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Page 1 of 38 **Averaging Time for Standards**

 Can EPA please explain why it uses 30

- day averaging as the basis for emissions limits? What alternative periods did it consider, and what was the rationale for choosing 30 days? Does the averaging period have to be the same length of time for all polluta nts? Companies have shared data with us demonstrating considerable variation in emissions on a 30

- day rolling average basis, even when average emissions over longer periods are low. Certainly for mercury, my understanding is that it is cumulative rather than acute exposure that matters, which would argue for longer averaging periods.

 Can EPA please clarify how the startup and shutdown periods are incorporated into the 30

- day averaging periods? The draft rule states that work practice standards will be u sed for compliance during startup and shutdown, but it also says that “the rule requires sources to measure and report their emissions at all times, including periods of startup and shutdown” (p. 330). The mention of compliance measurement, at least in th e summary, mentions 30 consecutive boiler operating days without addressing startup/shutdown. Does this suggest that emis sions during startup and shutdo n will be included in the 30

- day rolling averages for purposes of compliance? **Emissions Averaging**
 Can E PA provide the interagency reviewers with an explanation for why it did not elect to allow averaging between units in the same subcategory? If appropriate, that explanation should also be included in the preamble. **Limited Use Units**

 Can EPA explain why it chose a 5 percent annual capacity factor as the threshold for defining the limited

- use oil

-fired subcategory, rather than 10 percent? Can EPA please provide data to support its choice? **Monitoring and Compliance**

 Several c ommenters in the regulated indust ry raised concern s about the testing procedures. Can EPA please clarify how the changes in the rule since proposal have addressed concerns about the relationship between stack testing requirements and CEMS, and the frequency of required stack tests?
 Has EP A considered the costs associated with using and replacing CEMS equipment, as well as the man hours necessary in completing the monitoring and submitting the data in their cost analysis?
 Page 355: We refer to a statement on this page: “Where a CEMS (including a sorbent trap monitoring system) is used for demonstrating initial compliance, you also must use the CEMS on a continuous basis to demonstrate ongoing compliance.” Sorbent traps are not continuous monitoring devices, and should not be characte rized as such . A sorbent trap requires long sampling times (for low

- level HAPS such as Hg), transport to an analytical facility (which are

## Summary of Interagency Working Comments on Draft Language under

EO s 12866 and 13563 Interagency Review. Subject to Further Policy Review.

Page 2 of 38 frequently not located on site) and analysis in a laboratory. All this is required for a single reading. It is not unreasonable for long periods of time to lapse before the sample reading can be returned. This would not qualify as a continuous technology that reports real

-time emissions, which allows operators to tune boiler operation so as to minimize these emission s. Therefore, any reference to sorbent traps as a continuous monitoring technology should be eliminated.

 Page 358: This comment refers to the requirements pertaining to use of Hg CEMS or sorbent trap monitoring systems. On page 436, the draft final ru le says, “we have determined that there are adequate test methods to measure the regulated HAP at the new source levels.” We seek information on the EPA determination that sorbent trap monitoring systems can support an adequate test method for Hg. Sorbe nt traps are not a continuous monitoring technology, as they are designed to take readings in batch (intermittent) mode. They are a poor fit for measuring HAPs that occur at such low concentrations (like Hg) because such long sampling times are needed to collect sufficient mercury on the trap. Furthermore, due to the long sampling time, it has been shown that sulfur can begin to also collect on the trap, and “kick off” mercury, leading to inaccurately low Hg readings. For this reason, sorbent traps are a poor fit for mercury monitoring and should not be included here.

 Page 359, Section V.G.(2): This section requires monthly stack tests or use of PM CPMS for proving compliance with the PM emission limits. It appears that costs involved with conducting mo nthly stack tests would be expensive, especially for small power plants. The operating permits for most of the existing plants may require use of opacity monitors for compliance with PM emission limits that may be more stringent than those in the MATS rul e. Would these plants now have the extra burden of maintaining dual monitoring/testing programs for the same pollutant? **Mercury Emissions Standard**

 Can EPA explain the basis for its mercury standard and in particular the sample of units it u sed to determin e the standard? How does that set of units compare to the set of units used to calculate emission standards for other pollutants?
 More specifically, EPA used a different number of units to set the new unit MACT floor for acid gas and PM (131) than it did to set the new unit MACT floor for Hg (40). Many submitted public comments that EPA did in fact possess the data to base the new unit MACT floor for Hg on 127 units. EPA failed to address this comment in the final rule. This comment was repeatedly submitte d but was well articulated in particular by Duke Energy. The comment is summarized here for EPA to address. “Section 112(d)(3)(A) of the CAA specifies that EPA must set a MACT limit for existing units that is at least as stringent as the average emissio n limitation achieved by the best performing 12 percent of the existing sources (for which the Administrator has emission information). EPA

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Page 3 of 38 determined that it needed additional information on HAP emissions to conduct the current rule making to set MACT li mits. EPA undertook an information collection request (ICR), sending it to all coal

- and oil

-fired EGUs and requiring extensive reporting of historic emissions information. In designing the stack testing portion of the ICR, EPA considered choosing plants either on a purely random basis or selectively choose only units that it believed were best performing units and would have the lowest emissions of a given HAP. EPA chose to follow the second option in its 2010 EGU MACT ICR. However, to ensure that it coll ected data from the best performing units, EPA elected to require stack sampling for mercury, acid gases, and non

- mercury metallic HAPs from what EPA considered was the best performing 15% of the 1,091 coal fired units. In addition, EPA collected a large amount of existing emissions data under Part II of the ICR, particularly for mercury. Before EPA submitted the ICR to OMB, representatives from EPA and industry met to discuss the scope of the ICR and how units would be selected for testing. EPA‘s preferre d approach was to require testing by units that EPA thought were the best performing for emissions of mercury, trace metals, HCl, organic HAPs and dioxins. Industry argued that if EPA selected plants in this manner, then it must use data from a number of s ources representing 12% of the entire industry to calculate the MACT floor. Assuming a total of 1,091 coal

-fired units, 131 units would represent 12% of sources. As a result, EPA stated in its Supporting Statement for the ICR: For 3 of the HAP groups or in dividual HAP, to the extent the Agency can establish that is has in fact collected data from all of the existing sources that represent the best performing 12 percent of the existing sources, we intend to use data from sources representing the best perform ing 12 percent of all sources in any category or subcategory to establish the CAA section 112(d) standards. On this basis, OMB approved EPA‘s Utility MACT ICR and sources conducted the required testing. In the proposal, EPA used emissions from 131 units

-- 12% of the 1091 coal

-fired EGUs

-- to calculate the MACT floor HCl and total PM. Because EPA intentionally selected what it thought were the best performing units, Duke Energy strongly agrees with EPA‘s use of 131 units to calculate the MACT floors for these HAPs. However, Duke Energy strongly disagrees with EPA‘s use of 40 units to determine the MACT floor for mercury emissions. In the preamble to the proposed rule, EPA now stated: “ For Hg from coal

- fired units, we used the top 12 percent of the data obtained because, even though we required Hg testing for the units testing for the non

- Hg metallic HAP, we did not believe those units represented the top performing 12 percent of sources for Hg in the cate gory at the time we issued the ICR and we made no assertions to that effect.” This runs counter to EPA‘s position when it sought approval of the ICR from OMB when EPA stated: “ For Hg and other non

- mercury metallic HAP group, EPA believes that units with th e newest PM controls installed represent those units meeting the lowest PM emission limits, and, thus, are believed to be among the top performers with respect to Hg and other non

- mercury metallic HAP emissions. Therefore, EPA has selected 175 units with the newest PM controls installed; of these 175, the newest 170 operating units will be required to conduct Hg and other non - mercury metallic HAP testing. This number includes units with ACI installed and other control configurations are also included (e.g ., for SO2 and NOx control.” Given these conflicting statements, the question becomes whether EPA did collect mercury data from the best performing units during the ICR. After the proposed rule was released, various errors were identified in the derivation o f the mercury standard. Once these errors are corrected, the mercury ICR data do show that the best performing units were tested during the

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Page 4 of 38 ICR. The most significant error involved converting Part II ICR data that had been reported in terms of lb/GWh. When these data were converted to lb/MWh, EPA divided by a factor of 1,000,000 instead of the correct divisor of 1,000. Because of this error, many units that reported Part II data appeared to be among the top units because their actual reported mercury emissi ons were understated by 1,000 times. Of the 40 existing units that EPA identified as the best performing for mercury emissions, 20 were incorrectly listed among the best units because of this single conversion error. Looking at the original list of best pe rforming units, it is easy to understand why EPA may have questioned whether the ICR testing really targeted the best performing units for mercury emissions. Once the error is corrected, the result is clear

