those that operated near full capacity most of the time, and a coal

- fired unit's heat rate is often at its highest during start

up.

Commenters stated that the study recently conducted by NERC confirms that EPA's building block 2 may interfere with achi evement 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 admit s 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 imp rovements 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. Comment ers 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 ; t hese are pl otting 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 fr om 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 he at 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 coal299 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 bu ilding 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.

Commenter s stated that the interaction among Building Blocks 1, 2 and 3 may ser ve 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 re newable 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. Commen ters 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 t han a 1% improvement in the average fleet

wide 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 E PA should adjust Building Block 1 to require no more than a 1% heat rate improvement across the existing coal

- fueled generating fleet.

Commenter s stated that the proposed rule impedes its own goal of heat rate reductions through improved economic dispa tch. 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 wou ld disrupt that market structure by substituting emission rate over efficiency as a primary dispatch criterion.

Commenter s 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

e fficiency is impacted by both level of output and the number of start

- ups experienced by the unit.

Commenter s stated that EPA incorrectly assumes that coal

- fired power plants will maintain a heat rate improvement of 6%. Commenters stated that cycling c oal

- 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 mea ns of example, Pennsylvania's coal plants operated300 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 di scussed 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 direct ly following commissioning. Commenters stated that EPA should recognize heat rate degradation and swings in this rulemaking.

Commenter s 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 sa me 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 s tated 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 he at 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 ex pect 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 facto r 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 ” ) tha t 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.

Commenter s 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 to301 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 "back

off" 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 tha t 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).

Commenter s stated that changes in dispatch may also adversely affect the ability of older coal

fired 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 outpu t 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 Ra te 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 l oad 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 u nits 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 t hermal efficiency decreases when operated at loads less than 60% which increases the level of emissions per unit of electricity.

Commenter s stated that besides significantly underestimating the costs of a 6% heat rate improvement, EPA failed to consider that the other building bl ocks 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 re

dispatch to NGCC or new low

- and zero

- em itting 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 par t 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.302 Commenters stated that this negative feed

- b ack loop is compounded by the fact that they ha ve already made significant capital investments to comply with MATS and other looming environmental regulations. Commenters stated that they ha ve 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 ef

ficiency 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.

Commenter s 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 war m 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

- follow ing service.

Commenter s 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 th e 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 th e 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.303 Commenter s stated that EPA recognizes that coal

- f ueled 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 i ncrease." 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. Commen ters 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 un its 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 EP A acknowledges that building block two

- increased natural gas generation

- will displace coal: "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 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 improv ing coal unit efficiency. Commenters stated that i n 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 ra tes. Commenters stated that EPA completely fails to take this into account in its building b lock one calculations.

Commenters stated that increasing the utilization of NGCC units will displace coal

- fired EGU output and coal

- fired EGU heat rates will actua lly 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 ne cessarily 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 phase

out period at end

- of

- use. Commenters said redispatch should not be a mai nstay 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 impa ct 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, i f KU's Brown Unit 3304 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 imp act 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

- f ired 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 sai d 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 increase d 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 dec rees. 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 decrease s 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 s aid 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 dat a 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. Commen ters 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 redu ctions 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 demonstrates305 that operati on 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 redu ced 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 NG CC 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 Measu res 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:

Commenter s 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 whi le 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 u nit 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 ch anges 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 v ice 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 actu al 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 create d based on hourly ambient temperature data. Commenters306 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 "b ins" 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 menti oned 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 tempera ture, 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 i ts 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

- referenc ed 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 desig n, 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. Commente rs stated that consequently, EPA's estimate of potential improvement opportunities is flawed and inaccurate.

Commenter s stated that cooling water temperature has a large impact on heat rate and while ambient air temperature does impact heat rate, its i mpact 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 temp erature, 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, intak e 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%.

Commenter s 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 w ith 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 fac tor (see Figure 2

- 3, page 2

- 24 of EPA's TSD), where operating at307 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 a n 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.

Commenter s stated that some of the best practices that EPA focuses on, if implemented, can compromise reliability obligations. Commenters provide d 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
stat ed 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.

Commenter s 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 r ates 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 performance

improving 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 result s EPA concludes are achievable under Building Block 1, particularly at those facilities with smaller cooling ponds.

Commenter s questioned why the EPA didn’t analyze the non

- air impacts of heat rate improvements such as changing cooling systems as menti oned on p. 2

- 5 of the GHG TSD

.
Commenter s stated that ambient conditions have been well

- demonstrated to influence a plant's heat rate. Commenters stated that f or 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 c ommenter s stated that the magnit ude 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 circulation308 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 diffe rences 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 flaw ed 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 Cha pter 2 of the GHG Mitigation Measures TSD supporting the final CPP.

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

Commenter s stated that EPA did not consider cooling water temperature, which in practice has a far greate r 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 improvemen t measures

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

Commenter s 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 s pecifically 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 m oisture 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 (alkalin e 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 fur ther309 stated that there are solutions for this, but NSR provisions can be an obstacle to consideration of these solutions.

Commenter s 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.

Commenter s 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 practic es."

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, a nd 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 "combus ted" 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 pe riod that resulted in more than the 6% used as its model to justification for heat rate improvements.

Commenter s 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 competitive310 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 he at

- rate fuel and therefore, lignite fired units have historically been compelled to seek more efficiencies than those of units burning higher heat

- rate coals.

Commenter s stated that the fuel

- derived annual heat rate is highly variable starting in 2008 an d through 2011 at Antelope Valley Unit 2. Commenters stated that the o wner 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 increa sed 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 com promised by the change in fuel properties.

Commenter s 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.

Commenter s 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 u sed 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 heatin g value of coals and the rank of coal burned. Commenters stated that t hese 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 da ta 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 1 0% ha s decreased. Commenters stated that the additional coal moisture has had a definite impact on heat rate.311 Commenters presented a chart (Impact of coal rank on heat rate 2000

- 2014, tons coal & Heat Rate, bituminous, & subbituminous, Gross & Net Heat Rate) sh owing 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 th eir comment l etter, 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 1 0% 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 bit uminous 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 gen eration 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% use d in the model justifying for heat rate improvements.

Commenter s 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 whi ch 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.

Commenter s 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 t he 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 su pporting the final CPP.

The following are summaries of the specific public comments under this comment:312 Commenter s 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 ov er this period, and that have a direct e ffect 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 es timating any remaining potential for heat rate improvements at existing coal

- fired units.

Comm e n ters stated that i nstalling and operating emission control systems can often mask or offset any future heat rate improvement actions. Commenters stated that fr om 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 incre ases 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, c onsidering variable speed drives where practical, optimizing ductwork configurations, etc.), but these design options are site

specific, and in no case are they enough to offset a net heat rate increase from the addition of these control systems. Commenter s 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 f or 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

.
Commenter s 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 "capac ity factor, reporting method, or other events," these 16 units emerged from the national inventory and reported a single year

over

- year improvement in gross heat rate of at least 3

- 8%. Commenters stated that the sixteen units, owned by twelve utilities, we re 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 report ed 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. Specificall y, 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 S CR 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 and313 coal handling upgrades as part of a project to add SCR, FGD and fabric filter to th e 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.

Commenter s 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 gener ation 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 req uired SCR equipment retrofits will cause individual EGU heat rates to increase (become less efficient).

Commenter s stated that the Proposed Rule fails to recognize future efficiency

- compromising retrofits that may be required for compliance with upcom ing environmental standards, such as the MATS Rule.

Commenter s 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 he at 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 All en S. King Plant, on which EPA unreasonably relies as adequate demonstration of a six percent heat rate improvement [ GHG Abatement TSD at 2

- 32 ] . Commenter s stated that Xcel Energy undertook a large, voluntary emissions reduction project that included equip ment 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 baghous e; 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 emissi on control upgrades cost

- effective. Commenter s 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 t he 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. Commenter s stated that in light of this significant overall increase in heat ra te, 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. Commenter s 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"). Commenter s 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 an314 additional heat rate improvement to offset any loss in efficiency from parasitic emission control technology.

Commenter s 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 r emaining 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 de gradation in heat rate that is inherent with the operation of this additional equipment.

Commenter s 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 wi th 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 pre sents (Figures 2

- 1 to 2

- 6 ) typical curves defining the relationship between gross heat rate and operating load for six units representative of the twenty

eight examined. Commenters stated that the units selected represent supercritical and subcritical boil ers, 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

- e ight 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 conclude d 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 f ull

- load operation are on average more than offset by penalties for low load operation.315 Commenter s stated that many coal

- fired EGUs are installing pollution control systems to comply with other regulatory requirements, such as the Mercury and Air Toxic s 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 gene ration 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 indi cates 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 effe ct 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 Buildi ng 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.

Commenter s re ferred 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
t hat 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 w ould 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 201 2, the analysis demonstrates that heat rate increased about 1% while average capacity factors decreased

- demonstrating the important impact of capacity factor on heat rate.

Commenter s stated that the Flint Creek unit is being retrofitted with addition al 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 effi ciency. 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 tha t 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.316 Commenter s stated tha t 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

asso ciated 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.

Commenter s stated that compliance with MATS can be accomplished through technologies such as wet and dry scrubbers, dry sorbent injection systems, act ivated 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.

Commenter s 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, Ef fluent 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 addition al 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 o verall 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.

Commenter s stated that due to the heat

- rate and fuel chemistry of lignite, many Texas lignite

fired EGUs' control technolog ies 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 th e ability to comply with Block 1 of EPA's BSER model.

Commenter s 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 inst allation 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.317 Commenter s stated that the EPA neither analyzed nor addressed the effects of other regulations under the CAA that will ac tually serve to increase average net heat rates over time by adding auxiliary loads from additional pollution controls

.
Commenter s 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 I mprovement 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 Hun tington 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. Commen ters stated that m oreover, the EPA has not accounted for the heat rate penalty of installing parasitic emission control techno logy 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 rat e 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 S tone 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. Commenter s 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 ca se 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 prop osed 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 emiss ions, 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 wa s 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 over all 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

c ould lose up to 3.5 percent efficiency.318 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 degrad ation 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
ot her 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 effic iency 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 require ments 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.

Commen ters 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 Te chnology 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 eq uipment, 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 insta llation 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 i mprove 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 coal

fired 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 th e motor is turned off319 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 coal

fired 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 importan t 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. Comm enters 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. Commente rs 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 opti ons 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 Guide lines. 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 faciliti es, 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 disch arge 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 significa nt. 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 t o 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 limest one 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 Technolo gies 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 those320 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 incorrect ly 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. Commen ters 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 s crubbers 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. Commente rs 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 c hart , titled: “ Capacity factor, FGD Installat ions, 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 lea st 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.

Comment ers 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 reg ulations 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 sou rces to install the Best Available Retrofit Technology.321 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 emission s, 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 stati on 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 efficien cy 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 impro vements 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.

Commenter s 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 environme ntal 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 w ere 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 separa te 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 expecte d 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.

Commenter s agreed with EPA in recognizing that as units drop below full ca pacity, 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 impro vement assumption would effectively322 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 t o 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 coa l

- 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 p unishing 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 po llution reduction and thus should exclude CO2 emissions emitted from power supplied to pollution control systems in compliance calculations.

Commenter s 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 li terature 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, rel ied 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 efficienc y of today's coal

- fired power plant fleet, and may be unachievable.

Commenter s 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

an alysis 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 el ectricity output. Commenters stated that net heat rate depends significantly on the auxiliary load from a unit that is needed to provide323 power to pollution control equipment, water pumps, and coal pulverizers, among other systems. Commenters stated that re trofitting 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 CO 2 emission rate.

Commenter s commented on the degradation of efficiency due to other EPA regulations. Commenters stated tha t 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 grea ter HRIs to offset the additional auxiliary loads that will decrease the efficiency of the coal

- fired unit.

Commenter s stated that by including these heat rate improvement targets in the determination of the state's CO2 goal, EPA's Proposed Rule assume s 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 c ost 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 sta ted 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 emissio ns 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.

Commenter s 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). Commente rs 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 impl ementing those

measures.

Commenter s 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 t he DC Circuit Court for reconsideration and at this time, the DC Circuit has324 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 ru ling 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 rate s and these heat rate degradations have not been included in the 2012 heat rate baseline for Building Block 1.

Commenter s further discussed the Mercury and Air Toxics (MATS) Rule. Commenters stated that under MATS, controls for compliance with this rul e 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.

Commenter s stated that as proposed, the ELG rule can require physical, chemical, and/o r biological treatment as well as thermal zero liquid discharge systems and that his additional control equipment and systems can increase plant he at rates.

Commenter s stated that the proposed Coal Combustion Residuals (CCR) rule could eliminate
wet as h handling for both fly ash and bottom ash and a conversion to dry handling could be required, which may impact heat rates.

Commenter s 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.

Commenter s 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 baseli ne for Building Block 1.

Commenter s stated that utilizi ng 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:

“ C oal

- Fired Power Plant Summary based on NEEDS Database 5.13v3 ” ) which presents the coal

fired power plant fleet statistics as summarized from the NEEDS database. Commenters stated that the addition of environmental control equipment will negatively impact t he 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 si gnificant auxiliary load to operate heat rates will be negatively affected.325 Commenter s 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 recen t 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

.
Commenter s 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 pe rformance 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 imp lementation 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

var iable CO2 emissions that can be expected from modern coal

- fired EGUs.