– EPA did select the best units for ICR testing. After the conversion factor is corrected, all but six of the top 40 units submitted Part III test results. Looking at the broader group of 131 best performing units, the Part III testing bias for the best performing mercury units becomes inescapable. Of th e top 131 units, only 22 did not submit Part III results. There are several other reasons to conclude that the Part III testing focused on units with the lowest mercury emissions. One indication is the disproportionately high number of units equipped with activated carbon injection (ACI) that were tested. ACI is installed on coal

-fired EGUs for the sole purpose of controlling of mercury emissions. EPA‘s spreadsheet of the Part II ICR data lists 45 EGUs as having installed ACI systems. Of those 45 units, 33 reported Part III mercury test results. Had the Part III testing for mercury been completely random, as EPA‘s present choice of 40 units to set the MACT floor suggests, then only 15% of all ACIs units would likely have been selected for Part III testing

-- or 7 units. In fact, 73% of the units equipped with ACI were required to conduct Part III mercury testing. Ultimately, EPA had a much larger database to establish the MACT Floor. Using 40 units to represent 12% of the population (1,091) indicates that EPA had a data from approximately 330 units or almost a third of the entire industry. Considering all these factors shows that EPA‘s data set robustly represents the very best performing of all of units. EPA is therefore incorrect when it states” For Hg from coal

- fired units, we used the top 12 percent of the data obtained because, even though we required Hg testing for the units testing for the non

- Hg metallic HAP, we did not believe those units represented the top performing 12 percent of sources for Hg in the category at the time we issued the ICR.” As a result, the only appropriate action is for EPA to use 127 units to determine the MACT floor for Bituminous and Sub

- bituminous subcategory.
**Area Sources**

 EPA received many comments supporting GACT standard s for area sources. Can EPA explain why they cannot establish GACT standards for area sources under the authority of 112(d)(6)? Is EPA prohibited from establishing area source standards? What impact would GACT standards for area sources have on the costs , benefits, and standards for the major sources?

 Responding to comments about the need for area source standards (page 480), EPA notes “Commenters indicate that many EGUs owned by small entities are potential area sources. However, commenters fail to note that there are also EGUs owned by small entities that are NOT potential area sources, and, thus, would not accrue any “lessened regulatory burden” benefit from a decision by the EPA to establish area source standards.” This is not a strong

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Page 5 of 38 response to the argument that area source standards would reduce burdens on many small entities. Please revise to more directly address the comment **Compliance Deadline**

 EPA appears to be essentially delegating all authority to extend a fourth compliance year to State permitting authorities. Can EPA explain why it is not simply using its own authority under 112(3)(B), which it appears to retain even when States have Title V permitting authority (“The Administrator (or a State ... ) may issue a permit that grants an extension ....”), to give broad

based extensions?
 A three year implementation timeline for multiple emissions controls upgrades seems extremely aggressive. This has been noted in the comments section. However, I am concerned that a large number of non

- compliant coal plants would suddenly need to design, construct, test and operate emission control devices within three years. One issue is that the A/Es, various e quipment providers, labor, etc. could probably not handle this sudden influx of business. This can result in extended lead times for emissions controls equipment, shortages of qualified designers, shortages of specialized construction, etc. When there is a surge in need for these suppliers several issues typically arise. 1) The price of equipment and services increases to reflect demand, 2) The design and construction schedules extend beyond original estimates and/ or 3) The quality of the emission controls design and construction is compromised by rushed work. Also, supply and demand applies here as the greater the need for the controls increases the overall cost associated with these emission controls which could easily result in costs greater than EPA originally estimated. Has EPA evaluated this effect on the cost and availability of control technology? In particular, rural cooperatives often have relatively smaller generating units. The best qualified A/Es, equipment suppliers and construction outf its will seek to work with the projects that have the greatest potential for profit (larger and multiple coal units) which could put small G&T cooperatives at a disadvantage when seeking support to build the new emissions controls. Investor owned utilitie s would probably be first in line for vendor and consultant support.
 Page 508: “Permitting authorities should be familiar with the operation of the 1

-year extension provision because EPA established regulations to implement the provision and the provision applies to all NESHAP. See 40 CFR 63.6(i)(4)(i).” Is applying for and granting a 1

-year extension easy or simple to do? If so, it would be very helpful for EPA to explain.
 Page 513: We refer to a statement on this page: “However, other commenters requested that no additional time be granted for compliance. These commenters reference a number of reports (e.g., by the URS Corporation, by M.J. Bradley & Associates and the Analysis Group, and by the Bipartisan Policy Center) to indicate that not only is technology readily available, but that the technology can typically be installed in less than 2 years and that the electric industry is well

positioned to comply with the EPA’s proposed air regulations without threatening electric system reliability.” The co mment that EPA is referring to is almost certainly from Exelon Corporation (Exelon submitted public comments to this effect, and also referenced the reports noted here by EPA). Exelon’s power generation portfolio is weighted heavily toward non

- coal generat ion. As of late 2009, Exelon held full or majority ownership of 17 nuclear reactors in 10 nuclear power plants. In the spring of 2011, Exelon announced a merger with Constellation Energy. The combined

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Page 6 of 38 company will own nearly 19 GW of nuclear generation, 8.2 GW of natural gas generation, and nearly 3 GW of renewable generation including hydroelectric. Exelon’s power generation business would likely benefit tremendously from as many coal plant retirements as possible. Therefore, it is not surprising or cre dible that they have submitted comments stating that the compliance period is reasonable, and the technology can be installed in less than two years. Other utilities (such as American Electric Power and Southern Company) with actual experience in pollutio n control retrofits disagree strongly with the assertions made by Exelon, based on their submitted public comments. **None of these reports confirms that control technologies (specifically dry sorbent injection) are readily available.**  The referenced report by URS Corporation was commissioned by Exelon Corporation (this is specifically stated in the executive summary of the report). As noted previously, Exelon would benefit from a large number of coal retirements brought on by the aggressive compliance perio d due to their heavy nuclear and gas portfolio. The referenced report by Bipartisan Policy Center also explicitly states that their assumptions regarding the cost, effectiveness, and availability of DSI were completely informed by EPA, not their own asses sment. Finally, the referenced report by M.J. Bradley was funded by the Clean Energy Group’s Air Policy Initiative, whose members include Exelon Corporation and PG&E (both heavily invested in nuclear generation as well as natural gas), Constellation Energy (who has merged with Exelon Corporation), and Calpine Corporation (whose portfolio is weighted heavily toward natural gas). All three of these reports were funded by organizations that have a stake in coal retirements, and they all lack the independent research, development and demonstration that would actually indicate that DSI could be installed as widely as EPA has assumed.

 Page 513: We refer to a statement on this page: “ Another commenter noted that utilities that failed to plan ahead “should not be permitted to use their own inaction to justify more time.” Commenters noted that several major utility companies have anticipated the EPA’s rules and are already taking action to ensure a reliable supply of electricity in their service territory and beyond.” The aggressive MATS compliance period almost requires utilities to immediately start making decisions regarding retrofits. Failure to do so may result in getting caught up in a wave of other utilities that wait until MATS becomes final, possibly res ulting in cost premiums due to supply chain pressure, or inadequate time remaining to complete the project. The issue with starting early is that utilities run the risk of making wrong decisions because the rule changes, either due to litigation, vacation by the court, or other factors. A utility that initiates a fabric filter or FGD installation, ultimately to learn that it is not needed because the rule changed, will prove to have made a costly decision. Given the current economic times, utility execut ives are more likely to be risk averse and may instead opt for retirement, rather than make the wrong retrofit decision. A more appropriate compliance period would avoid this issue by giving utilities adequate time to make retrofit decisions, and allowing for a more reasonable project schedule, while still achieving the stated EPA goal of pollution reduction.

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Page 7 of 38  Pages 515: We refer to a statement on this page: “Clean Air Act section 112 specifies the dates by which affected sources must comply with this rule. New or reconstructed units must be in compliance immediately upon startup or [DATE OF PUBLICATION OF THIS FINAL RULE IN THE FEDERAL REGISTER], whichever is later. Existing sources may be provided up to 3 years to comply with the final rule; if an existing source is unable to comply within 3 years, a permitting authority has the ability to grant such a source up to a 1

-year extension, on a case

- by

- case basis, if such additional time is necessary for the installation of controls.” Numerous sources such as American Electric Power and Southern Company, have repeatedly stated that while 4 years (3 years, plus a one year extension) may be adequate to physically install the equipment, it does not allow for permitting (which can take up to a year alone), design, procurement, installation, testing, and startup. It is worth nothing that these are institutions in the electric power industry and have a great deal of experience in pollution control retrofits. According to AEP, a fabric filter retrofit typically takes 3 and a half years, while an FGD requires nearly 6 years from project conception to startup. Southern Company has confirmed these estimates. These schedules also do not account for the constraint in labor and construction resources that will most likely occur under a 3

– 4 year MATS compliance period as proposed. The compliance periods for MATS, as well as other pertinent regulatory initiatives (including the Cross State Air Pollution Rule (CSAPR), 316(b), and Coal Combustion Byproducts) are overlapping, and plants will likely have multiple projects occurring simultaneously, to comply with several different rules. This high demand for services in a relatively short period of time will put a strain on the construction and engineering firms that are availa ble to perform the work. A likely outcome of these overlapping timelines is that there will be a large amount of retrofit activity in the fossil power generation sector during the 2012

- 2016 timeframe, causing the supply chain to become constrained, and sub stantially increasing project costs. Don Broelis, Vice President of Fluor Power Group, described the impact of the proposed MATS compliance period: “If it is a three

-year program, we believe we are going to see an extreme peak in activity and that’s going to be the complete supply chain. That will be tightening the supply for environmental technologies such as SO2 scrubbers, selective catalytic reduction, baghouses, chimneys and then some of the typical bulk materials like steel and components such as pumps, motors, transformers and so forth. There will be a tightening even with contractors to perform the work.”

 Page 522, Section VII.F, Response: In EPA’s response throughout this section, the issue related to the adequacy of compliance timing and i ts effect on grid reliability has been addressed. However, a part of this issue brought up in the public comments is to do with the ability of the affected sources to install the required environmental controls by the compliance deadline (including the one

-year extension allowable by this rule). Several commenters provided estimates of the installation timing required that exceeded the allowable time for some controls, including wet FGD scrubbers and baghouse filters. Many commenters also pointed to

## Summary of Interagency Working Comments on Draft Language under

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Page 8 of 38 the i nadequacy of resources within the industry to build the required controls within the allowable time. One commenter (Utility Air Regulator Group) submitted a detailed study on the issue of adequacy of the available industry resources, especially the skille d labor. It appears that EPA’s responses do not fully address these concerns in the preamble. Please advise if there is another rule document where these issues are covered.

 Page 515: We refer to a statement on this page: “The EPA has considered the co ncerns raised by commenters and has concluded that given the flexibilities further detailed in this section, the requirements of the final rule for existing sources can be met by most sources without adversely impacting electric reliability. In particular, EPA believes that the flexibility of permitting authorities to allow a fourth year for compliance should be available in a broad range of situations (as discussed below), and that this flexibility addresses many of the concerns that have been raised. Furthermore as indicated below, in the event that an isolated, localized concern were to emerge that could not be addressed solely through the 1

-year extension under CAA section 112(i)(3), the CAA provides flexibilities to bring sources into compliance while m aintaining reliability.” Unscrubbed coal units burning either bituminous or subbituminous coal, in states affected by CSAPR are the units that are most likely to be impacted by MATS, in addition to CSAPR, the coal combustion byproducts rule and 316(b). C onsequently, there is likely to be significant activity within select geographic areas, which can potentially be problematic for attracting and retaining skilled labor. Many engineering cost estimates frequently include incentives beyond a typical 40

- hour workweek. Often, these monetary incentives are required to retain a skilled labor force on a jobsite. Without an extra financial incentive, there is little that can be done to prevent skilled craftsmen (such as pipefitters, welders, or ironworkers) from going to a nearby, competing job that pays better. Such an exodus of craft labor can be devastating to the successful completion of a project, on time, and within budget. Given the proximity of the coal

-fired power plants that are likely to require engine ering and construction services, and the high demand for such services during a short period of time, there is likely to be a premium put on the existing labor force during 2012

- 2016 (assuming the one -year extension is granted). This could seriously hampe r the ability of the coal

-fired power generation industry to comply with MATS during the proposed timeframe. A more relaxed schedule would likely alleviate the pressure on this resource, and increase the likelihood of achieving MATS compliance.
 Page 531: “While the ultimate discretion to provide a 1

-year extension lies with the permitting authority, EPA believes that all three of these cases may provide reasonable justification for granting the 1

-year extension if the permitting authority determines based on information from the RTO or other planning coordinator for the relevant region, and/or NERC or one of its regional entities, and/or the Federal Energy Regulatory Commission (FERC) or the DOE, that continued operation of a particular unit slated for retirement for some or all of the additional year is necessary to avoid a violation of applicable FERC

- approved or state electric reliability standards.” Again, since units have no economic motivation to announce retirements early, the situation may arise whe re plants announce retirement with as little as 45 days notice of January 1, 2015 to the RTO. If EPA grants the RTO the 1

-year extension to complete transmission upgrades, then the RTO essentially has 1 year plus 45

- 120 days (depending on the RTO) to imple ment transmission upgrades. Since these upgrades can take 1

- 3 years as even identified by EPA in this

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Page 9 of 38 preamble (Page 507), this does not give the RTO adequate time to respond to a transmission security reliability issue by the compliance deadline. A 1

-year extension to the permitting authority may not be adequate for alleviating reliability concerns.

 Page 535: “The EPA believes that the number of cases in which a unit is reliability critical and in which it is not possible to either install controls on the unit or mitigate the reliability issue through construction of new generation, transmission upgrades, or demand

-side measures, within 4 years, is likely to be very small or nonexistent. This view is echoed by commenters explicitly mandated with ensuring g rid reliability.” These commenters made this statement under the presumption that EPA would incentivize early retirement announcements by granting compliance extensions only to units who announce their retirement with at least 2 years advanced notice (see Corrected Comments of PJM Interconnection, L.L.C., August 4, 2011 ). Most commenters recognize that reliability issues are a very really problem, especially from a transmission security standpoint, and absent EPA providing early retirement incentives, thes e regions may be required to make system upgrades in a little more than one year. This limited timeframe is counter to public comments and public documents outlining historic timelines to install transmission upgrades.

 EPA should, in the final rule, grant a blanket 1

-year extension to all existing EGUs under Section 112(i)(3)(B) of the CAA. We believe this section of the CAA allows the Administrator to issue a Title V permit that grants a 1

-year extension. Since EPA ultimately can approve or veto any Tit le V permit, even one issued by a State permitting authority, Section 112(i)(3))(B) should be construed as granting EPA the authority to issue such a 1

-year blanket exemption. A blanket extension will result in the fair and uniform exercise nationwide of the discretion provided by the Act to grant an extension for installation of controls. Further, Section 112(i)(4) contains the option that authorizes the President to grant an extension of 2 years (which may be renewed) if the President determines that the “technology to implement [MACT] standards is not available and that it is in the national security interest of the United Sates to do so.” The proposed MACT standards require large

- scale installation of new control technologies to meet HAP limits. The i nstallation of controls on such a massive scale within 3 years is not feasible. Accordingly, we recommend that EPA seek a Presidential exemption that could then be implemented through qualifying criteria enumerated in the final rule. Once granted, EPA wou ld use the Presidential exemption extension where additional time beyond 4 years is required in order to maintain electrical system reliability. The use of this Presidential exemption would be vastly preferable to the use (as currently proposed) of EPA’s enforcement discretion to allow operation of sources in non

- compliance beyond the 4

-year timeframe.

 EPA’s assumed installation timeframes do not include the time necessary for conceptual and detailed design and permitting. We are providing below the ti meframes for control equipment installation based on TVA’s extensive experience designing and constructing such control systems. As detailed below, the times required for the three main acid gas removal options

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Page 10 of 38 (DSI, Dry FGD, and Wet FGD) as well as for c ontrol via onsite replacement Combined Cycle (CC) generation and transmission upgrades range from 39 to 59 months for back end controls and replacement generation and up to 7 years for transmission upgrades. EGU’s representing approximately one half of th e coal

-fired generating capacity in the US do not currently have FGD or DSI systems installed for acid gas control. All of these units will either have to be controlled or retired based on the proposed rule. The installation timeframes described below for the alternative control options do not include the anticipated schedule impacts associated with the large number of equipment installations, replacement generation construction, and transmission upgrades that will be ongoing during the same time period . Equipment suppliers will be critically challenged to meet the national demand for controls, new generating units, and transmission upgrades in a timely manner, adding further uncertainty to installation timeframes. The number of units that can be offlin e simultaneously for controls installation/tie