Commenter s 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 efficie ncy, 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 electrici ty 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 pre sent 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.

Commenter s stated that EPA's as sessment that plants can undertake projects to improve efficiency by 2% across the nation is incorrect. Commenters stated that as consumer owned utilities, they ha ve an obligation to provide all possible cost savings to customers and cost effective efficie ncy investments are regularly assessed and undertaken when financially prudent.

Commenter s 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 imp roved 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 modest326 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. Comm enters 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
megaw att as the proposed rule assumes can be done.

Commenter s 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 adjustment s to their building block 1 goal.

Commenter s 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 a s 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 e nvironmental 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
percen tage) 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 opera ted 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 t hat 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 b oth the states and utilities must be free to respond to pollution control requirem ents outside of any CO2

- related requirement.

Commenter s 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 co mpared 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.

Commenter s stated tha t 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.327 Commenter s 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.

Commenter s 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 exis ting 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. C ommenters 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.

Commenter s stated that EPA did not consider the parasitic load and lost efficiency of new emission control systems requir ed 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 t hese problems illustrate the danger in a state relying on heat rate improvem ents as high as 6% in their plans to achieve the rule's goals.

Commenter s 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

a ccordingly, this worsening of the heat rates negates any improvements resulting from specific projects.

Commenter s 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.

Commenter s 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.

Commenter s stated that in technical support do cuments, 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 e nvironmental 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 entir e "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 pr ices, increased generation from renewables, and costly control retrofits to meet new pollution standards.

Commenter s 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 for328 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 w ill 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.

Commenter s stated that i mplementing 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 historicall y 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 ca n 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 state d 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 wi th the federal Regional Haze Program.

Commenter s 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 requir e 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 s tated that achieving 6 percent efficiency gains while adding additional environmental protections unrelated to the CPP may not be possible for the fleet.

Commenter s 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 (C SAPR) 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 inv ested 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.

Commenter s sta ted 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
p rojects frequently decrease a unit's gross output and/or increase the unit's auxiliary load, both of329 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.

Commenter s 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 equ ipment 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 unreas onable 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 pla nt operators are unlikely to be able to shoulder such retrofit costs without affirmation that their investments will bear fruit over the long

- term.

Commenter s 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. Co mmenters 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 add ressed 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 pol lution 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 p arasitic 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%330 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 st ated 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 addre ss in any future subsequent rulemaking.

Commenter s 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 p otential 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 measur es, such as those that are necessary to comply with the MATS Rule or the Cross

- State Air Pollution Rule. Commenters stated that f or example, their Cross 1 and 2 units were originally designed to include three scrubber modules per unit, with an original goa l 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 thre e 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 cumu lative 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 emiss ions 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 un its 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 re newables 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 pl ant 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 facili ties 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 wi thout significant cost, if at all.331 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 C hapter 2 of the GHG Mitigation M easures TSD supporting the final CPP for EPA’s response to this comment

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

Commenter s 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 maxi mum 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,

e ach 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 t o 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 C hapter 2 of the GHG Mitigation M easures TSD supporting the final CPP for EPA’s response to this comment.

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

Commenter s stated that i n 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 understo od 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.332 Comment 38 : Comm ents 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 c omment :

Commenter s 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 component s ." 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 regardi ng 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 i nput 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 defi ned 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
t emperature 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 dat a 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, the333 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 conclusio ns 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 low

moisture coal. Commenters stated EPA incorrectl y 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.

Commenter s stated that EPA's calculation of a 4% HRI from best management practices ( BMPs ) is speculative and while EPA's analysis uses data points thro ugh 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 th e 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.

Commenter s 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 t hen 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 exa mples 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 conclus ion.

Commenter s 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 demonst rated 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 a t 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 specified334 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 EP A 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 wo uld 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 conser vative, 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 ana lyze 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 pe rcent 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 t hese 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 hypo thetical 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 (analog ous 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 ac tuality, 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 improveme nt is achievable and that its choice of 4 percent is overly conservative.

Commenter s agree d with UARG that EPA's "model" assessing potential heat rate improvements via "best practices" is arbitrary and capricious. Commenters stated that i n 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, a nd 50 percent. Commenters stated that EPA335 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 agree d with UARG that this conclusion is arbi trary and unfounded. Commenters stated that a bsent 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 a t most, EPA's discuss ion 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 t he Agency makes no attempt to show whether the measures it identifies as "best pract ices" 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.

Commenter s stated that EPA's so

- called "statistical analysis" of heat r ate 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 partic ular, 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 cor responding 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 becau se 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 & M ichael 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 perce nt "best practices" estimate to any identifiable, technically feasible heat rate improvement measures. See I d. 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 red uce 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 su ch 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 variat ion that EPA calculates at each unit do not represent varying implementation levels of "best practices" measures: they were apparently selected without any336 technical basis. Thus, EPA's decision to "conservatively" select a level of reduction that is "in th e middle of the range of options" it arbitrarily chose is itself arbitrary. GHG Abatement Measures TSD at 2

- 34.

Commenter s 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 ha ve access to on a national basis. Commenters explain ed 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 conclude d 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.

Commenter s 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 impr ovements 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 exi sting 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, y et, it is precisely this assumption upon which EPA's proposal for large improvements relies.

Commenter s 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
percen tage (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?

Commen ters s ummarize d that EPA s aid that "...[b]y applying best practices to their operating and maintenance procedures owners and operators of EGUs could reduce heat rate variability337 relative to average heat rates and, because deviations generally result in performan ce 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 state d 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 matri x 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 regressio n 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 a nd 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 an d 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 questi ons 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 1 68bin 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.

Commenter s also stated that EPA's analyses and conclusions ar e 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.

Commenter s 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 deter mine the amount of variability in heat rates across the existing fleet. See I d. at 34,860. Commenters stated that338 r ecognizing that ambient temperature and hourly load levels (capacity factors) have a direct impact on a unit's heat rate and are outside a un it'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 t he Agency assumed that any remaining variabilit y 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 34,8 60. Commenters stated that f or 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 I d. 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 observati ons within defined ranges of temperature and load could be eliminated through adoption of best practices." Id. at 34,860. Commenters stated that b ased on this analysis, EPA concluded that: A reasonable estimate for purposes of developing state

- specific goa ls 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 t his 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 i n 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 i n the absence of a clearly articulated basis for this 30 percent value, it ca n 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 state d that a s 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 v ariability is change relative to an average value, not relative to an optimal (in the case of heat rate, minimal) value. Commenters stated that n evertheless, EPA conducted a regression analysis of 884 generating units and concluded that units with more var iable heat rates tend to have higher heat rates. See Abatement Measures TSD at 2

- 22. Commenters stated that e ven if this is true, the regression analysis only identified the relationship between variability and higher heat rates; it did not identify the ca use of the variability , and that i n 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 state d 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. Comment ers stated that a s 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 Reliab ility 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 n o analysis supports this assumption and assigning the cause339 of 30 percent of the variability to O&M practices, therefore, is arbitrary. Commenters stated that

a ccordingly, EPA's analysis did not identify the cause of the observed variability in heat rates. Commenters f urther 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 EP A'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" ana lysis begins with the premise that any variability in a unit's heat rate represents an opportunity to improve heat rate and reduce emissions. See I d. 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

w hile EPA is correct that improved heat rates result in reduced emissions from coal

- based EGUs on a rate basis, see I d. at 34,905, EPA has fai led to produce a reasoned analysis to quantify how much average heat rates can be improved by implementing additional O&M measures. Commenters stated that m any factors contribute to heat rate variability; some of these are outside the control of the unit o perator and can never be eliminated. Commenters stated that m ore 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 t his 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 det erminant of heat rate for units with varying load. [ See Abatement Measures TSD at 2

- 25. ] Commenters stated that t he bin analysis reduced the effect of load factor changes, but each bin itself includes a 10 percent range of load factors. [ See Abatement Meas ures TSD at 2

- 24 to 2

- 25. ] Commenters stated that a n 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 t hus, the bin approach reduced, but did not eliminate, the very significant impact of variable load factor on heat rate. Commenters stated that

a s 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 rat e for fossil

- based EGUs. See Appendix C at 4

- 5. Commenters stated t he higher the load factor, the lower the heat rate. Commenters stated that l ower capacity factors or increased cycling increase heat rates and increase heat rate variability. Commenters sta ted that i n 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 th at u nit owners and operators, therefore, cannot control load factor to address concerns about heat rate. Commenters stated that i f 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.

Commenter s 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 va riables affect heat rate and, thus, the potential for efficiency gains through best operating practices.340 Commenter s summarized EPA's approach to determine estimated efficiency gains of 4% from best operating practices Commenters stated that EPA then es timated 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. A nd 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 i n 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 aff ects heat rate. Commenters stated i n regions where baseload capacity is spread across coal, nuclear, and natural gas facilities, coal

fired facilities will cycle more often, meaning they operate at higher heat rates. Commenters stated that overall electric ity 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 ten d 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.

Commenter s stated that, to support its determination that best p ractices 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 conclu sion. 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.

Commenter s stated that EPA made overly simplistic assumptions concerning the ability of like

situated 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 tem perature 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 assumption341 concerning best practices is not supported, it leads to an arbitrary conclusion that coal fired power plants can improve he at rate by four percent.

Commenter s 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 em ploy 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 a n 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; u tilize 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 maint enance 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 chec ks 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 utiliti es, 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.

Commenter s 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. Co mmenters 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 a nd 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 sta ted 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 stat ed 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 va riability 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 I d. at 34,90 5, 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 impo rtantly, EPA's assumption that improved O&M can ameliorate variation in heat342 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 improvemen t through O&M best practices is both reasonable and economic. Id. at 34,860.

Commenter s stated that EPA's a ssumptions a bout Operating "Best Practices" is incorrect, as exemplified by their u nits. 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 avera ge 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 impos sible. Commenters stated that i ndeed, 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 th at indeed, Sargent & Lundy itself concludes that "it appears that most of the utilities are employing best operational and maintenance practices. Commenters stated that i n light of this observation, it appears that significant further reduction in heat rat e, 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 f urther 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 inef ficiencies. 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.

Commenter s stated that EPA's conclusions as to efficiency improvements from O&M activities, however, are not ba sed 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 tha t 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 account ed 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. Comme nters 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 abili ty 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 condit ions. (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 suppo rt for its assumption that the "residual" variability in existing coal unit heat rates can be eliminated through the implementation of improved O&M practices.

Commenter s stated that EPA claims that improvements in O&M activities alone can achieve, on

a verage, 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 loa ds, 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 bas ed 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 accoun ted 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 throu gh 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 hum idity 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 fo r 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 towe r 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 att ributable 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, howeve r, 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 da ta based on unit characteristics that cannot be replicated at other facilities.

Commenters stated t he Proposed Rule fails to account for known sources of heat rate variability and also fails to address the potential cumulative effect of those factors tog ether. Commenters stated t he 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.

Commenter s 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 w ould 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.

Commenter s stated that EPA's "best practices" analysis assumes that any variability in a unit's heat rat e 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. Comme nters 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 outs ide 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 unsuppo rted.

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

c ould 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 the345 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 ha ve 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 in stallation 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.

Commenter s stated that EPA's determination that a 4 percent heat rate improvement is achievable by implemen tation 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 y et, EPA provides no actual evidence that those measures can bring about such an improvement. Commen ters stated that

r ather, 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 believ es that most coal units across the country operate in a persistent degraded and inefficient state and that t o the contrary, they already engage in many measures to ensure Lowman's efficiency. Commenters stated that t hese activities attempt to restore and/o r improve equipment efficiency while balancing consumer costs and reliability. Commenters stated that a s routine maintenance occurs, an attempt to restore or increase efficiency is made to minimize the amount of heat rate degradation. Commenters stated tha t 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.

Commenter s 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 w ith controllable operating and maintenance practices that would be cost effective to perform. Commenters stated that EPA fails to consider that what346 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

ma intenance 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.

Co mmenter s 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 inefficienc ies 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 p ractices. 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.

Commenter s stated that EPA lists examples o f 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 attemp t 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.

Commenter s 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. C ommenters 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

ov er 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. Commenter s 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 conside r 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 chan ges 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 equipp ed 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 pro cess optimizers that are already installed at the plants.

Commenter s 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 th at "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 suppo rt 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 acknowled ge 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 canno t 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.

Commenter s 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 E GUs' 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 f rom 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 tha t 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 pr actices, 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% o f the difference between the reported value348 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 b asis 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.

Commenter s 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 rate s 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 potenti al 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 num erous 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.

Commenter s 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 w as 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

un fortunately, 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 re gulations that would impact349 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 thr ough best practices.

Comment 39 : Comments stating that potential heat rate improvement through best practices is not achievable

Response 39 : The response to c omments 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 g roups 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 improvem ent at all. Furthermore, i f 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 c omment:

Commenter s 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 op erating 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 effi ciency 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
te mperature 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."

Com menters 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, more350 efficiency gains would have to be achieved through equipment upgrades, in which there is no certainty that even the two percent gain pro posed by EPA can be achieved.

Commenter s stated that EPA did n ot 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 mai ntains 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 refer red to Sargent & Lundy who stated that "most

u tilities 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."

Commenter s stated that even if permissible it is not at all clear that it is fea sible 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.

Commenter s 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 sy stems, 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 b y 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 ar e 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 al low 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 coal

fired EGUs are able to operate very near design values.