- in and the number of transmission facilities that can be offline simultaneously for transmission upgrades is limited due to system reliability requirements. The above uncertainties and limitations notwithstand ing, installation timeframes for selected control devices based on TVA’s direct experience are provided below and in the attachments.
**DSI:** DSI may be a viable acid gas control option only for those units burning lower sulfur coals in conjunction with a baghouse. TVA does not believe that DSI will be adequate for medium to high sulfur coals. Importantly, DSI may also not be adequate for meeting other anticipated regulatory requirements, such as SIP requirements to meet the NAAQS for SO 2 and fine partic ulate (PM 2.5 ), or for achieving SO 2 reductions needed for compliance with the Cross State Air Pollution Rule(CSAPR) . The Shawnee plant is TVA’s only plant currently equipped with baghouses. Where both a baghouse and DSI would be needed, we expect installation of the baghouse and associated fans and other equipment would present a critical path for the project. The time required to select, design, permit, and construct DSI system with baghouse would be similar to the dry FGD schedule, which is a minimu m of 50 months as described further below. For units where a suitable baghouse is already installed, we expect a minimum of 39 months would be required to select, design, permit, and install DSI. **Dry FGD:** TVA expects the use of Dry FGD with baghouse to be a viable acid gas and particulate control option for some units burning medium to low sulfur coal, depending on the emission limits in the final rule. As described in the attached report by George Farina and Donald Houston, Attachment 1, we estimate 5 0 months are required to select, design, permit, and construct a Dry FGD with baghouse. The report also shows that where an offsite disposal facility must be located, acquired, permitted, and constructed, the total project duration increases to 63 months because activities relating to establishing a disposal facility would be critical path. **Wet FGD:** TVA expects the use of wet FGD to be a viable acid gas control option for most coal

fired units, but also the most expensive and time consuming controll equi pment to install. As

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Page 11 of 38 described in the additional report by George Farina and Donald Houston (Attachment 2) we estimate 59 months are required to select, design, permit, and construct a wet FGD. As noted above, we estimate 63 months will be required where an offsite disposal facility is required. **Replacement Power:** Depending on the emission limits in the final rule, TVA expects the best emission control option in some cases will be to retire the coal

-fired units and replace that generation with Combined Cycle (CC) units. As described in the report by Dan Tibbs and Donald Houston (Attachment 3) we estimate 48 months are required to select, design, permit, and construct a CC plant on site to replace retired coal units. We agree with EPA’s understanding t hat the 1

-year extension provided for in the CAA for the installation of controls should apply to the installation of on

- site or off

- site replacement power.
**t ransmission Upgrades:**  TVA expects the best emission control option in some cases may be to retir e some coal

-fired units, and through construction of transmission upgrades, deliver the power generated by the remaining units to customers, thus resulting in an overall reduction in fleet emissions. Pursuant to Section 215 of the Federal Power Act, as a user, owner, and operator of bulk power system, TVA is required to meet certain performance criteria established in Reliability Standards promulgated by the North American Electric Reliability Corporation (NERC) and approved by the Federal Energy Regulato ry Commission. As a result, compliance with those criteria is not optional. The NERC requirements are very stringent, and we do not anticipate any additional upgrades beyond those required by NERC for reliability purposes. TVA built and continues to op erate one of the largest high voltage transmission systems in the country, and our in

- house Electric Systems Projects group has extensive experience upgrading and extending the system. Current lead time for delivery of large transformers typically is 2 ye ars, and environmental review and land acquisition alone for transmission lines can take several years. As shown in Attachment 4, TVA estimates that a typical 20 mile single circuit 161 kV transmission line project will take approximately 56 months from i nitial planning studies to completion. A project for a 30 mile 500 kV line would require approximately 84 months. We agree with EPA’s understanding that the 1

-year extension provided for in the CAA for the installation of controls should apply to transmi ssion upgrade projects associated with retirement of coal

-fired units. We expect in some cases additional operating time beyond 1 year for units being retired will be needed to maintain power system reliability. **Startup/Shutdown**

 Additional leeway must be given during periods of startup or shutdown. A 5 percent rate of capacity requirement does not account for the variability associated with starting up or shutting down a facility.
 On page 3 41 , requiring sources to use either natural gas or distillate oil ignition during startup may be an undue burden. Will EPA have/allow exemptions? How does a source demonstrate compliance with §63.10011 (g)(2)?

## Summary of Interagency Working Comments on Draft Language under

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Page 12 of 38  Page 3 40 , 1 st Paragraph The definition of startup in this paragraph is restricted to cold startup only, with no discussion of warm and hot startup modes. The turbine is also not connected to the grid during these warm and hot startup modes. Please note that, during warm and hot startups, the boiler and turbine surfaces are warmer and, therefore, the startup time s are shorter than those during cold startups. However, the unit operation is still unstable during the warm and hot startup modes, and the emissions of various pollutants may still be higher than those achievable during stable loads. Does EPA have emiss ions data for warm and hot startups to confirm that affected sources can meet the same emission limits during these startups as during the full/stable load operation? If not, we recommend that EPA consider these points in clarifying the definition of startup, which is also discussed on pages 338 and 339

.  The rule preamble describes cold startup as starting from the point of no fuel being fired in the boiler and the boiler at ambient temperature. Heat from adjacent units and other sources prevents out of s ervice boilers from reaching outside ambient temperatures, and due to their large mass, several days can be required for cooling to near ambient power house temperatures. Startup of a boiler that has cooled sufficiently to allow for human entry, which is to approximately 120 degrees Fahrenheit, should be considered a cold startup.

 **Work practice standards should apply for all startups and shutdowns, and not be limited to only cold startups.**  The rule appropriately requires work practice standards instead o f numerical limits during cold startups and shutdowns, acknowledging the highly variable emissions and lack of appropriate emissions data during these periods. However, emissions during warm and hot startup periods are also highly variable and, likewise, l ittle emissions data is available for these time periods. Accordingly, work practice standards should apply, instead of numerical limits, for all startups and shutdowns.

 EPA also considers that startup ends when the turbine

- generator is synchronized to the grid and is requiring sources to operate using either natural gas or distillate oil for ignition during startup. TVA operating procedures for safe startup generally require establishing a coal fire shortly prior to synchronization and then prompt init ial loading of the generator after synchronization. Oil and coal are then co

-fired as load increases until normal minimum load is reached, where a stable coal fire is established and the oil fire can be safely removed. Startup should be considered to con tinue until a stable coal fire is established and the oil fire can be removed. Combustion of coal during startup should be allowed consistent with manufacturers ’ recommendations.

 EPA is requiring sources to operate all control devices necessary to meet the normal operating standards under the final rule (with the exception of SCRs) when coal or residual oil is fired in the boiler during startup or shutdown. Baghouses and some other control devices, in addition to SCRs, have minimum temperature and other requirements that limit their operation during startup. The work practice standard should require operation of control devices during startup and shutdown to the extent allowed by manufacturers’ requirements.

## Summary of Interagency Working Comments on Draft Language under

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Page 13 of 38 **Impacts of the Rule on Ratepayers**

 I t does not appear as though EPA took into adequate consideration the real potential utilities will close and the surrounding communities experience economic hardship due to these regulations.
 The coal units affected by this regulation would be faced with a large investment of funds that will result in no added production from the plants . On the contrary, the parasitic load (electricity necessary to run the equipment in the plant itself) that each plant normally requires would increase substantially due t o the installation of emission controls devices that require power to operate. So, in essence, the power plants will ultimately produce fewer megawatts due to the increased parasitic load and associated revenues would be decreased. Has this effect been a ccounted for in the costs of the rule and effect on ratepayers?
 Page 555: We refer to a statement on this page: ““The EPA’s estimates of increase in the retail electricity price range from 1.3 percent to 5.9 percent regionally in 2015...Low

- income household

s will thus see some increase in electricity price, but this increase should be modest.” This percent price increase does not take into account the cumulative effect of numerous EPA rules that could place upward pressure on electricity prices. Additionall y, it is unclear why a price increase as high as 5.9 percent would not be considered a major increase to a low

- income consumer

 We strongly recommend that EPA consider providing context for the projected change in electricity prices by comparing either the projected prices or the magnitude of the projected increase to recent historical data. For example, based on a quick look at EIA data( http://38.96.246.204/electricity/monthly/ex cel/epmxlfile5_3.xls ), it appears that EPA could explain its projected average price of electricity with the EGU MACT rule would still be less than average electricity prices for 2008

- 2010 (EPA should confirm that those numbers are comparable). Alternativ ely, EPA could say that the 3% increase is on par (or even less) than typical year

-to
-year price variability (again, after verifying that is in fact the case). **Noncompliance**

 Additional details need to be provided on what the penalties are for non compliance. Can EPA explain to the reviewers how non

- compliance is treated? Is there an appeals process? **Appropriate and Necessary Finding**
 Given the scrutiny that can be expected for EPA’s “appropriate and necessary” finding, We recommends that EPA provide a simple and succinct plain language explanation of its rationale at the beginning of Section III, before describing in greater detail the “appropriate and necessary” finding. A plain language explanation that “connects the dots” would be very helpful for the lay reader. **Applicability**

 Does EPA have a guidance manual that will be available on their website of all the entities that will be regulated under this regulation? The statement that an entity must reach out to their regional representative to find out if they must comply with this regulation is not ideal.

## Summary of Interagency Working Comments on Draft Language under

EO s 12866 and 13563 Interagency Review. Subject to Further Policy Review.

Page 14 of 38  Why were 10 and 15 percent production levels selected as the cut off point fo r coal fire? What is the rational?
 Page 593: We refer to the statement on this page: “Only those units that begin construction, modification, or reconstruction after May 3, 2011, will be affected by the final rule.” For units meeting this criteria, but who already have air quality permits, will this apply to them retroactively? There is a legal precedent for preventing retroactive application of new permit levels for units that have already obtained permits (Xcel Energy case cited above). **Tone** Page 314 (and elsewhere) , regarding EPA’s response back to UARG

-- t hough we can understand EPA’s argument, the response is combative and unnecessary. Suggesting softening the tone. **Impact on Rural Utilities**

 The regulation will have a disproportionate impact on smaller generating units (such as those owned by rural G&Ts). This will cause an increase in electricity rates. These small rural utilities have limited ability to recoup investment through rate adjust ments due to the relatively small size of consumers within the respective service territory. EPA suggests that the cost for smaller generators is proportional to larger generators. Has EPA modeled higher costs for smaller generators? **Emissions Limits**

 Page 318, Table 3: Clarifications are requested for the following emission limits:

 Existing Unit designed low rank, virgin coal , Mercury, 4.0E0 lb/Tbtu (4.0E

- 20 lb/GWh): Possible typo, 4 x 10^

- 20 Lb/GWh? Suspected that this should read 4 x 10^

- 2 Lb/GWh, which would be a gross heat rate unit of 10,000 Btu/kWh.

 New unit designed for coal > 8,300 Btu/lb , Mercury, 2.0E

- 4 lb/GWh: For bituminous coal, this limit of 0.0002 Lb Hg/GWh converts to approximately 0.027 microgram/dry normal cubic meter (corrected to 3% O2). This is almost two orders of magnitude below what commercial CEMS can accurately measure. Discussions with University of North Dakota’s Energy and Environmental Resea rch Center (EERC) indicate that measurements in the range of 0.5

– 1 microgram/dry normal cubic meter were accurate, however below this, the readings became less accurate due to extremely low Hg levels. EERC also indicated that they have never tested mercu ry CEMS at or below 0.1 microgram/dry normal cubic meter (which is still nearly four times above the proposed limit). Therefore, this mercury limit should be reconsidered since 1) continuous emissions monitors cannot accurately measure down to this level , and 2) sorbent traps are not a continuous monitoring technology and should therefore not be considered for this application.

## Summary of Interagency Working Comments on Draft Language under

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Page 15 of 38  New Units designed for coal > 8,300 Btu/lb: While the emission limits for most sources are higher than those included in the pro posed rule, the PM emission limits for the new coal units are significantly below the proposed levels. The new limits also appear to be well below the levels ever permitted in the US for coal

-fired boilers. Based on a rough calculation for a boiler firing a coal with 10% ash and a heating value of 12,000 Btu/lb, the fly ash loading assumed to be 80% of the total ash at the inlet to the particulate control device would be approximately 6.7 lb/MMBtu. With a stack emission limit of 0.007 lb/MWh (or roughly 0 .0007 lb/MMBtu), a device with a particulate control efficiency of 99.99% would be required to meet this limit. Since the coal ash content can be higher or the heating value of coal can be lower, the efficiency requirement for such coals would be even hig her. A plant may not be able to procure such a device. If the new PM emission limits are based on ICR data from a small number of units, EPA may want to look at the tested operating conditions, such as coal ash contents, and potential errors in reporting to confirm the validity of these limits.
**Coal subcategories**

 Page 389 : We agree with EPA on creating the coal subcategories based on high

- and low

- rank coals. However, this does not cover a situation where a plant decides to burn a mix of these two coal types (e.g., lignite and western coals). This could potentially happen, if a plant is aiming to control the coal mercury or chlorine contents to meet the specific emission limits in this rule. If a mix of the two coal types were fired in a boiler, u nder what subcategory would it fall?

 Page 394: We refer to a statement on this page: “We were particularly concerned about the CFB units because other CFB units are well represented among the best performing EGUs for Hg in the >8,300 Btu/lb subcategory, b ut the CFB units burning low rank, virgin coal are not achieving the same levels of control.” It is known that CFB’s, which have a higher percentage of unburned carbon (due to a more course fuel grind) than pulverized coal (PC) units, have lower emission s of Hg (due in large part to Hg capture by the unburned carbon). It is also known that fuels with higher concentrations of halogens (such as chlorine) are capable of high inherent levels of mercury removal, resulting in low emissions. Circulating fluidi zed beds burning coal >8,300 Btu/lb have all the necessary elements to achieve high levels of inherent mercury control, and should therefore be in a separate subcategory. This would ensure that all new and existing CFB’s meet the low Hg emissions that they are truly capable of. It would also ensure that new and existing PC units are not held to an unattainable standard set by failing to subcategorize CFB’s.

 Page 397: The first Coal

-fired EGU subcategory is based on units that fire coals with heating valu es of less than 8,300 Btu/lb and that are constructed and operated at or near the mines that produce such coals. Please note that certain types of units, e.g., cyclone

-fired boilers, may use low rank virgin coals and may not be located close to the coalmi nes for these coals. EPA should

## Summary of Interagency Working Comments on Draft Language under

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Page 16 of 38 consider either deleting the distance requirement or establishing a new requirement for plants that do not meet the distance criterion.

 Pages 445: We refer to a statement on this page: “The EPA believes that the data used to conduct the beyond

- the

-

floor analysis are consistent with results achieved in U.S. DOE Hg control technology demonstration projects. The DOE’s National Energy Technology Laboratory (NETL) sponsored a project entitled “Mercury Control for Plants Firing T exas Lignite and Equipped with ESP

- wet FGD”. In this project, URS Group evaluated sorbent injection for Hg control in an 85/15 blend Texas lignite/PRB

- derived flue gas. The authors of the final project.........” We would like to consult with EPA on the conditio ns of these tests and the interpretation of the data from the test results cited. For the short

-term test:

 What was the blend of coal being used? It should be confirmed whether this is a blend that would be representative of a unit that burns low rank, v irgin coal.

 The relative amount of removal (90%) is not the basis for justifying an emissions limit, but rather the actual Hg emissions. What was the absolute level of Hg emissions in units of Lb/GWh for the tests that achieved 90 percent removal? Does t hat data support the EPA selection of the Hg emissions limit for this category?

 The authors wrote at the bottom of page 3

- 16: “ Three of the brominated sorbents (DARCO Hg

- LH, B

- PAC, and CPAC) performed bery similarly with results indicating that 90% reduction of mercury was attainable at 2

-3 lb/Macf.” However, data for the short

term tests presented in Table 3

- 7 and Figure 3

- 7 indicate that one (not three) technology was able to achieve 90% reduction in Hg emissions at injection rates of 2

- 3 lb/Macf. If t he tests are determined to be a valid basis for supporting an Hg emissions limit for this category, DOE would like to consult on interpretation of the data. point. For the long

-term test:

 The report clearly indicates that for approximately 10% of the time during the long

-term test, the unit was firing 100% PRB (heating value >8,300 Btu/lb.) Would this invalidate the results as a basis for setting the emissions limit for units burning low rank, virgin coal?

 Assuming that the coal blend does not invalidate t he results as a basis for setting an Hg emissions limit for low rank, virgin coal: Would the test results over a 30 day compliance period demonstrate that the EPA emissions limit for this category is attainable? During the long

-term test, controlled Hg e missions were as high as 0.06 Lb/GWh, 50% above the proposed limit.

## Summary of Interagency Working Comments on Draft Language under

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Page 17 of 38  Page 466: We refer to a statement on this page: “Commenters assert that FBC units are disproportionately represented among the best performers, with the inference being that they were se lected because of their boiler design.” CFB boilers represent approximately 3% of the entire installed coal capacity in the U.S. However, CFB’s represent 35% of the MACT floor units. If CFB’s did NOT have unique properties with respect to Hg emissions t han the number of CFB’s in the floor would be much closer to 3%. The fact that such a large proportion of floor units are CFB’s is evidence that this is a unique boiler design that may warrant its own subcategory. The benefit of creating a separate subcat egory is that CFB’s may be held to a higher standard with respect to Hg emissions. In addition, other coal boiler technologies such as pulverized coal will be subject to a more appropriate emission limit that has not been skewed by including CFB emissions in the MACT floor calculation.