Commenter s s tated 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 ste am 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 fu rther improvements through best practices infeasible. Commenters stated that CPS351 Energy has a staff of engineers and technicians dedicated to identifying and implementing efficiency improvements and keeping these units running as efficiently as possible.

Commenter s 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 t hen 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 f rom this range, EPA decided that, on average, coal

fired E GUs 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 of ten, 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 simil arly fails to account for variations in heat rate among different types and ages of facilities.

Commenter s stated that EPA projects that a universally applied average 6% reduction in GHG emissions will result from their building block 1 heat rate imp rovement 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 ar ising 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 Repo rt and the NETL reports cited by EPA as the basis for their conclusions.

Commenters stated that the assumptions m ade in the first two building blocks are not technically feasible and viable for Michigan or most other states; therefore the methodology in t he goal calculation must be reconsidered352 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 c omment :

Commenter s 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 alread y 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 th e 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 su pplemental 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 comme nt.
The following are summaries of the specific public comments under this c omment:353 Commenter s 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 alternativ e 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
percen t 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 t o 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 improvem ents 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 d etermine 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 im provement 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 upgrade s . O ur 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 c omment :

Commenter s 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 f or 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 "y ear

- to

- year." but it does not include any supporting354 data. Commenters stated that w ithout 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 o n the achievability of EPA's heat rate projections.

Commenter s 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 A dequately 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 fro m 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 prov ide 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.

Comm enter s 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 impr ovement 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 e missions 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 fo r 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 no t 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 po ssible upgrade

- technologies to allow states to consider each on a case by case basis in developing their plans.

Commenter s 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 input355 for purposes of developing state goals an estimate that, on average across the fleet of affected EGUs, only half of the full equipmen t 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 th an 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, fal ls 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 d raws 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 necessar y to achieve the goal, as required by the D.C. Circuit.

Commenter s 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. Ove r how many years?

3. Please provide the details of this analysis and record of peer

- review.

Commenter s 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 o r 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?

Commenter s 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?

Commenter s 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 regulati on, however, in this instance, EPA chose to forgo a search for relevant data to support its

a nalysis. Commenters cited GHG Abatement Measures, at 2

- 36. Commenters stated that instead, EPA proceeds to establish emission guidelines for Arizona and other sta tes, 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

.356 Commenters stated that a review of pertinent data for U nits 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 eq uipment 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 opport unity 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 effici ency 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 sh ow 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 EP A's p roposal would require.

Commenter s 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 signif icant variables so unit heat rate is compared to a best achievable heat rate.

Commenter s 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 fleet

wide basis as many of these overhauls are implemented as usual practice, and the benefits decrease with time. Commenters then describe d 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%.

Commenter s 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 generali zed 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 tu rbine upgrades (the measure with the highest estimated payoff) are only357 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 availabl e 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 y ield substantial benefits if they were implemented again. Commenters stated that other measures are simply not compatible with the design of particular units.

Commenter s 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 improvement s: 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 conclude s 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 fo ur 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 an d 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 exte nt 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 T able 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 tha t 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 d ata 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.358 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. Comme nters 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 r ate 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 char acteristic. 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 ra tes, 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 ap proximately 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 infrequen cy 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 wor ldwide. 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 201 2. 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 reductio n 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 c ommenter s ' study indicates, few plants have actually invested i n 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 as sociation 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.359 Commenter s 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

- to

year improvements in heat rate. After filtering out those cases that may have bee n 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. Com menters 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 h ad 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 sust ained. 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 9,7 53 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 wou ld 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 coal

fired 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 in clude 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: w hen 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.360 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 P lants, DOE/NETL

- 2013/1611. U.S. Department of Energy, National Energy Technology Laboratory. April 1, 2014.)

Commenter s 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 ha ve 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 sche duled 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 add itional 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 e fficiency 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 tea ring 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 t he 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 c omment :

Commenter s 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

r educing the already

- inflated target by half w ithout further analysis is not "conservative," it is361 merely guesswork. Commenters stated t he 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. Comme nters stated that EPA cannot require affected EGUs to duplicate emission reductions they have achieved using measures they have already taken. Commenters stated that
t herefore, EPA must assess what efficiency upgrades have already been implemented by affec ted coal

- fired EGUs in order to determine what level of additional heat rate improvements is achievable. Commenters stated t he Agency has simply failed to adequately prepare the necessary background information for this rule. Commenters stated that l ikewis e, 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 pres ent at a unit and whether the upgrades may present operational reliability issues at a particular unit. See NCC Report at 71.

Commenter s stated that 2% is flawed and based on outdated information. Commenters stated that EPA relied on an exceedingly sma ll 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 obtain ed 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 thr ough 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 una ble to confirm specific equipment upgrades." Commenters stated that e ven 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, uncer tain. 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 S argent & 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 on ly 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 som e 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 sufficien t 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 th at 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 i ndeed 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 state d that for its part, EPA's analysis relies on suppositions of what heat rate improvements are yet untapped that fall far short of the requisite362 "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. Installati on 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 co ntrols 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 h eat 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 th e 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 ha ve co llected information reflecting upgrades that have been made to the coal

- fired fleet

, and it is the c ommenter s ' understanding that many units have already undergone modifications to improve heat rates. Commenters stated that b ecause 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.

Commenter s stated that the CPP in establishing the 6% heat ra te 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 plan ts 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.

Commenter s stated that EPA's analysis of the heat rat e improvement from equipment upgrades at coal

- fired power plants is flawed because EPA's assessment is not representative of most coal

fired power plant. Commenters stated that EPA cannot conclude that a heat rate improvement of two percent is attainable f rom equipment upgrades at all coal plants based on sixteen units.

Commenter s 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 improveme nt 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 techni cal potential and cost of such363 improvement opportunities, while ignoring significant feasibility, sustainability, measurability, and regulatory challenges.

Commenter s 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 upgra des 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.

Commenter s believed that it is unlik ely 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

- o f

- 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 e xisting 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.

Commenter s 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 sav ings to customers. Commenters stated that cost effective efficiency investments are regularly assessed and undertaken when financially prudent.

Commenter s 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 anal yze 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 data364 sources exists with respect to potential HRI at individual p ower plants across the country, EPA has cited virtually no hard data that provide an accurate picture of realistically achievable HRI from equipment upgrades.

Commenter s stated that EPA relies on the Sargent and Lundy (S&L) report prepared for EPA in 2 009 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 stat ed 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.

Commenter s 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 ont o 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 s ources 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 t hat 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. C ommenters stated that calculating a reasonable goal for efficiency gains from 2014 onwards requires dat a 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 hav e 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 o f what heat rate improvements are yet untapped is not supported by the record.

Commenter s 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 h ave 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 s tated that EPA presents no data to365 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 m ethodology 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
equ ipment 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 mai ntain 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 ol der turbine).

Commenter s 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 bl owers 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.

Commenter s stated that with regard to equipment upgrades, EPA makes an arbi trary determination that does not naturally stem from the data it relies upon and that i t cites one study

- conducted by Sargent & Lundy

- as its source. Commenters stated that i t 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 up grades. 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. C ommenters 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 in cluding 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.366 Commenters said for example, EPA's H RI 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 h ighly 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 Measur es 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 comme nts under this c omment:

Commenter s 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 simp ly 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 provid e 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."

Commenter s 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 upgrade s 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 rel iance 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 backe nd 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 tha t 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 unde r 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 minim um 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 t o potential downstream effects on electrostatic precipitators ("ESP") and FGDs.

Commenter s 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 agree d 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 s ix 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

con trol 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 bel ieves that the methodology described in the above

- referenced portions of the preamble and TSD provides the368 best method of determining the heat rate improvement component of the BSER, for the reasons described therein.

The following are summaries of the spe cific public comments under this c omment :

Commenter s stated that reviewing the plots for the six units still operating on Navajo land,

c ommenters 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 Un it 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 commenter s ' 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 op erating 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 NG CC 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 requireme nts 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 c omment :

Commenter s 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 o f 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 continue d stating that, while initial efficiency improvements, regard less of the range, might be technically feasible, it is a well

- known fact369 these efficiency gains are not sustainable. Commen ters stated t he degradation of operational efficiency is a forgone conclusion, and it simply would be uneconomical and impractical t o expect the industry to maintain a specific efficiency level. Commenters stated that f inally, stakeholders from all of Kentucky's utilities reinforce the conclusion that achieving a heat rate improvement of six percent is highly unlikely, if not impossibl e. Commenters stated that o ne 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 i t 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 state

specific goal. Commenters stated that a n alternative would be to reset the heat rate impr ovement 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 s hould EPA see fit to readjust t he percentage, the Cabinet again contends that simply shifting the reduction to another building block would be inappropriate.

Commenter s stated that in addition to its analysis of variability in hourly heat input rate and gross generation data for th e "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 ra te 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 rea sonable 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." Commenter s 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 he at rate.

Commenter s 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 ha ve an obligation to provide all possible cost sa vings 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."

Commenter s stated that EPA misinterpreted the 2009 Sargent and Lundy Repor t 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 t heir 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 case370 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 stra tegies is economically justified."

Commenter s 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 calculatio n, EPA relies on a 2009 Sargent & Lundy report detailing four equipment upgrades. Commenters stated that t he impact of implementing the four equipment upgrades ranges from 2.1%

- 6.7% improvement. Commenters stated that f rom the Sargent & Lundy report, the minimum improvement from the steam turbine overhaul is nearly 1%. Commenters stated that h owever, many utility turbine sections have already been upgraded including one or more turbine sections on seven TVA coal

- fired units. Commenters stated that

u sing EPA's assumptions for turbines that have already been upgraded, only 1.1% potential upgrade potential remains for these units. Commenters stated that a lso, these upgrades do not provide a sustainable heat rate improvement; efficiency degradation occur s as they operate. Commenters stated that i n 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 e fficiency 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 deg radation 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 a s 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 Strat egy, Sargent and Lundy Description and Applicability to TVA Units.

Commenter s 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 & Lund y'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 economic al 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.

Commenter s also stated that EPA also concludes that unit

- specific "e quipment 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 a ccordingly, EPA lacks a sufficient and reasonable basis for concluding th at 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 ex clusively on the 2009 S&L report in its determination that equipment371 upgrades could result in HRI of two percent. See Abatement Measures TSD at 2

- 33. Commenters stated that t he S&L report outlined 13 different HRI measures. Commenters stated
t he Agency sep arated these measures into two categories, based largely on cost. See I d. at 2

- 33. Commenters stated t he 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 un it (that had not already deployed them) the overall HRI would be four percent. See I d. 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 I d. at 2

- 35. Commenters stated that w hile 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, achi eve 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 f urther 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.

Commenter s 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 a uthors 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 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

- by

case analyses should be conducted to determine whether the incremental heat rate improvement throu gh the application of multiple strategies is economically justified."

Commenter s 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 te chnical 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. C ommenters 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 impr ovements 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 be en 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 f

or 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 clari fied 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.

Commenter s stated that although the 2 009 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 f or example, turbine upgrades or replacements would be expected to provide a reduction in heat rate following implementation, but, as with all equipment upgrades, are susceptib le to degradation over time. Commenters stated that r outine 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 wil l 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 similarl y 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 evalua tion of fleet

- wide average heat rate improvement opportunities, EPA overestimated efficiency improvements that can be achieved and sustained.

Commenter s 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 Commissio n 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 avail able 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 bo th 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 rep ort 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 B tu/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 sp ecific 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 st ated 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. Comment ers 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 degrad ation 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 Statio n to be no more than 1%.

Commenter s 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 conc lusion 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 tha t 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 oper ation 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.374 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 opportu nities, 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 th e 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 fol lowing 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 20 09 S&L Report represent order

- of

magnitude 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 convert ed 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

- spe cific 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 th e available HRI methods must be evaluated on

a case

- by

- case basis.

Commenter s 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 base d on a literature

- survey

- and

- vendor

- data analysis, EPA uses national averages to conclude375 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 improve ment 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 demon strate 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 th e 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 imp rovement 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 wo rk. 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 outs ide 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 Sarg ent 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.

Commenter s 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 operat ion 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 ope rate on a minute

- by

minute 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 conclude d that the payoff from any given heat rate improvemen t method is highly site

- specific. Commenters stated that i n 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 t he results sho w 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 techno logies using the Sargent & Lundy Report. Commenters stated t he 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 inappro priately (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 obtai ned immediately after the project for many of these means often degrades with time. Commenters stated that a s 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 i n 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 performa nce.

Commenter s 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. Comment ers 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 suppo rt 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 to377 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 i nappropriately 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 base d on invalid data, is inherently flawed, and does not support a rational basis for the emission reductions required by Block 1.

Commenter s 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 2 009 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 upgrade s a nd 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 state d 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 improveme nts 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. Co mmenters stated that therefore, the two percent heat rate improvement via equipment upgrade in the proposed rule is arbitrary and capricious.

Commenter s stated that with respect to available equipment upgrades, most EGUs in West Virginia have already a chieved 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 s tudy 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 th at none of the case studies involved a typical modern West Virginia base

load 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 outdated378 bec ause 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)

Commen ter s 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 t hat 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 l ikely 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 repo rt 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."

Commenter s 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 thi s 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 personne l 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 repor t 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 b een examined to every individual generating unit. Commenters stated that3 79 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.

Comme nter s stated that EGU operators have strong incentives to run their power plants as efficiently as possible. Commenters stated that e fficient 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 achie ving 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.