 Page 467: We refer to a statement on this page: “The fact that FBC units have “vastly dissimilar ash properties” that may contain higher levels of lime or unburned carbon in the fly ash than conventional PC EGUs does not in dicate that the overall system behaves any differently with regard to emissions to the atmosphere (the key metric) than a conventional PC EGU with add

- on controls.” This is accurately stated by EPA. However, the fact that an uncontrolled CFB is emitting s imilar levels of Hg as that of a controlled PC unit is the exact reason that they should be included in a separate subcategory. FBC is a unique combustion design that lends itself to low Hg emissions, and this should be recognized by creating an appropria te subcategory.

**Establishment of the Floor**
 We suggest EPA consider including an explanation of EPA’s rationale for why, when it regulates one HAP under section 112, it must regulate all HAPs for a source category, beyond just citing to National Lime case. Given the fundamental importance of EPA’s interpretation of this legal issue and because the supporting documentation for the rule does not provide the level of scientific evidence for the health risks associated with EGU emissions of acid gases (H Cl and HF) as it does for mercury, providing a cogent response on this point would be helpful (see comment on page 119).

 Page 412 : We refer to a statement on this page: “The language of the Act does not address whether floor levels can be established HA P

- by

- HAP or by any other means. The reference to “sources” does not lead to the assumption the commenters make that the best performing sources can only be the best

-performing sources for the entire suite of regulated HAP. Instead, the language can be reas onably interpreted as referring to the source as a whole or to performance as to a particular HAP.” Contending that the floor can in fact be established on a HAP

- by

- HAP basis is one possible interpretation; however, it does not seem to be a reasonable one . The floor is supposed to represent the top performing 12% of units. However, the 64 existing units that can meet the proposed limits represent less than 5% of all coal units in the United States.

## Summary of Interagency Working Comments on Draft Language under

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Page 18 of 38  Page 412 : We refer to a statement on this page: “The EP A agrees that this language refers to sources’ actual operation, but again the language says nothing about whether it is referring to performance as to individual HAP or to single facility’s performance for all HAP.” While the language in the Clean Air Act may not have been specific on this issue, a reasonable interpretation of the language would be that the intention was that of a single facility’s performance for all HAPs. The alternative, which was the approach taken here, resulted in limits that are n ot representative of the performance of the top 12% of similar units. It is therefore suggested that EPA abandon their HAP

- by

- HAP approach and adopt what was most likely intended by the Act, which was a unit

- by

- unit approach.

 Page 412 : We refer to a stat ement on this page: “The fact that Congress did not do so does not compel any inference that Congress was sub

-silentio mandating a different result when it left the provision ambiguous on this issue. The argument that MACT floors set HAP

- by

- HAP are based on the performance of a hypothetical facility, so that the limitations are not based on those achieved in practice, just re

- begs the question of whether CAA section 112(d)(3) refers to whole facilities or individual HAP.” Perhaps Congress was not in fact sub

- silento mandating a “plant by plant” HAPs approach by failing to specifically address this issue when the law was written. It certainly is not clear, and EPA acknowledges this: “The argument...re

- begs the question of whether CAA section 112(d) (3) refers to whole facilities or individual HAP.” The likely scenario is that the law never considered that such a possibility would arise, and therefore did not explicitly address it. However, it seems unlikely that Congress intended for a HAP

- by

- HAP approach t hat results in hypothetical limits based on the performance of a facility that does not exist. It is therefore suggested that EPA abandon their HAP

- by

- HAP approach and adopt what was most likely intended by the Act, which was a unit

- by

- unit approach.

 Pages 414 : We refer to a statement on this page: “The EPA’s long

-standing interpretation of the Act is that the existing and new source MACT floors are to be established on a HAP

- by

- HAP basis. One reason for this interpretation is that a whole plant approa ch could yield least common denominator floors

– that is floors reflecting mediocre or no control, rather than performance which is the average of what best performers have achieved. See 61 FR at 173687 (April 19, 1996); 62 FR at 48363

- 64 (September 15, 1997) (same approach adopted under the very similar language of CAA section 129(a)(2)). Such an approach would allow the performance of sources that are outside of the best

-performing 12 percent for certain pollutants to be included in the floor calculations for those same pollutants, and it is even conceivable that the worst performing source for a pollutant could be considered a best performer overall, a result Congress could not have intended. Inclusion of units that are outside of the best performing 12 p ercent for particular pollutants would lead to emission limits that do not meet the requirements of the statute” There are alternative ways to interpret the MACT floor requirements that would avoid the pitfalls described by EPA (best performing unit for on e HAP may also be worst

- performing for another), as well as the problems associated with the HAP

- by

- HAP approach interpreted in this rule (which results in emission limits of a theoretical plant which does not exist). We have suggested

## Summary of Interagency Working Comments on Draft Language under

EO s 12866 and 13563 Interagency Review. Subject to Further Policy Review.

Page 19 of 38 to EPA that they ra nk the HAPs emissions (for Hg, PM, and acid gas) of each plant relative to the best performing unit based on a HAP

- by

- HAP approach. Such a method would take into consideration actual emissions from plants (rather than performance of a non

- existent hypothe tical plant), while also avoiding the EPA’s concerns. Based on this approach, we estimated that for existing units burning coal > 8,300 Btu/lb, the limits would change as follows: PM: 0.048 Lb/MMBtu (increase from the proposed limit of 0.03 Lb/MMBtu); HCl : 0.01 Lb/MMBtu (increase from the proposed limit of 0.002 Lb/MMBtu); Hg: 1.5 Lb/TBtu (increase from the proposed limit of 1.2 lb/TBtu).

 Page 4 17 , 2 nd Paragraph: This paragraph cites one coal

-fired EGU that meets all of the final new

source emission limi ts. It would be helpful if you provide the number of EGUs that meet each of the new

- source limits separately. A small number of EGUs, especially if there is only one EGU, may not address the variability that may exist due to differences in coal characteri stics, unit designs, ambient conditions, and other site

- specific factors. The new

- source emission limits are out
- put based and all of these design factors would play a large role in the ability of a unit to meet the specified limits.

 Page 429 , Item 5: It should be noted that the public commen ts being discussed in this item were based on some of the very stringent emission limits included in the proposed rule. These limits have now been revised upward in the final rule. **Reliability**
 It would be helpful if the agency responded with greater specificity to the public comments received regarding EPA’s reliability analysis. Specifically, EPA received public comment on several key aspects of reliability analysis but EPA’s response appears to only generally touc h on some but not all of these issues.

 EPA’s resource adequacy analysis does not reach local or intra

- regional levels and the Agency has not analyzed system security.
 Transmission delivery not adequately addressed. Commenters noted that EPA has not anal yzed any transmission or delivery constraints within regions or on the local level, including system upgrade requirements. More specifically, commenters pointed out that even if EPA’s analysis found capacity is adequate in individual areas, RTO/ISOs would consider that capacity adequate unless it could be delivered.
 Transmission system upgrades not adequately addressed. Transmission system upgrades could include new transformers, circuit breakers, and line reconducting. Typical delay factors related to transmission upgrades include environmental permitting, siting issues, and financing. In addition, commenters noted that transmission upgrade costs did not appear to be included in EPA’s analysis and would be passed on to utility consumers.
 Load pockets n ot addressed. EPA has not addressed transmission issues for urban centers for which inadequate local generation exists. These load pockets import the bulk of their electricity via transmission lines.
 Frequency response not addressed. In order to provide stability, the system requires regulation and a uniform frequency response (60 Hz). Since at risk coal units are capable of

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Page 20 of 38 providing frequency response to balance out small changes that may take place on an hourly basis, retirement of certain units coul d degrade interconnection of the frequency response.  Relationship to Black Start Services not addressed. EPA has not addressed the rule’s impact on generation that can provide power to start other generation on the system in order to aid in system restor ation. Black Start Service is very location specific.
 Renewable energy transmission requirements not addressed. Within EPA’s resource adequacy analysis, the Agency’s assumptions regarding renewable energy offsets for coal retirements did not address the potentially long lead time necessary for pipeline siting and construction, and should not assume the offsets are 1:1 replacements for coal.
 In the Response to Comments section where EPA talks about the common flaws in industry retirement analyses, we suggests also explaining the fact that many of these studies ignore lower cost compliance options such as dry sorbent injection (DSI). This could be included as another example of overstating the stringency and impact of the rules, and it is more directly relevant than the cooling water intake rule assumptions.

 In response to retirement projections and reliability concerns cited by a commenter, EPA responds that most studies projecting over 10 GW of retirements do not hold up to scrutiny and that many tool s exist to maintain reliability (including new generation, demand response, energy efficiency, transmission upgrades, and energy storage). First, EPA’s retirement analysis relied heavily on the installation of DSI for compliance, which few of the many stu dies disparaged by the EPA did. **More detail on EPA’s sensitivity case where “less DSI systems and more scrubber systems were installed” is required.**  In this case, DSI was limited to 35GW on installation and only one more GW is retired as compared to the base analysis. However, in modeling frameworks, it is likely that the most optimal units for DSI will get the technology, then other units will install FGD. Where the real sensitivity would become apparent is limiting DSI by size and coal type, which woul d show the limitations of the technology. In addition**, the retirement projections rely heavily on low natural gas prices**  **– a higher gas price sensitivity**  **analysis is required.** In addition, many of the reliability measures cited by the EPA are still in th e developmental stages or potentially very costly

– **EPA should have also factored the costs of maintaining reliability into their analysis.** 

 Page 514 : We refer to a statement on this page: “Commenters cite recent electricity forward capacity market auctions in the PJM and ISO

- New England markets for the period of 2014 and 2015 that indicate that the capacity markets cleared with electricity reserve margins of 20 percent in PJM and greater than 14.4 percent in ISO

- New England; these reserve margins are well in excess of the default reliability targets used by the North American Electric Reliability Corporation (NERC

) for the year 2015.” Please note that res erve margins are not within NERC limits. While the actual reserve margins from the capacity auctions a re accurate
– the NERC target reserve margin is 15%, so ISO

- NE will be below accepted ranges. NERC Working Groups have identified 2015 as when ISO

- NE will drop below reserve targets. The phrase referencing ISO

- NE should be revised to correctly capture th e results of the auction. The ISO

- New England

## Summary of Interagency Working Comments on Draft Language under

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Page 21 of 38 2014

- 2015 capacity markets cleared with more than 3,000MW of capacity in excess of its standard reserve margin for installed capacity of 14.4%.

 Page 514 : We refer to a statement on this page: “One commenter quoted NERC , stating that NERC does not see impacts from the proposed climate legislations or anticipated EPA regulation as a reliability concern.” We note that NERC may not have made a blanket statement that proposed regulations are not a reliability co ncern. What NERC has publicly stated in the Executive Summary of the Special Assessment: “The results of this assessment show a significant potential impact to reliability should the four EPA rules be implemented as proposed.” and a headline of “Proposed EPA regulations may have significant impacts on forecast planning reserve margins” and numerous other similar comments.

 Page 517: “ Although such an analysis does not address the potential for more localized reliability concerns associated with transmission constraints or the provision of location

-specific ancillary services (such as voltage support and black start service), the numb er of retirements projected suggests that the magnitude of any local reliability concerns should be manageable with existing tools and processes.” While local reliability concerns may be addressed with existing tools and processes, this requires early not ification by power plants of their intent to deactivate. Absent early announcement of plant retirements, regions may not be adequately prepared to handle reliability concerns given current limited announcement obligations within their regions. This is addr essed in subsequent comments.

 Page 522: We refer to a statement on this page: “As a preliminary matter, none of these situations, either alone or in combination, will necessarily lead to an electric reliability problem.” We note that NERC and the vario us ISO/RTOs have identified potentials for local reliability issues as any of these situations occur. (Source: NERC LTRA 2010. http://www.nerc.com/files/2010_LTRA_v2

- .pdf

.

 Page 522: We refer to a statement on this page: “As explained above, our modeling of the impact of this final rule at the regional level projects retirements of less than one percent of nationwide generating capacity and confirms that there will continue to be adequate capacity in all 32 sub regions of the country as sources comply with the rule.” Already 26+ GW have been publically announced for retirement

– SNL data shows 27.5 GW publicly announced as of Oct 5.

 Page 522: “As a preliminary matter, none of these situations, eith er alone or in combination, will necessarily lead to an electric reliability problem. There is excess generating capacity in the U.S. today and in most cases an EGU that closes, either temporarily until it comes into compliance or permanently, will not cause a reliability problem.” Using resource adequacy to blanket

statement that electric reliability problems are not a concern is different than the public comments provided by those entities in charge of ensuring bulk reliability of the power system. Moreover, the EPA has not conducted any analyses using advanced power flow models to identify potential localized reliability impacts. To state that excess generating capacity is

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Page 22 of 38 indicative of a secure power system is flawed. To cite comments from PJM (see Corrected Comments of PJM Interconnection, L.L.C., August 4, 2011) “It is not sufficient to assume that because the region as a whole has sufficient resources, that local reliability is automatically maintained.” NERC defines reliability as addressing both resource adequacy and system security (see http://www.nerc.com/page.php?cid=1|7|114 ). The EPA has only addressed resource adequacy in their evaluation of the rule’s impact on reliability. The EPA has no t conducted analyses which evaluate transmission security. As such, the EPA can only comment on reliability from a resource adequacy standpoint, not as a whole.

 Page 524: We refer to a statement on this page: As we said before, in most places a closing plant will not be a cause for concern. To the extent there is concern, however, early notification will provide an opportunity for transmission planners, market participants, and state authorities to develop solu tions to avoid a reliability problem. In RTOs with forward capacity markets, owner/operators that do not bid generating capacity that they plan to close will provide an advance signal to market participants to take action to assure adequate future capacity.” That signal has not yet occurred. For several years of forward capacity auctions, minimal new generation and transmission have been built. In most instances, DSR has been the largest resource to take advantage of the lack of Generation & Transmission Resources and is almost over- saturated.

 Page 523: “First as we said in the proposal, early planning is key.” Page 524: “Second, companies that intend to retire EGUs should formally notify their RTO (or comparable planning coordinator in the case of non

- R TO regions), state regulatory agencies, and regional reliability entities as soon as possible that they will retire.” Page 525: “Although EPA does not have the authority to require such early notification, it strongly encourages it and believes that respons ible owner/operators should and will do the early planning for compliance and provide early notification of their compliance plans, especially where such plans include retiring one or more units.” Wholesale markets do not have the ability to force units to announce retirements. Their tariffs, as approved by FERC, obligate units to announce retirements with as little as 45 days notice. If the RTO/ISO’s cannot identify which units will retire, and if units have a motivation to remain operational as long as po ssible, then there is no mechanism to provide early planning in the competitive wholesale electricity markets. Units that wait to decide whether or not to retire until obligated to do so have a competitive advantage, since the retirement of other generati ng units may result in larger revenue shares via additional transmission congestion charges paid to a unit or through overall higher locational marginal prices (LMPs) that result from the retirement of a unit with lower production costs. Thus, a unit that waits to announce retirement until the last possible chance gains two advantages: either it realizes that the retirement of other units nearby increases the costs on the system, thereby increasing the revenue for such a generator to continue operation, and thus

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Page 23 of 38 making it economical for the generator to retrofit control technologies if feasible from a time perspective, or, if the economics of the unit are still not realized to retrofit control equipment then the unit announces its retirement at the last mome nt and has benefited from energy payments received up to that point in time. Therefore, there is no advantage for generators to announce retirements early in a competitive wholesale electricity market since this disadvantages the generating unit from poten tially benefitting from the increased system costs resulting from the retirement of other units. This is consistent with public comments from PJM. EPA’s comments do not provide justification fo r units to announce retirements in competitive markets as early as would be beneficial for regional grid reliability planning purposes. Therefore, EPA should acknowledge the limits to its authority and recognize the other sources of authority that are responsible for the minimum notification periods for retirement..

 Page 526: “With regard to transmission, recent experience also shows that, in many cases, transmission upgrades to address reliability issues from plant closures can be implemented in less than 3 years.” While this is true, the rule does not provide ince ntives for plants to announce retirements prior to RTO tariff obligations. As stated in EPA’s comments, RTO’s only obligate plants to announce retirements with 45 to 120 days notice, depending on the region. Absent incentives from the EPA to announce early retirement, and in considering competitive market advantage to delay announcing retirement, plants may continue to operate until obligated to retire. As such, even though transmission upgrades can be completed in less than 3 years, there is no guarantee t hat RTO’s will be afforded that amount of time based on when units announce their retirement. Moreover, while there as some cases of transmission upgrades being completed in less than 3 years, there are other cases which can be cited as taking longer, up to 5 years or more (see Corrected Comments of PJM Interconnection, L.L.C., August 4, 2011 in reference to Buzzard Point and Benning Road Deactivation Studies).