Comment ers 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 tho se 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 coal

fired EGUs covered by the P roposed Rule had already implemented some or all of the improvements in the study by 2012, making further improvements beyond that baseline unrealistic.

Commenter s emphasized a fundamental finding in S&L's critique of EPA's use of its 2009 study

- it i s 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 upgra des, 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 o f some of the HRI strategies surveyed in the 2009 report will degrade over time, in spite of bes t maintenance practices.

Commenter s stated that S&L has publicly stated in correspondence with National Rural Electric Cooperative Association (NRECA) and t he 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 coa lfired 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 applicab ility 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 d ue 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 strate gies identified by the S&L report.380 Commenter s 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 pl ants. 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 thes e upgrades at affected units would generally be prohibitive and could trigger onerous New Source Review permitting requirements.

Commenter s stated that while EPA arbitrarily adjusts the potential improvements from four percent to two percent without kn owing 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 arbit rarily 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 clo sely resemble the S&L Report's 850 MW case study unit.

Commenter s 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. Comme nters 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.

Commenter s stated that EPA inappropriately relies on the 2009 Sargen t & Lundy report

.
Commenter s 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 finding s 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 manufac turers, 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 equipm ent 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 t o apply each strategy and the amount of heat381 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 we re 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 improve ments 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 imp rovement 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.

• The performance of some of the evaluated heat rate improvement strategies degrades over time, even with best maintenance pr actices. 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.

Commenter s 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 pot ential 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 stud y 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 sta ted 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 achi eved 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 i mportant 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:382 • 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 justif y 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 f rom 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 fu ll 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.

C ommenter s 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 "a dequately 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 s imply 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 appropriate383 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.

Commenter s 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 combined

cycle, 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.

Commenter s stated that the Sargent and Lundy study on heat rat e 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 stat ed 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 a nalysis 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 "Sarge nt & 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.

Commenter s 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 hea t 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 conne ction 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."

Commenter s 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 determi ned to be achievable at any particular EGU. Commenters cited the S&L study indicating384 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.... "

Commenter s 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 tha t 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 t he 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 limite d and highly site

- specific.

Commenter s 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.

Commenter s stated that EPA's reliance on the 2009 Sargent & Lundy repor t 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 "Co al 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 state d 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 operation al 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 anywhe re 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.

Commenter s stated that EPA incorrectly utilizes the d ata 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 th e implementation of additional heat rate improvement projects and economics aside, it would not be physically possible to implement all of the Sargent and Lundy385 upgrade options at a single unit to achieve the additional efficiencies to meet the required 6 percent level.

Commenter s 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 b y 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.

Commenter s stated that EPA failed to support its claim that a 2% improve ment 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 opp ortunities 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 an y 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 assu mes 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 cumulati ve 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 measura ble 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 improvemen ts 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 conclu de 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 limit ations 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 dependen t 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 light387 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 Aba tement Measures Technical Support Document, but that evidence also fails to provide sufficient support for EPA's building block 1 assumptions.

Commenter s stated that EPA's conclusion that a 2 percent fleet

- wide HRI could be achieved by equipment upgrad es 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 fo r 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.

Commenter s 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 he at 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 limitati on. 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 ef ficiencies 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.

Commenter s stated that EPA cannot justify using the hypothetical and generalized assumpt ions 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 improveme nts 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.

Commenter s stated that Sarg ent & 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 improve ments.388 Commenter s 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 impr ovement 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 im provement 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 case

by

- 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 conceptu al 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 th at 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 distingu ished 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 th at 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 lea kage 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 al ready made these upgrades."

Commenter s 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

.
Commen ters 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 presen ted 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 uti lity 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 bui lding 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.

Commenter s sta ted 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 Elec tric 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 fea sible 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.

Commenter s 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. Comm enters 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 speci fic 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.

Commenter s 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."

Commenter s stated that Sargent & Lundy has recently addressed EPA's misuse of the S&L Study. Sargent & Lundy noted that "the only technic ally 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 EG Us 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

man y 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 project s;

• 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.

Commenter s 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 "ma intenance "

.
Commenter s state d 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.

Commenter s referred to a letter sent to the National Rural Electric Cooperative Ass ociation (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 r ate 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 signif icant further reduction in heat rate, such as that assumed by the EPA, may not be feasible."392 • 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 Coope rative EGUs, which show a 6% HRI is not possible at most EGUs.

Commenter s 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 rat e 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 tha t 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 site

specific 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. Comm enters 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 multi ple 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 implem ented. 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 pro mulgates emissions guidelines that the state uses to make its individual source decisions about the proper performance standard for the unit in question.

Commenter s 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. Commenter s stated that the PAPUC finds the analysis to be technically thorough but offers some comments and observations.393 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 analysi s 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 PAPU C 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.

Commenter s 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 di fferent 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 r eport, 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 re sulting 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 rat e 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.

Commenter s stated EPA relied almost exclusively on the 2009 S&L report. Commenters stated that while "best pr actices" and "equipment upgrades" can improve heat rates and reduce emission394 rates, the use of a single report is not a sufficient basis for concluding that the nationwide coal

fired EGU fleet can, on average, achieve a 6 percent HRI. Commenters stated tha t 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." Comm enters 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 rep ort 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 a ny estimates of implementing HR I 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 E PA's approach that resulted in the identification of a national average HRI is without merit.

Commenter s 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 acro ss 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

- fi red 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

- uni t 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 2 009 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.

Commenter s stated that U.S. EPA also cites the results of a HRI study prov ided 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 t o 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 to395 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, 20 14 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 exist ing 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 outag e 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 fur thermore, 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 studie s 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 ma intenance 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 consid erably 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 acknow ledge 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."

Comm enter s 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 r eviewing 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 st udy 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 p urpose 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 proje cts referenced for HRIs are not functionally applicable to specific units.396 Commenters stated that for example, replacing economizers for better performance could cause additional problems such as: fouling issues can arise in finned tube designs dependin g 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 a ctivities 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 best

practice 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 reco gnize 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

a nd 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 o f 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.

Commenter s stated that the S&L Study alone was used to inform the ability for sources to achieve HRIs through equipment upgrades. Commen ters 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 reasona ble 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 ha ve 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

- eff ective 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 a nd 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 circum stances 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 sh ould 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 "tec hnical 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 aggre gation 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 examine d 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 "si te

- specific conditions" such as fuel type and unit type and "must be evaluated on a case

- by

case 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 e stimated 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 re alized."

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 impro vement 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 Commenter s 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. Commente rs 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. Commenter s 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 perform ed 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 b e 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 bo iler 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 tha t 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 B tu/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" as sume 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 d ata 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 me thods, 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 fleet

wide basis.

In summary, c ommenters 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 upgrade s, 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 insta lled 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.

Commenter s 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 re consider 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 som e 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 a lso 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 of400 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 improvem ents. 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 themsel ves 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 th at 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 ma ke sense

after 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 s tudy 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 gen eration 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."

Commenter s stated that based on a review of the 2009 Report, as well as a review of EPA's Goal Computation Tec hnical 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 im provements 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. Comme nters 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 implemen ted 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 generatin g unit due to a number of factors, including plant design, previous equipment upgrades, and operational approaches.

Commenter s 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 t he Agency relies primarily on a 2009 report by Sargent & Lundy comparing vari ous heat rate improvement measures that are generally available, as well as401 EPA's own limited analysis of historical data on reported generation and heat rate from existing coal

- fired EGUs. Commenters stated that s pecifically, as one component of the targe t, 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 ove rhaul. 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 a s 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 poten tial 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.

Commenter s stated that EPA misinterp rets 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 technicall y and economically feasible.

Commenter s 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. Com menters stated that r emaining 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 ti me. 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.

Commenter s stated that the y believe that EPA inappropriately used the 2009 S&L Report to assume that the types of improvements es timated 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) an d 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).

Commenter s 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 these402 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
t he study's conclusions to fit the CPP and that i nstead , the types of equipment upgrades available to a particular EGU ar e far from uniform. Commenters stated that a given upgrade may produce significant heat rate improvements in one facility, but may not p roduce 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 ductwo rk 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 specifi c 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 bui lding block 1.

Commenter s 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 identifie d 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 hea t 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 pr ovided 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."); I d. at 13 ("Bilirgen and Gaikwad emphasized the difficulty in generalizing the potential for heat rate improvements in units across the nation absent calculati ons 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 and403 site specifications." Sargent & Lundy, Coal

- Fired Power Plant Heat Rate Reductions at 1

- 3 (Jan. 22, 2009).

Commenters stated that as heat rate improvemen t 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 s ound 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

- fir ed 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 a nd 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 acknowl edges 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 Abat ement 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? C ommenters 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 l oad 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 coal

fired 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 2 014 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 been404 "adequately demonstrated" as required by Section 111(a)(1) and for this reason alone, EPA should w ithdraw its proposed building block 1.

Commenter s 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 in

house 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 impro bable 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 fa cility's average heat rate is lower when it is base

- loaded than when it is load

- cycled.

Commenter s stated that while they do not own coal generation, part of their purchased power electric generation mix is generated from coal. Commenters

, therefore , w ere 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 t his [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, noth ing 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 h eat 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 lowe r 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 leve l." 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 11 1(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.

Commenter s 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 co sts 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.

Commenter s stated that Building block #1 incorrec tly 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 coal

fired generators such as CWLP to a dopt 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 ho w 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 i s 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 USE PA'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/En vironmental_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." S ee, 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." Com menters stated that therefore the USEPA misapplied the S&L study in406 determining the heat rate improvements according to the S&L comments from November 24, 2014.

Commenter s provided the following comments in regards to their 2009 report on heat rate im provement: "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

- of

magnitude costs to implement the changes. Commenters stated t he 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 improvemen t, nor for determining the average fleet

- wide costs of implementing the HRI methods. Commenters stated that h eat rate and cost data provided in the 2009 S&L Report, if applied properly, supports the conclusion that a detailed site

- specific analysis is requ ired to identify potential HRI opportunities, and to assess the performance, costs, and cost

- effectiveness of the available HRI methods."

Commenter s 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 prima rily 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 20 09, 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 p ower 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 t hat 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 degrad es 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 Sarg ent & 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 Commenter s 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. Commente rs 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 ass essment. 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 a nalysis 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.

Commenter s 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.

Comment ers 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 altern atives 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 alterna tives. 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 i mprovement 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 a nd 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.

Commenter s stated that in the preamble to the proposed rule, EPA stated that it "believes that impl ementation 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 he at 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
sta te 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 exp ected 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. C ommenters 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 th at 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

.
Commenter s 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 Preside nt, 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 utilities409 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."

Commenter s 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 stud y 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

- sp ecific 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 I mprovement Study at Coronado Generating Station (SL

012487), 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 coal

fired EGU's in Arizona. Commenters stated that EPA recognizes and acknowledges that this assumption has no basis "because the EPA expect s 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 refiner ies.") 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

- HQ

OAR

- 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 and410 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 upgr ades.

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. A s stated there, w e 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 mitig ate this degradation, and may need to more frequently replace components.

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

Commenter s 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 lo ng 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, u nits 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 h eat 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 cl ose 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 after411 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 hel p 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 s tated 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.

Commenter s stated that performance deg radation 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

.
Commenter s stated that EPA erroneously assumes that the initial payoff from any heat rate improvement project remains constant ov er 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 observe d 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.

Commenter s 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 de gradation, 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 equipmen t 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 tur bine).

Commenter s 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

- fire d 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 effici ency 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 coal

fired EGU turbines over the 10

- year performance period.

Commenter s stated that they ha ve 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 i n the integrated elec tric 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 i s reasonably achievable.

Commenter s 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 t his assumption is unsubstantiated and that t he heat rate of coal

- fired power plants naturally deteriorates over time and is not fully offset by routine maintenance and canno t be addressed economically with new equipment. Commenters stated that f or 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 t hat d eterioration 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 t hough 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

a ccordingl y, the heat rate improvement that EPA assumes existing coal power plants can achieve cannot be sustained due to natural degradation despite routine maintenance.

Commenter s stated that EPA attempts to support the achievability of Building Block 1 by re lying 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 peri od 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 through413 2012

- w hen 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.

Commenter s 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 frac tion 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 p lant 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."

Commenter s 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 turbin es, 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 continu ous 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.

Commenter s 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 turbi ne 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
sta ted 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.

Commenter s 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 obs erved at a unit.

Commenter s 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 est imate of a heat rate improvement is only for a414 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.

Commenter s 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 t echnology installed to reduce heat rate at an existing coal

- fired EGU, the unit heat rate initially obtained may increase over time

.
Commenter s 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.

Commenter s stated that heat rate improvements are not a permanent change to the performa nce 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 t hat 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 b ut at an unpredictable rate or time.

Commenter s 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 hea t rate improvement by means of CO2 emissions computation.

Commenter s 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 st ated 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 degra dation that the EPA has not factored into the rule but is a reality for coal

- fired units.415 Commenter s 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.

Commenter s stated that EPA ignores the fact that heat rate degrades over time.

Commenter s stated that the CPP did not take into consideration that heat rate improvement projects are not permanent and plant performance d eteriorates immediately following the completion of the improvement project

.
Commenter s 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 t hat 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 th at 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 impr ovement 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 inde pendent 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 out age (every 7 years).

Commenter s 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.

Commenter s 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 depende nt 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 emp loyed or the technology installed to reduce heat rate at an existing coal

- fired EGU, the unit heat rate initially obtained may increase over time.

Commenter s stated that the EPA did not take into consideration that HRI projects are not permanent in nat ure 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 emis sion
rates.

Commenter s asked why didn't EPA study heat rate improvements previously undertaken to assess degradation

.416 Commenter s asked why the EPA did not provide any follow up assessment of degradation of these HRI

.
Commenter s 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.

Commenter s 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 rat e 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 ove r 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. Comme nters stated that r outine 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.

Co mmenters 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 ti me. 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.

Commenter s stated that heat rate improvements do not remain constant, but degrade over time, ultimately increasing the rate and mass of CO2 emissio ns and EPA has falsely assumed heat rate improvements will remain constant.

Commenter s 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 t o 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. Comm enters 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 ex perience 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.

Commen ter s 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 des igned 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.

Commenter s sta ted 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 st ated 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.

Commenter s stated that in addit ion, 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.

Commenter s 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.

Commenter s stated that EPA's assump tion 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 upgrade s 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 achiev ed, coal

- fired EGUs would in fact have to achieve a HRI greater than 6% and continue to implement additional HRI over time.

Commenter s stated that EPA incorrectly assumes that coal

- fired power plants will maintain a heat rate improvement of 6%. Comment ers 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 yea r performance period. Commenters stated that the heat rate improvements that coal

fired power plants can achieve through the installation of new turbines, rotors, economizers, fans, and other such equipment necessarily will decline over time. Commenters st ated that such declines are due to natural degradation of new equipment, installation of new pollution control418 technologies that impose parasitic loads, and changes in the way that the power plant operates in response to market evolution and changing custo mer demands.

Commenter s 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.

C ommenter s 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, operat ion 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 stat ed 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.

Commenter s stated that EPA erroneously assumes that hea t 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. coal

fired 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 improvi ng 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.

Commenter s 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 clea n 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 ef fectively irreversible. Commenters stated that EPA ignores this reality, and therefore its assumption that heat rate gains accumulate and last indefinitely is simply incorrect.

Commenter s 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 w hy EPA did not consider degradation as a variability fact or

.419 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 Mitiga tion 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 t ake into account the potential heat rate improvement of individual EGUs

— should states desire to consider potential heat rate improvement at all. Furthermore, i f an affected EGU cannot meet the particular emission standard solely because it has below

- averag e 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 summari es of the specific public comments under this c omment :

Commenter s 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 larg e 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.

Commenter s stated tha t 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 roo m 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, Equi pment, Water Treatment System.

Commenter s 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 referre d 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 improv e 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 f urther 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 of420 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 conti nue to implement best maintenance and operating practices on all four Units to reduce significant degradation on their heat rates.

Commenter s stated the changes to the units' heat rates based on the modifications implemented at CGS as well as the pote ntial 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. Comment ers 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.

Commenter s stated that in addition to the numerous steps voluntarily undertaken by Heartland to promote renewable energy and ener gy 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 Propo sed 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 achiev ements 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 similarl y, 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 so rt 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 shortc omings 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 emissi on 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).421 Commenters stated that WEC2, l ocated in Nebraska, is owned by five public power utilities, including Heartland, which formed the Public Power Generation Agency ("PPGA"), an inter

local agency established in Nebraska for the sole purpose of constructing and operating WEC2. Commenters st ated 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 facilit y. 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

a vailable 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 s pecifically, 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 s team 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 de scribed 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 Nebrask a 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 un it 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 B uilding 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.

Commenter s stated that Wisconsin electric utilities are regulate d by the Public Service Commission of Wisconsin (PSCW). Commenters stated that t hrough 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 an d 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 EGU s.

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 conve rted 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 t he 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 sootblow ing 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 p otential 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 achieva ble 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 us ed 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.

Commenter s stated that Great River Energy's Coal Creek Station exem plifies 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 practice s 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.

Co mmenter s 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 pow er 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, i s 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. Com menters 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 he at 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 pla nts 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 th e 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 t herefore, the h eat 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 mis attribution of improvements from "best practices" to "equipment upgrades" and vice versa

Response 49 : For the EPA’s respons e 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 c omment :

Commenter s 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 pract ices (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 rat e 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 bette r 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.

Commenter s stated th at 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
appr oach 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 properly425 be attributed to these "equipment upgrades" or vice versa. Commenters noted that turbine overhauls are already routinely done on most EGUs t o 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
up grades" 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.

Commenter s 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 he at 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 individ ual 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 c omment :

Commenter s stated that EPA's 6 percent figure is based in part on a misc haracterization 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 coal

fired EGUs can achieve a 6 percent heat rate improve ment, 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 improvemen ts 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 im proving 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.

Commenter s state d 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 were426 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.

Commenter s 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 reduci ng 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 low er 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.

Comme nter s 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 particu lar, 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.

Commenter s 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 b ased 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 th erefore 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 doe s 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 i n 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. Commen ters stated that a lso, 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. See427 NCC Report at 71 ("The benefits and cost are hig hly variable and depend on the specifics of any one site."). Commenters stated that f or 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 fre quency drives depend heavily on existing equipment. Id. at 62, 65

- 66. Commenters m oreover 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. Cich anowicz Statistical Critique at 10 (discussing achievability of 2 percent heat rate improvement through "equipment upgrades").

Commenter s stated that the combinations of several heat rate improvement projects by percentage are not additive in nature fo r 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 r ate 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 time s 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.

Commenter s 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 201 4 GHG TSD. Commenters stated that e ach 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 "pay off" of another, such as intelligent sootblowing; neural net software, and ESP modifications.

Commenter s stated that EPA's assessment of available heat rate improvements through "equipment upgrades" is arbitrary. Commenters stated that t he 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
percen t because "some units may have applied at least some of the upgrades." Commenters stated that t his methodology erroneously assumes that the heat rate improvements from these upgrades are cumulative and that they provide consistent long

- term benefits. Comme nters stated that i n 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 ser vice. Commenters stated that EPA cannot require affected EGUs to duplicate emission reductions they have achieved using measures they have already taken.

Commenter s 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 projects428 designed to improve heat rate. Commenters stated that while so me 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 imp rovements are not necessarily additive." Commenters stated that as Cichanowicz & Hein showed, the benefits of different efficiency measures are not cumulative.

Commenter s stated that while EPRI studies indicate there may be opportunities to achieve a

v ariety 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.

Commenter s 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 t his assumption is flawed. Commenters stated that m any of the heat rate imp rovement methods that EPA identifies cannot be combined and are not cumulative. Commenters stated that i n other words, once the improvement is achieved by one method, another method cannot achieve the same or similar improvement.

Commenter s 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 alternativ es 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 alternative s. 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.

Commenter s 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 r ecommendations 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 available429 Response 51 : See section V.C of the final rule preamble of the CPP and C hapter 2 of t he 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 c omment:

Commenter s describe d 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 f or example, Sherco Unit 3 in Minneso ta 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 i mproved 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 f or example, Iatan 2, Plum Poin t, and Prairie State units all came online in the last three years and all have the most efficient technology. Commenters stated that t here is no improvement technically available for these units regardless of cost and that was not factored into EPA's base line calculations. Commenters stated that t he Agency should adjust its assumptions to take into account units that do not have any efficiency improvement technically available.

Commenter s 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.

Commenter s stated that heat rate improvement opportunities depend on the original design of the unit, including space constraints. Commenters stated that s ome 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 c ompliance 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 c omment :

Comme nter s stated that there is no evidence that EPA considered the impact of retiring coal units on the results of the analyses. Commenters stated that i f a unit closes, there can be no HRI potential at that unit. Commenters stated that EPA ran a sensitivit y analysis that excluded units that have announced retirement dates before 2016. See Abatement Measures TSD at 2

- 35. Commenters stated that h owever, 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 p resumably, these units have higher design heat rates because they are older and that

a ccordingly, they might ap pear (statistically) to have significant HRI potential, but this potential will not be realized if these units retire. Commenters stated that t herefore, EPA should exclude430 these 46

- 49 GWs when assessing the future HRI potential of the existing coal

- based f leet. Commenters stated that i nclusion of these units likely inflated EPA's assessments of HRI through O&M "best practices."

Commenter s stated that EPA's assumed 4% to 6% efficiency improvement target at existing coal plants is not achievable in part b ecause 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.

Commenter s stated that while it is possible or e ven 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
t he rule pr eamble 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. Commenter s stated that specifically in Washingt on, 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 h eat rate improvements are intrinsically a pollution prevention type of emission control. Commenters stated that a ll 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 pe riod. Commenters also stated that f or these situations they suggest that EPA consider excluding specific heat rate improvements for those units when the effects of building block one are calculated.

Commenter s stated EPA's evaluation of historic heat r ate 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 a ge

- 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 operatio n during the period affected by the guidelines.

Commenter s 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 introdu ced a strong conservative bias to the analysis.

Commenter s stated that after announced and planned retirements, there will be very few, if any, uncontrolled coal

- fired units operating in Ohio after 2016

.431 Commenter s stated that in their analysis of e xisting 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 w hile this assumption may be achievable, they instead evaluated the decisions that th ey ha ve 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 reduct ion 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 l bs/MWh, a decrease of 52 lbs/MWh.

Commenter s 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 affecte d 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. Commen ters 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 sta ted 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 20 30 emissions goal by either removing the interim goal or phasing in all Building Blocks

.
Commenter s stated that the EPA should not have considered units that are expected to close when assessing fleet

- wide heat rate improvement potential through statist ical 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 to432 operate at relatively low capacity factors and accordingly, they might appear (stati stically) 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 c oal

- based fleet and inclusion of these units likely inflated the EPA's assessments of available HRI through O&M "best practices."

Commenter s stated that they are concerned that HRI measures made at the coal

- fired utilities prior to 2012 cannot be cons idered 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 stat ed 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

.
Commenter s stated that EPA's broad application of the heat rate improvement assumption fails to consider planned retirements for coal units prior to 2020

.
Commenter s stated that EPA has relied on outdated information and reports to justify its proposed 6% (or 4%) heat r ate 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 be ing 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 operati ng. 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.

Comm enter s 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 wh ereas 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

- spec ific, as shown in EPRI studies and that the maximum potential improvement depends on the condition and operation of the unit.

Commenter s stated that in addition, any fossil

- fuel EGUs (coal

- fired) that are planning to retire as a result of USEPA regula tions (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,

res ulting in substantial reductions in CO2 emissions from these to

- be

- retired coal plants.

Commenter s stated that no improvements should be assumed for units that have firm commitments to retire or fuel

- switch to natural gas before 2020. Commenters provid ed a433 summary of Alliant Energy's current announcements that should be excluded from the EPA's estimated Block 1 heat rate improvements.

Commenter s 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.

Commenter s 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.

Commenter s stated that coal units that are expected to retire soon could have d istorted 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.

Commenter s st ated 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 giga watts 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 rapid ly 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 a nticipated 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
capac ity 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 mea ns 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 substant ial change in the composition of the grid's generation units will affect reliability and costs.434 Commenter s stated that in the State Agencies' comments, they argue that there is little incentive for upgrades to existing coal units, because they will hav e 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 outl ined 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 t he 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 carbo n emissions than the heat rate improvements assumed by EPA in its development of Building Block 1 for Nevada.

Commenter s stated that EPA also attempts to look at the entire "existing" pool of coal fired units for heat rate improvement opportunities, ho wever, 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 t o 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 i mprovement target is unrealistic for the remaining fleet.

Commenter s 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

- b urning 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.

Commen ter s 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 t hat 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. Commente rs 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 progr ams (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 th at in addition, SPP says it "used current load forecasts supplied by SPP members, currently planned generator retirements, currently planned new generator capacity with GIAs [generation

interconnection 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 interconnec tion 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 ret irement 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 renewabl es (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 that436 En tergy'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 appa rently 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 plan t. 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 commenter s ' 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 t o purchasing and running underutilized gas plants, converting White Bluff to burn gas, or even building new gas combined cycle capacity. Commenters stated that c ommenters reached those conclusions with a forecast of gas prices reaching $10/MMBtu in 2020; g as 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. Comme nters 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 wi nter.

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 r elied 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.

Commenter s 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 CO 2 emissio n 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.

Commenter s 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. Comm enters 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 2012437 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.

Commenter s stated that EPA should exclude coal

- fired EGUs that will be retired before 2020 in calcula ting the heat rate improvement target for each state.

Commenter s 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 li fetime 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 e xpected 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 h ave 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 a ir 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 tha t 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 ba seline 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 fact ors 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.438 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 unit

specific requ irement 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 poten tial heat rate improvement on a regional basis.

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

Commenter s 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 h owever, 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 h owever, the numerical values for separate heat rate improvements may not be additive. Commenter s stated t hey also may not be achievable or justifiable at every coal

- fired plant. Commenters stated that i n 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 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.

Commenter s 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. Commenter s 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.

Commenter s stated that EPA states it has independently analyzed the improvements in gross heat rate that can be achieved by reducing vari ability 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 conclusio n regarding the improvements in gross heat rate that could be achieved by439 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.

Commenter s 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) uni t 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 sh ould be evaluated individually to determine what cost effective improvements are available at each unit. Commenters stated that b ecause of the variation among units, requiring a universal 6% heat rate improvement is unrealistic.

Commenter s 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 anal ogy 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 i mprove, 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 h er 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 one

size

- 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% HR I without regard to what is technically achievable at a given EGU is arbitrary and should not be included in the Final Rule.

Commenter s stated that the same solution cannot be applied to all units as each facility is different and to obtain reliable in formation on achievable heat rate improvements, each unit should be evaluated individually to determine what cost effective improvements are available at440 each unit. Commenters stated that b ecause of the variation among units, requiring a universal 6% heat rate imp rovement is unrealistic.

Commenter s 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 s upport the case that all coal plants in the country are capable of this level of improvement.

Commenter s 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.

Commenter s 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

.
Commenter s 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.

Commenter s believed that it is inappropriate for EPA to apply a nationally assumed HRI to each state, given the unknown technical feasibility o f 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 coal

fired 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 ful l consideration of the drivers of net generating efficiency.

Commenter s 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.

Commenter s 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. Comm enters stated that m oreover, 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 add ed that because the EPA has not adequately demonstrated that heat rate441 improvements can be made to any specific EGUs in Kansas, the y ha ve set the heat rate improvement increase in efficiency to zero percent for Ka nsas's affected EGUs.

Commenter s 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 le ast, 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 reduct ion.

Commenter s stated that realistically, 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 impro vement is not achievable for coal

- fired EGUs as a category.

Commenter s 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 o ne 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 i nformation that accounts for differences in achievable heat rate improvements.

Commenter s 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 maintenanc e and normal operating procedures, and the temporal variation of the payoff reduce the system

- wide, long

- term target.

Commenter s 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 over looked 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 improve ment 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 t hat 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 on442 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.

Commenter s s tated that the Wyoming Public Service Commission and the Wyoming Department of Environment al 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 o f them, not just the technologies highlighted by EPA. Commenters stated that the reason for the disparity between EPA's 6% estimate and the c ommenter s ' 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 an d 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 w hile "[t]he heat rate improvement for the study population is derived fr om 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 ave rage.

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 reas onably 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 result s 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.

Commenter s 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 descr iption than the national average and the goals for those states, therefore, will be arbitrarily strict.

Commenter s stated that EPA's generic conclusion that the coal fleet as a whole can improve efficiency by 6 percent fails to recognize that the poten tial for efficiency improvements is highly443 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 improve ments] 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, sy stem 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 wh ile 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 existi ng 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 f or 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 efficienc y, and periodic turbine overhauls are already a best practice. Commenters stated that

s ite

- specific engineering analyses would be required to determine any remaining opportunities for economic heat rate improvement measures." Commenters stated that similar ly, 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."

Commenter s 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 h ave 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 prese nts 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 p lant 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 a nalysis at each existing source to render an appraisal of potential improvements that is more sensitive to real present

- day circumstances in Indiana.

Commenter s stated that EPA's erroneous 6 percent figure is apparently based on its incorrect assumptio n that all the heat rate reduction strategies discussed in the 2009 Report can be applied at all coal

- fired units. Commenters stated that t o the contrary, "[a]ll efficiency improving measures are unit and site

- specific and will not always be technically an d/or economically feasible." Commenters stated that therefore, the 2009 Report does not support EPA's 6 percent figure

.444 Commenter s stated that heat rate is not a constant value and compared it to the fuel efficiency rating of an automobile. Commenters f urther 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 p oint ed 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 i dentified 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.

Commenter s 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), a nd 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 wh ile 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.

Commenter s 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. Commenter s stated that their analysis demonstrated that the 2 001 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 que stion 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

- fire d 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 co ntinue 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 contro ls 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.

Commenter s stated that more robust an alyses of the potential improvements in heat rate of coal

fired 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 overlo oked 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 t his is a recurring theme throughout the analysis, and is intuitive: when efficiency improvements are performed at an existing coal unit, th ere 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 re trofits, 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.

Commenter s 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.

Commenter s stated that further, these cited improvements were determined on an industry

- wide aggregate basis and therefore, they apply we ll 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 achi evable for each.

Commenter s 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 gen eration 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 stat ed 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

-446 fired pla nts 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 s tated 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 state d that to resolve this technical feasibility concern resulting from "fleet

- wide" assumptions being applied to a small cohort of units, the y recommend that EPA consider an incremental approach to Building Block #1 so that there would be no reductions associ ated 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 a nd would support EPA's intention to avoid setting emission standards on a plant

- by

- plant basis.

Commenter s stated that EPA has determined in some cases an efficiency improvement of 4

- 6 percent is achievable and automatically assumed that such improveme nts 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 f actors such as age, basic design, location, fuel, type of service and m any 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, Virg inia will be forced to mandate further reductions within other "building blocks" that are equally or even more challenging.

Commenter s 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.

Com menter s 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 su ggesting that emission reductions of 6 percent are achievable by any source, let alone by all existing sources across

- the

board 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 their447 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.

Commenter s stated that the EPA assumes the industry can improve heat rate by 6% over the entire coal fired power plant fleet. Commenters stated that a lthough there may be an isolated generating station that can accomplish that goal they believe it is the exception ra ther than the rule. Commenters stated s pecific targets should be set on each unit's specific characteristics and credit given based on past improvements.

Commenter s stated that since it is recognized that each EGU is unique as to how much HRI can
actua lly be realized, c ommenters 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 degre e of heat rate improvement which could be achieved by that EGU, and would be included in the state's plan as such.

Commenter s 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 a nalysis 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.

Commenter s stated that more importantly, however, pot ential 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 al so 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 o perations.

Commenter s 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 ind ividual EGU in the computation of heat rate improvement goals under building block 1.

Commenter s 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

- u nit basis as prescribed by section 111(d) and stipulate that improvements will not trigger a New Source Review.

Commenter s stated that a more careful analysis of the availability of heat rate improvements suggests that applying a blanket average percen tage is improper; instead, the amount of448 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.

Commenter s 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.

Commenter s 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.

Comme nter s 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 state d that under the proposed guidelines, forward

thinking 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 adde d environmental controls, and other factors, such as consideration of variable dispatch effects on efficiency that are specific to EGUs within each state and region.

Commenter s stated that the proposed guidelines set a uniform rate of 6 percent on a na tionwide 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 perc ent 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 n ational 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 technically449 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 constrai nts. 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 c urrent 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 d esign 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 tec hnical 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 state d 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 appr opriate 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 recommend ed EPA to evaluate sp ecific 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.

Comment er s 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.

Commenter s 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 regar ding 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 fle xible 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 co al450 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 tar geted to those facilities capable of making such efficiency gains while recognizing the capital investment made by those plants already realizing such efficiency improvements.

Commenter s 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 tha t are already more efficient, EPA should evaluate heat rate improvement capability at indi vidual coal

fired 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 ba sed 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 base d 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 t he 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 c omment :

Commenter s 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. C ommenters 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 impro vement, 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.

Commenter s 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 the451 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 n ot 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 preli minary 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 improvemen ts 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. Commente rs 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.

Commenter s stated that the EPA should acknowledge tha t 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.

Commenter s stated that EPA does not take into account all of the variables that can affect heat rate, including coal q uality, boiler design, and unit size. Commenters stated that f or all of these reasons, site

- specific analyses are critical for understanding actual heat rate improvement potential.

Commenter s 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 i n 1980, the y develo ped 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 u nit specific heat rate and availabili ty requirements are set annually through a formal hearing procedure, and the y ha ve the authority to reward utilities that reach their requirements and penalize those utilities that do not. Comm e n ters stated that e ffectively, 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 i n over 30 years of offering incentives, the y ha ve not seen consistent heat

- rate improvements in the six percent range as suggested in the Proposed Rule. Commenters stated that i n the last five years alone, changes in EGU specific heat rate efficiencies ranged from negative eight percent to positive four percent, e ven with the GPIF program incentives. Commenters stated that t hese fluctuations appear to be driven, in part, by452 efforts to comply with environmental requirements. Commenters stated that r ather than relying on an across the board six percent assumption, th ey propose a more Florida

- specific analysis of achievable, permanent and cost

- effective CO2 emission reductions. Commenters stated that s uch an analysis will take into account, not only potential for heat rate improvements (which can be verified through hi storical 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.

Commenter s 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 eco nomic 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, e tc.) 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. R egional 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 respecti ve generating fleets.

Commenter s 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 demonstrate d 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.

Commenter s 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 operat ed 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 an d 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 efficien cy 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 to453 improve the efficiency at one coal

- fired EGU facility may not necessarily directly transfer to a coal

- fire d 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 holistic ally 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 envi ronmental 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

v endor 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 th at, 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 assessmen t is grounded in uninformed and inaccurate assumptions and conclusions that454 reflect an incomplete understanding of the nature, cost, and availability of potential heat rate improvement opportunities.

Commenter s stated that, should the improvements in Block 1 prove attainable, the EPA estimates a 30 lbs/MWh reduction in Florida's CO 2 emissions. Commenters stated that the EPA estimates the cost of implementing heat rate improvements at "relatively modest capital costs" o f $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 describe d 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 thro ugh 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 i ncentives 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 tak en 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.

Commenter s stated that in summary, while there is a basis for considering heat rate perf ormance 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 stat ed 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 state s can set attainable standards of performance on a case

- by

- case basis for each affected existing source within its jurisdiction.

Commenter s stated that EPA asserts that it is possible under Building Block 1 to achieve overall HRIs of 6% (or 4% under th e 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 un it

- 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 op erating in South Dakota455 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.

Commenter s 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) th e 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.

Commenter s 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 high er 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 w hile 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 bi tuminous 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 estimating456 HRI; (2) ability for gener ation facilities to support investment in HRI equipment; and (3) the impact of regional load factors on HRI.

Commenter s 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. Commenter s 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. Commenter s 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 ac tual data, what the appropriate HRI should be.

Commenter s 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 uni t, state, regional, and national levels.

Commenter s 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 Propose d 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 tha t 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.

Commenter s 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 Comm onwealth 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 the ir facility. Commenters stated that moreover, crucially, any BSER must conside r 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. Co mmenters 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 the ir facility. Commenters stated that in support o f 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 BSE R 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 tha t 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 improvement s at their plant without first457 having a specific engineering analysis of the ir 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

- fi red EGUs would require a "detailed site

- specific analysis" that considers, among other factors, "plant design, previous equipment upgrades, and existing operation and maintenance practices."

Commenter s 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.

Commenter s 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.

Commenter s stated that EPA should allow states to propose heat rate improvement targets that are appropriate to their coal

- fired pow er 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 l imitations 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.

Commenter s stated that to addres s 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

exe mpt 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 th at 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 th e 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 improvem ents 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 a nd 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 local458 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 sig nificantly 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 the se 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 refle ct these kinds of unit and state specific concerns.

Commenter s 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 feasib ility, cost and remaining useful life of each unit as Section 111(d) requires.

Commenter s 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 state d 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.

Commenter s 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 Build ing 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 sug gested that the analysis be done as part of the state's Section 111(d) plan, and that the goals be adjusted accordingly.

Commenter s stated that coal

- fired EGUs are subject to air regulations that have required the installation of controls over the last decade. Commenters stated t hese 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 resulte d 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

- u nit 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 their459 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 t hat 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 g oal, 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.

Commenter s 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 aff ected unit based on a case

- by

- case assessment of the unit's history, boiler configuration, fuel type and remaining useful life.

Commenter s 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 poten tial 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 requ irement 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 variabl e 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. Commenter s stated that EPA must be consistent in its development of BSER across the building blocks. Commenters stated recommend ed EPA to consider HRI loss over time and variability at the unit level and adjust the proposed BSER accordingly or finalize the 6 percen t, 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 demonstratio n 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 C hapter 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 c omment :460 Commenter s 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 11 1(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 st rategy 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 arbitr ary and unsupported in practice

.
Commenter s 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 impr ovement (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 Electri c 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 evalua tion "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 i mprovements 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 i mprovements 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.

Comme nter s 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; oper ating/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 b e 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, full

load, steady

- state condition and is considered the best a unit could potentially a chieve 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 h eat 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.

Commenter s stated that th ey 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 Chol la 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 improve ment 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 tha t 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. T he c ommenter s 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 pr oposed 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 de termined 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.

Commenter s 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 achiev ed 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 wheth er best practices are being used. Commenters stated that a unit

- by

- unit analysis is important because utility maintenance practices vary based462 on their different circumstances and operating and maintenance best practices may have already been developed and implemented

- as they have been at Southern Company.

Commenter s 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).

Commenter s stated that NERC is concerned that the assumed improvements may not be realized across the entire g eneration fleet since many plant efficiencies have already been realized and economic heat rate improvements have been achieved. Commenters stated 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 s ite

- specific engineering analyses would be required to determine any remaining opportunities for economic heat rate improvement

measures.

Commenter s stated that EPA's methodology in calculating its prop osed 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 th at 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." Comme nters stated that NERC notes that "[s]ite

- specific engineering analyses would be required to determine any remaining opportunities for economic heat rate improvement measures."

Commenter s 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 ha ve app roved 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. Commenter s added that working toward a six percent improvement will require detailed analysis at each coal unit to determine the realistic heat rate improvements, whereas appl ying a general standard across various technologies and unit ages masks the true potential gains that could actually be achieved by an individual state. Commenter s 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.

Commenter s stated that the 6% e fficiency 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 performed463 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.

Commenter s 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 energ y 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 i t 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 2 012 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 achi eved 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 a lready 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.

Commenter s stated that since EPA did not provide the data for individual EGUs analyzed in its statistical approach, they w ere 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 state

level 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, SO 2, 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 ca pacity than previous years. Commenters stated that despite this change, North Carolina's state

- wide average heat rate46 4 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.

Commenter s 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 no t 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 imple mentation;

• 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 technolo gies 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 h owever, this past practice means that every well

- maintained unit likely has implemented several co st

- 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 fact ors 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 ("T urk") that began operation in 2012 represents a state

- of

- the

art ultra

- supercritical steam cycle, which is a design that produces higher steam temperatures and pressures than is typical in most units. Commenters stated that t he result is that the Turk Plan t 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

- supercri tical 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 t hat 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 characteris tics, 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 vari ations 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 c onsidered 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 oper ated and maintained differently.

Commenter s 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 newest466 coal

- fired power plants in the country and has demonstrated some of the lowest emi ssion rates for S O 2, 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 absor ber for S O 2 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% impr ovement 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 insta lling 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 P ower 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 incor porated in the GHG Abatement Measures TSO. Commenters stated t he 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 ra te. 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 thi rteen 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.

Commenter s 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 ha ve 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 ha ve also insta lled 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 w hen their Kingston Coal Plant added scrubbers, the unit heat rates increased by 4

- 6%. Commenters s tated that i ncreasing a unit's heat rate also increases the CO2 emission rate. Commenters stated that EPA should specify in its emission guidelines a467 methodology for including unit efficiency improvements in state plans. Commenters stated that
t he States s hould 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 a n important factor is how dispatch significantly impacts efficiency

Commenter s 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 base

loaded 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.

Commenter s 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 site

specific design.

Commenters prov ided 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 reduction s 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 electrost atic 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 pri marily to the installation of wet FGD and SCR systems. Future potential heat rate improvement is limited to 0.6%.468 • 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 ra te 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 m ay 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 op erating 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.

Comme nter s 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. C ommenters 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 con current 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 assoc iated 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 equ ipment 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 sta ted that as a result, the total auxiliary load469 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 exp ected 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. Commenter s 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 u sing 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 deg radation 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.

Commenter s stated that opportunities for increasing the energy efficiency of the existing coal

fired 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 ha ve 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 pu mp 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;470 • Coal pulverizer flow and balance studies to improve boiler combust ion;

• 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 consu mption 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 complete d 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 upgr ades/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 CO 2 Performance Goal calculation purposes, EPA must recalculate t he goals using a realistic overall 1 percent heat rate improvement for both units.

Commenter s 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 nece ssary 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. C ommenters stated that accordingly, a "uniform" methodology is not appropriate for setting realistic efficiency improvement goals for each state/utility.

Commenters stated that they ha ve already completed turbine overhaul projects on most of its units and t his 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 b ased 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. Commenters471 presented Table 1 "Best Practices" from the Sargen t & 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 tange ntially 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.

C ommenters 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 th at 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 i s mainly an impact on auxiliary power from fan loading. Commenters stated that air hea ter 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 add itional 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 expe cted 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 woul d 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 a ir 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 emissio ns. 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%. Commenters472 stated that this is due not only to optimization, but also to the PRB coal th at 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 t hey 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 r esult 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 ha ve invested a tremendous amount of capital t o ensure that it is operating at an optimal efficiency because this approach is not only good for the environment

- it is good for business.

Commenter s 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 practic es" 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 coal

fired generators to adopt state of the art operational strategies and technolog ies 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 competiti ve economic nature of the ERCOT market, FPP has already identified and implemented "best practices to reduce hourly heat rate variability."

Commenter s stated that Florida utilities, including their plant have already taken steps to improve heat rates a nd 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 unde rtook 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 t h e unit would have to be completely replaced.

Commenter s 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 t his study compares EPA's claims of heat rate improvement of 6% at an average power plant with a detailed study of473 the a ctual 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 Po llution 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 guide lines 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 se ctor, including existing fossil fuel

fired 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 C O2 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 i n 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

ea ch 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 provi de 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 estimate d 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 equ ipment 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 percen t 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 is474 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 imp rovements 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. Contr ary 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 co sts 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 do es 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 limi tations 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 Commente rs 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 o f 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)

Commenter s 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 ge neration 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 con cern 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 th at nonetheless, assuming that EPA corrects its clear errors regarding achievability and reasonableness of CO 2 emission reductions through dispatch changes among affected EGU's under "building block 2," SRP requested that RTP prepare this analysis. Commente rs 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_H Q_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 CO 2 emission rate of the fleet of twelve coal

- fired EGU's i n 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 fina l 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/M Wh 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 rate476 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 coal

fired EGU's in Arizona clea rly 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 r ate 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 rel ated 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 c omments regarding costs of this rule overall is addressed in section 8.0. For EPA’s response to the remainder of these comments, s ee section s 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 pre amble 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 c omment :

Commenter s stated that even if EPA had authority to regulate these p ieces of equipment under Section 111, its technical conclusions are erroneous. Commenters stated that a s discussed by UARG's consultants

, J. Edward Cichanowic z 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 l arge benefits fro m 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 m any of the available heat rate improvements for whi ch 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 Commenter s stated that the c osts to improve heat rate are unit

- spec ific; 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 e conomy of scale also plays a role, as the expendi tures are more easily justified for larger units with higher capa city factors.

Commenter s 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. Comm enters 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.

Commenter s 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 trig ger onerous New Source Review permitting requirements.

Commenter s 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.

Commenter s 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 increa ses of 1% or 2% would be extremely expensive.

Commenter s stated that a cost

- benefit study would need to be conducted for each specific coal

fired unit to determine if any achievable heat rate improvements can be economically justified.

Commenter s s tated that a 6% heat rate improvement target is not reasonable for smaller generating units. Commenters stated t his 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 c ustomizing equipment to accommodate small unit

- specific requirements adds to cost, if such equipment is available at all.

Commenter s 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 th ese 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 fou r 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 st ill 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) ; commenters478 expec t 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 a nd will produce greater savings in conserved fuel.

Commenter s 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 inc reased." 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 cost

effective "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 alr eady occurred.

Commenter s 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 project s for their fossil

- fueled EGU fleet, and cannot expect to see substantial increases from future improvements without significant cost s

.
Commenter s stated that the incremental cost of improving heat rates further may be significantly higher for generati ng 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.

Commenter s stated that the finance requ irements 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 reasonab le 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 C hap ter 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 c omment :479 Commenter s stated that Building Block One presumes that coal

- fired power plant owners are not sufficiently motivated to improve h eat 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 co st 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 h eat rate, doesn't this report suggest that utilities are already pursuing whatever i nvestments 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 alrea dy 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

co mmenters . 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 c omment :

Commenter s 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. C ommenter s stated that acknowledging that "climate change" is a global phenomenon with480 extraordinary political, social, and economic ramifications, focus on the controls of CO2 should be on cost effective reduction s overall. C ommenter s 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. C ommenter s 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. C ommenter s stated that there is a net benefit relative to CO2 emissions, at lower marginal cost.

Commenter s 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 t o 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.

Commenter s stated that EPA recognizes that improving a unit's heat rate likely will mean that such a unit is more econo mical 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 (als o 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 unreal istic 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 contemp lating 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 coal

fired capacity, though cleaner with respect to CO2 intensity, should only be a conc ern 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 co st 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. Comment ers 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. C ommenters 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 discusse s 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 c omments 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 t hings,
t hose 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 impro vement of individual EGUs

— should states desire to consider potential heat rate improvement at all. Furthermore, i f an affected EGU cannot meet the particular emission standard solely because it has below

- average potential to reduce emissions through heat r ate 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 c omment :

Commenter s 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 si gnificant 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 dimin ishing portion of the generation mix in New York. Commenters stated482 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 thes e 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, a nd 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 hav e predictably increased . Commenters presented F igure 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 perio ds 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 ope rate 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 contemplate s 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 assum e 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 state s like New York where an already low utilization rate is not conducive to heat rate improvements.

Commenter s 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 w ould 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 f ive out of six coal plants in Louisiana are already beyond their designed life expectancy. Commenters stated that these plants will need turbine, boiler, and
ot her infrastructure replacements that are estimated to cost as much as a new CCGT power plant483 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 i mplemented. 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, uti lities 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 )

. Commenter s 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.

Commenter s stated that improvements from equipment upgrades would unavoidably re quire 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 pl ants at or beyond the end of their

econ omic 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.

Commenter s 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

Commenter s 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 reliabil ity 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 loa d factors to cost

effectively 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 C O2 emission rate in a cost

- effective manner.

Commenter s 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 compet itive 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 cou ld 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 dif ficult 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.

Commenter s 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 co ncerns 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 So uth 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 pr oposed rule exacerbates the inequity between regulated and restructured states

Comment 5 : Comments regarding HRI capital cost assumption s
Response 5 : For the EPA’s response to these comments, see section V.C of the final rule preamble of the CPP and Chap ter 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 offe red sufficient information to suggest otherwise.

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

Commenter s 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 n either of EPA's assertions about HRI costs is reasonable. Commenters stated that f irst, 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 t his cost data is nearly five years old and t hat 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 s econd, EPA's core argument in support of the reasonable cost of the HRI is that "any heat rate impr ovement 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 u sing cost estimates from the S&L report, EPA calculates an annualized cos t per kilowatt hour (kWh) of HRI measures. See I d. Commenters485 stated EPA then calculates an annualized fuel cost to estimate the average fuels savings related to a six percent HRI.

Commenter s stated that EPA's capital analysis relies on a 2009 report is sued 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: upg raded 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 red uction 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 est imate 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 coin

flip, indicating that EPA does not have any basis to estimate, liberally or conser vatively, 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

- effec tive as EPA claims.

Commenter s 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 t hat state' emission rate goals accordingly.

Commenters stated that while incentives are already in place for their facilities to make cost

effective, efficiencies improvements, in an initial analysis, they ha ve identified 35 additional, specific projects t hat 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 m any 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 the ir coal plant heat rate by,486 at best, 1.6 percent. Commenters stated that t he to tal capital cost of these projects is estimated at $60 million with a $2.5 million annual O&M cost.

Commenter s 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.

Commenter s 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.

Commenter s 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 E PA 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 examp le 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.

Commenter s stated that heat rat e 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 i mprovement 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 improve ment 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 effi ciency improvements obtained by installing IS B 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 wou ld 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.

Commenter s 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" a ssume 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.

Commenter s 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 f

or 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 a ll 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 t o 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 th at 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.

Commenter s stated that EPA assumed 6% improvement could be achieved at a capital cost of $1 00/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 g enerators 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 al ternative 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 i n their estimate of the overall energy system cost of the CPP in the unconstrained scenario. Commenters stated that although they w ere 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 signifi cant 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 in488 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.

Commenter s stated that EPA states that an additional 2% of heat rate improvements to get to 6% are available with some expense (presuma bly, 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

.
Commenter s 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 thi s 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 ba ck 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 de sign 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 boile r 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. Technologie s 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. Commenter s 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 co uld 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 investi gated 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 5 00 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.

Commenter s 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 r ecent 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.

Commenter s 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 equipm ent, material, and labor at the time of the490 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 mos t 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 state d 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 questio n 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 econom ically driven operating practices without a clear identification of benefits.

Commenter s 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 ins talled 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 rat e 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 f uel 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 f rom 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 p roposed six percent improvement are significantly more challenging due to significantly lower fuel costs for their plants.

Commenter s 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 i nput. 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 capit al 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 overlappin g 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 r educed 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.

Commenter s s tated 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 relie d 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." Commenter s 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 Propos ed 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.

Commenter s 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 th is 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 th at 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.

Commenter s st ated 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 w ill 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 and492 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 HR I 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 prod uce 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 s avings 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, i t 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
expen ditures 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 capit al 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 meet ing 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 recogni zes 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 achi eving 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

- wou ld 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.

Commenter s stated that EPA's capital analysis relies lar gely 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 vari able 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 g enerators: "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 assumption s cannot reasonably be said to be "conservative," because EPA does not have any identified basis to493 estimate, liberally or conservatively, how many coal units may already have undertaken these projects.

Commenters stated that coal

- fueled EGUs in North Dako ta, 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 r elied on 2008 data, four years prior to the baseline EPA assumes in its building block formula. Commenters stated a s that report stated, "[a]ll estimated capital and installation costs are referenced from work in progress and vendor quotes as of the year 2 008." 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 tha t 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 disad vantages 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."

Commenter s 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 o f 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 als o acknowledges that "[its] simplified cost analysis...will represent the costs for some EGUs better than others because of differences in EGUs' individual circumstances."

Commenter s 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 ha ve 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 tha t in addition, long term recommendations regarding turbine performance were made that can only be addressed during turbine overhauls. Commenters stated that they continually replace d leaking valves during outages, improvements were made in the combustion o f 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 routine494 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 estimate d 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.

Commenter s 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, the y ha ve 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 ut ilities 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 cleanin g 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.

Co mmenter s 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 uni t heat rate is compared to a best achievable heat rate.

Commenters stated that they ha ve 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 plant s 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 equipm ent or operating deficiencies. Commenters stated that efficient operations ha ve always been a focus of the ir plant staff so it will be difficult to identify any heat rate improvement projects which would not require significant capital investment, extensiv e modifications and environmental permit changes.

Commenter s 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 generati on 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 induce d increases in495 NGCC capacity factor. Commenters stated that in addition, if coal plants are forced to cycle more, heat rate efficiencies could deteriorate further.

Commenter s stated that EPA also fails to appreciate the magnitude of upfront capital cos ts 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 coal

fired 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 main taining that such upgrades will eventually pay for themselves through increases in power generation efficiency.

Commenter s 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 ha ve 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 appli cation, 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 list s potential NUHR Impa ct 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 im provements 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 traditio nal high output factor utilization. Commenters note d 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

ec onomically 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 energy

price 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.

Commenter s stated t hat 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 maintenanc e and capital investment activities.

Commenter s stated that EPA relied primarily on capital costs provided in the 2009 S&L Report to establish its $100/kW total capital cost, which, EPA concluded was "a representative496 combined HRI capital cost to achie ve whatever HRI Btu reduction is possible at an average site." Commenters stated that to establish this number, EPA apparently divided the range of capital costs ($) 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 i ntended 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 coul d 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 co nditions 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 furth ermore, 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 equipmen t 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 misapp lied 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. Co mmenters 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 includ e decreased thermal efficiency, increased parasitic loads, reduced497 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 requirement s, 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 c omment :

Commenter s 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 comment s 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 h eat 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 Cou ncil 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.

Commenter s stated that E PA'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 i n response to prior rules, they ha ve performed upgrades to the flue gas desulphuriz ation 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 m embers and resulted in a 2.5% increase in plant auxiliary load thereby negatively impacting th e 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 effic iency of the facility.

Commenter s 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 improve498 operations. Commenters stated that for the purp oses of their comments, and in general, they consider heat rate improvements from equipment and from operational improvements as part of one category, and the ir 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 ra te 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 burde ns 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. Commen ters 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, acro ss the fleet. Commenters stated that effective NSR reform is critical to unlock more potential from existing coal

- fired power plants.

Commenter s stated that EPA's formula for setting the targets includes an expected 6% improvement in heat rate at coa l

- fired power plants. Commenters stated that such investments are likely to require significant sums of capital

Commenter s stated that they own and operate one coal

- fired power plant, the Charles R. Lowman Plant ("Lowman"), in Leroy, Alabama. Commenter s 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 a n 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 state d 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, an d 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 cost

effective power generation for their members.499 Commenter s 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 f ound 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 incen tive 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. Comm enters 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.

Commenter s stated that they ha ve 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 conse rvation. 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 ha ve invested in heat rate improvements and continue to im plement 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 he at rate improvements they ha ve 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 S olutions, 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 valv es), 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 ove rhauls. 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 approximat ely $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 overha ul 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 33500 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 achievi ng 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 assume d 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. Com menters 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 ha ve already paid for the best heat rate improvements, it would require huge expenditures to gain negligible GHG reductions under this building block. Commenters

s tated 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.

Commenter s 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.

Commenter s 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 in vested 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 stat ed 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

Commenter s stated that also of concern is that regulated units could find additional efficiencies with significant investment and redesi gn, the investment may result in additional regulation under 111 (b) as well as 111 (d) (as both a new and existing resource). Commenters stated that501 this is not a legal action and is contrary to the governing statutes. Commenters stated that any final emi ssion 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 c omment :

C ommenter s 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 HR I 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 ass ociated 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 effecti veness 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 w ere 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 concl uded 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 never theless, 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 e ach 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 audit s 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, i ncluding, 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

spec ific and must be evaluated on a case

- by

- case basis.

Commenter s 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 projection s 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 estima te 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 c om menter s contended that the 6% HRI envisioned by U.S. EPA, let alone the 7.7% HRI modeled by IPM for Ohio, is unobtainable. Commenter s stated that this contention is supported not only by their analysis, but by, among others, Sargent & Lundy in their Octob er 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 enabl es 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. C ommenters 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, t hese 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 b oth 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% H RIs. 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 benef icial 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, in dependent 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 a dditionally, 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.

Commenter s stated that because EPA's technica l 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 lik ely 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 th at EPA must revise its Building Block 1 estimates to reflect current data on what is actually achievable at reasonable costs. Commenters stated that f ailure to do so would render EPA's state targets arbitrary and capricious.

Commenter s 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 t hat 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 disadvan tages 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 calculat ions 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 rat e."

Commenter s 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 be504 vastly more difficult to achieve. Commenters stated that all th e 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.

Commenter s 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 bu rning 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 3 3) 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 U SEPA'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 ha ve 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 impr ovement would not be feasible or economically viable for their facility , credit should be given for the improvements already achieved.

Commenter s stated that their analysis concludes a total heat rate improvement up to 1.5% from current operating param eters is the maximum attainable at an economically justifiable cost for a merchant unit.

Commenter s 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 per cent 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 co uld be achieved, but at costs well in excess of $6 to $12 per ton of CO2 removed. Commenters stated that they are concern ed 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 opportunity505 Response 8 : See section V.C of the final rule preamble of the CPP and C hapter 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 above

referenced 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

ru lemaking.

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

Commenter s 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 perfor med as routine/required maintenance and the efficiency improvements are secondary or inadvertent to the decision

making 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

- fire d 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 c onsidered 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 b elow:

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 th an 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. Comment ers 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 performan ce 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.506 (c) Plant assessments including optimization of performance through operational changes, expanded or more flexible operation of the steam turbine unit supported by on

site assessments and engineering studies. Plant assessments also consider improvements that can be addressed with minor maintenance outages (including improv ements 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 assess ments 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.

Co mmenters 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

as sumed 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 ord er 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 up grades:

(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 exist ing 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 calcula ted assuming a representative steam

- coal unit that had the following attributes:507 • 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 un its 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 coal

fire d 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 fo r 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. C ommenters 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 p art 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 potent ial 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 po tential 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 estima ted 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 estimate d 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 eac h units economic potential identified in stage 2.508 Commenters stated that for the economic potential, c ommenters made a final adjustment downward to the resulting fleet

- wide % improvements in stage 3 to account for cycling and part

load operations. Commente rs 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 CS PAR and Mercury MATS.

Comment 9 : Comment s 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 Mea sures TSD supporting the final CPP.

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

Commenter s 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 t his financing is dependent on continued operation of the unit to create a revenue stream tha t 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 th at t his 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 "reducti ons 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.

Commenter s stated that in 2010, in collaboration with one of their member s u tilities, they issued the results of a year

- long study titled "Methodology for Fleet

- wide Energy Efficiency Analysis". Commenters stated that t he 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 t he team developed estimates for each project including the co st to implement and the potential heat rate improvement. Commenters stated that then they determined which projects were applicable to each of their operating units.509 Commenters stated that t hose 174 capital projects were studied in detail to determine accu rate, unit

- specific costs and heat rate improvement values. Commenters stated that o f 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 in itial 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 t he remainder of the identified projects were estimated to cost $740 million to achieve an a dditional heat rate improvement of 2.5%.

Commenter s 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 establis h 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 $100/kW total capital cost, which, EPA concluded was "a representative combined HRI capital cost to achieve whatever HRI Btu reduction is possible at an average site." Commenters stated that t o establish this number, EPA apparently divided the range of capital costs ($) provided in S&L's repor t 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 m ethods 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 labo r 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 st ated 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, ca se 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 t o serve as the basis for calculating minimum or maximum fleet

- wide HRI implementation costs.

Commenter s 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 $60/kW on smaller units. Commenters stated that EPA acknowledged in the510 GHG Abatement Measures TSD that "the economy of scale of larger units allows the use of higher cost improvements to be more economic" and "economy of scale causes most HRI methods to be more costly ($/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 fe asibility 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 signif icant 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 categori es (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 eva luated 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.

Commenter s stated that in determining the capital cost of equipment upgrades, EPA again relies exclusively on the S&L R eport, 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 propos ed 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.

Commenter s 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 pro posal 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.

Commenter s stated that significant HRIs beyond those already accomplished cannot be economically justified at li gnite 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,511 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.

Commenter s stated that there is also inconsistency betwee n 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 Blo ck #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 marke t constraints created under Building Block #2

Commenter s 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 cap acity 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 cost

effectiveness 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

cu rrent 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 Meas ures 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 s tated that f or 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 utilit ies , it is n ot acceptable for independent power producer s . 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 e xpenditure to maintain the level of heat rate improvement, which would further increase the duration of the payback period.

Commenter s stated that furthermore, utility companies have expressed concerns about the difficulty in obtaining financing for th ese heat rate improvement projects. Commenters stated that b ecause 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 f acility becomes less attractive because it will be more difficult to recover the cost of the investment if the facility generates less electricity.

Commenter s stated that the 6 percent goal is even less workable when taking costs into account, as EPA i s 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 impro vements 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 to512 implement any economically realistic measure, particularl y 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 i mprovement 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 imp lementing 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 t hese undertakings also make the improvements unrealistic for Lowman in any event.

Commenter s stated that the first proposed component requires coal units to achieve a 6% efficiency improvement over current levels. Commenters stated that the EPA based t his 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 ar e 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.

Commenter s 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 opera tion 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 mone y on heat rate improvement.

Commenter s 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.

Commenter s 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 tot al annualized capital cost of all HRI methods to the projected fuel savings associated with513 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%.

C ommenter s 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 achiev e 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 o f 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 furt hermore, 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 improve ment 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 $60/kW on smaller units. Commenters stated that EPA acknowledged in the GHG Abatement Measure s TSD that "the economy of scale of larger units allows the use of higher cost improvements to be more economic" and "economy of scale causes most HRI methods to be more costly ($/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 unit s.
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 associat ed 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 unit514 size and retrofit difficulty. Commenters stat ed 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 state d 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 no d 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. Co mmenters 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 it s 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 ca lculation, 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

o wn 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 circumstance s." 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 n ot 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 footnote515 1 19 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 metri c 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 th is 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 ad vantage 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 c omment :

Commenter s 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 an d 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 wi th controlling the CO2 emissions and can potentially have an exponential amount of increase.

Commenter s 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 pr ovide 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)

Commenter s stated that a net 6% heat rate improvement is arbitrary in several other respects. Commen ters 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." Commente rs stated that EPA nevertheless assumed that efficiency improvements would remain static, but to be accurate,516 EPA must account for the fact that maintaining a 6% heat rate improvement will require periodic and expensive upgrades.

Commenters stated that EP A 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
ope rating 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 escal ating 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 coal

fired units expected to be in existence in 2030 would find i t 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 viabil ity of coal

- fired facilities like their facility

.
Commenter s 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.

Commenter s stated that in it s 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 becaus e 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 demonst rated." 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 E GUs 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 h owe ver, 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 po ssible 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 Virgin ia's existing EGUs to undertake new measures to increase their heat efficiency.

Commenter s asked what sensitivity analysis did the EPA run on the inputs referenced on p. 2

- 39 of the GHG TSD.

Commenter s 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 improvement s at their coal

- fired facilities since 2005: condenser replacement, condenser cleaning systems, turbine replacements, cooling tower replacement, and ID fan replacement.517 Commenters stated that since 2005, they ha ve expen t over $100 million on projects that have helped maintain and improve heat rates at its coal

- fired facilities.

Commenter s 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 improvem ent 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 s ubsection 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 b est 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 t he specific public comments under this c omment :

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 meas ures 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

- firin g 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 ma ximum 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 if518 one particular o ption 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 r ecovery ("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 m ore 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 b uilding block 3 (renewables). Commenter s 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. Comm enters 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 opti on 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 u nit519 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 s uggested 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 c omment :

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 efficien cy 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 econ omic 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 success ful 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 pre scribe 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 f or 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,520 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 greate st 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 suggest ions. 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 wi th 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 s pecific public comments under this c omment :

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 su bmitted 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 c omment :

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 othe r industry and academic st udies 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 list ed the following reasons why even cost

- effective coal plant efficiency521 improvements have not been implemented. Commenters stated that t hese include the fact that, in
some rate

- regulated markets, power plants are allowed to pass fuel costs on to consu mers, 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 moreov er, 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 oppor tunities 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 em issions 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 include d 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 c omment :

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 attempti ng to redefine the source.

Comment 6 : Miscellaneous criticism of BB1522 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, inc luding 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 requi re 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 c omment :

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 w ithout 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 a lready 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 antic ipates 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 relat ed 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 fir ed 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 c omment :

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 opti on 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, the y believe that algae

- based fuel production and other CO2 recycling approaches holds great promise for capturing carbon emissions at fossil

- fuel power523 plants, thereby reducing the overall emissions rate. Commenters stated that since these reductions have th e 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, wast e 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 AzCAT I 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 explic it 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 embracin g 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 i f they sufficiently support clean power R&D activities.

Comment 8 : National average heat rate improvement goal is unfair to states with primarily gas

fired 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 generati on 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, an d a uniform technology

- specific rate approach for quantifying BSER. Both of these changes also work to obviate the commenter s ' concern.
The following are summaries of the specific public comments under this c omment :524 Some commenters assert ed 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 st ates with primarily coal

- fired EGUs

.

Comment 9: Commenter s stated that while building block 1 addresses measures at the affected facility, it still includes measures outside the boundaries of an affected facility. Commenter s said building block 1 is le gally 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

C omment 10 : Comments suggesting an alternative to the CPP in which states determine mass

based 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 determ ining 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 unit

specific 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 insta ll 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 which525 distorts normal coal generation capacity factors and, therefore, makes the u se 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 bro ught 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 existi ng 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 assumpti on 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 fo ssil 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 reliabil ity.

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 re liability 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 complian ce 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 com pliance.

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.526 Comment 12: Commenters believed that EPA should au gment 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 targe ts. [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 bui lding 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 cou ld 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.