 Page 556: We refer to a statement on this page “The Agency has studied possible impacts on reliability as a result of this rule, and has determined that these impacts should not be significant and industry, along with relevant Federal Agencies, have the tools needed to address any reliability concerns.” The problem, once again, is the EPA analysi s does not take into account the cumulative effect of various EPA rules that cou ld affect reliability

 Page 556: We refer to a statement on this page: “The Agency did not prepare a cumulative impact analysis to accompany the rule for the following reasons... 2) decision makers and the public need to know the impacts specific to a particular rule in order to judge the merits of the regulation.” Decision makers and the public also need to know the cumulative impacts of various rules in order to judge the merits of the group of regulations. Additionally, Executive Order 13563 directs each agency to tailor its regulations to take into account the costs of cumulative regulations.

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Page 24 of 38  Page 563: “the commenter states, some claims linking retirements to the Toxics Rule are overstated and misleading. The commenter gives the example of the American Electric Power attempt to link its planned plant closures to the Toxics Rule, but those plants already are slated to either close or to upgrade controls to comply with existing laws... **Response:** EPA thanks the commenter for these observations and agrees with the findings of the independent studies mentioned by the commenter.” While these plants were already slated to eventually retire due to compliance with existing laws, the MATS rule resulted in these plants retiring much sooner than expected. Hence, this comment is misleading (and EPA’s agreement with the commenter) since the MATS rule did in fact push the retirement date up for such units. Therefore, the EPA should consider such retirements as being impacted by the MATS rule, and at the very least, consider them in a reliability analysis of the rule. While some debate may center around whether these plants will retire due to MATS, it is unclear whether EPA considered these planned retirements and other more recently announced retirements in their analysis, ultimately leading to their presumption that electric reliability is not impacted. Moreover, the recent study fro m the MISO ( EPA Impact Analysis; Impacts from the EPA Regulations on MISO, October 2011) identifies up to 13 GW of at risk plants when considering the cumulative impact of EPA regulations (CSAPR, CWA, CCR, MATS). While this analysis considers the cumulativ e impact of EPA regulations, it does note: “compliance associated with the Mercury and Air Standards (MATS) produces the most at

- risk units, since its compliance costs and emission reductions have the greatest impact of the proposed regulation.” This concl usion is counterintuitive to the above claim that retirements due to MATS is overstated.

 Page 599: We refer to the statement on this page: “Under the provisions of this proposed rule, the EPA projects that approximately 5.5 GW of coal

- fired generation (

less than 2 percent of all coal

- fired capacity and 0.5 percent of total generation capacity in 2015) may be uneconomic to maintain and removed from operation by 2015. These units are predominantly smaller and less frequently used generating units dispersed throughout the country.” The EPA retirement estimate of only 5.5 GW does not consider the numerous other regulatory initiatives being pursued by EPA, including NSPS, MATS, 316(b), coal combustion residuals, and CO2. When considered collectively, the act ual retirements are likely to be much higher. It is recommended that EPA consider the full suite of regulatory proposals to obtain a more accurate estimate of coal retirements. **DSI Costs**
 Page 516 , 1 st Paragraph: We agree with EPA’s approach in performing a sensitivity analysis to evaluate the impact of the affected sources installing fewer DSI systems and more wet scrubbers on the grid reliability. We recommend that EPA report the cost increase (both capital and annual costs) for this sensitivity case in the preamble.

 Page 537 : EPA has quoted in detail one commenter who appears to have provided no data to back up the claims on the efficacy of DSI technology for HCl removal. This commenter also

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Page 25 of 38 states that DSI may not provide full HCl control in some sit uations (without defining those situations). In addition, in EPA’s response, there is only a mention of DSI being used for SO 2 control and nothing about HCl control. We recommend that EPA provide more HCl

- related information.

 Page 5 41 : We refer to a statement on this page: “Non

-sodium based sorbents such as hydrated lime (calcium based) could also be used.” At the Air Quality VIII Conference in October 2011, Jim Dickerman, Director of Flue Gas Treatment Applications at Lhoist North A merica, gave a presentation on the use of dry sorbent injection using hydrated lime for MATS acid gas control. He explicitly stated that for units that are equipped with ESP’s, they could not achieve the acid gas compliance standard (0.02 Lb/MMBtu) and wo uld provide no such performance guarantees. For units with fabric filters, he stated that limited testing indicated that the acid gas limit may be achievable, but only at extremely high sorbent injection rates (no figures were given). A high sorbent inje ction rate adds to the flue gas particulate loading, causing problems for other downstream control technologies. For this reason, EPA should not assume that hydrated lime could be used for acid gas control. This again raises the issue of only trona being available to use for DSI, which has serious supply and distribution constraints as noted previously.

 Page 5 43 , 2 nd Paragraph: It is stated that, for units with EPSs and burning western coals, HCl limit can be obtained with DSI, without the addition of a baghouse. We recommend that a potential need for the existing ESP upgrade be mentioned here. **Employment Effects**
 Page 5 4 9: We refer to a statement on this page: “The Agency found that the impact on employment nationally should be small on net...” EPA should also note that there would be a decrease in labor productivity (i.e., more labor required to produce the same amount of electricity), which would cause the short

- run aggregate supply curve to shift to the left, resulting in higher prices and busines ses producing less (i.e., lower GDP).

 Pages 569 and 550, Last Paragraph: Please confirm if any of the commenters has referenced a study or provided any data to back up their claims on the adequacy of labor availability. We would also appreciate receiving a copy of the TSD referenced in EPA’s response.

 Page 603: We refer to the statement on this page: ““...each additional $1 million spending on pollution abatement results in an small net increase of 1.6 jobs; the estimated effect is not statistically signi

ficant different from zero.” It seems better to simply state the study finds spending on pollution abatement does not have a statistically significant effect on jobs. EPA’s analysis should also point out that there would be a decrease in labor productivi ty (i.e., more labor required to produce the same amount of electricity), which would cause the short

- run aggregate supply curve to shift to the left, resulting in higher prices and businesses producing less (i.e., lower GDP).

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Page 26 of 38 **Cumulative Effects of EPA Rul es**   Page 5 5 7: We refer to a statement on this page: “...the direct benefits from the 1990 Clean Air Act Amendments reach almost $2 trillion for the year 2020...” What was the effect on real GDP? This is a more relevant measure for decision makers than social costs, as changes to GDP growth are what determine whether the economy is experiencing a recession . We suggest EPA delete the discussion of this report, since it is not relevant to the rulemaking at hand. **Benefits**
 For the final rule, the only mercury be nefit that can be quantified either in economic terms or by a widely understood measure

– the total nationwide increase in IQ which results from a 90% reduction in utility mercury emissions

– are removed from the main body and are put in an appendix. Thes e findings are replaced by a “hazard quotient.” People understand what IQ points mean: if the MATS rule were to have caused children born of mothers who ate fresh caught fish (whose mercury levels were influenced by power plant emissions) to gain an averag e IQ of 5 points when power plant mercury emissions were sharply reduced, we would all have understood what an important public health gain had been achieved. No explanation would have been needed. However, EPA has now found that of the 240,000 children b orn of mothers who eat fish influenced by power plant emissions, the total IQ gain nationwide from the 90% reduction in power plant emissions is 510 IQ points, also expressed in the documents as 2/1,000 of an IQ point per child. EPA calculates the monetiz ed benefit of this increase of 510 IQ points nationwide to be between $500,000 and $6 million, depending on assumptions such as discount rates. The benefit is based upon total lower lifetime wages due to the reduction of 510 IQ points, and contrasts with costs of the regulation of about $11 billion. This finding is good news. It means that pregnant women can now be told that US mercury emissions will not harm the intelligence of their unborn child. Wouldn’t it be a good idea to make sure that readers of this document now know that they are safer than they might have previously thought? Public health findings aren’t always about harm we have found, but also about harm we suspected but later found not to be of concern. In contrast, the use of a “hazard quo tient” has no intuitive meaning to people. Further, it isn’t clear what actual harm exists if the hazard quotient is above 1.5 (the level at which a hazard is said to exist). There is suggestion of risk, but is the risk of a similar magnitude of the IQ r isks, now quantified? Of less risk of harm to health than the IQ risks? Therefore the suggestion is to also include, in the body of the Final Rule (instead of in an Appendix), the quantifiable (and positive) findings that virtually no adverse effect on IQs have occurred from US mercury emissions (because virtually no benefit occurs from a 90% reduction in such emissions). This appears to be news which anyone interested in health effects of mercury would want to know.

 Page 619: Table 9: Since some stu dies have found no significant effect of PM2.5 on mortality, perhaps zero should be included in the range of PM2.5 benefits, as Electric Power Research

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Page 27 of 38 Institute has suggested. EPRI indicated: “Since some models in some studies do not find a statistically significant effect of PM2.5 on mortality, the effects range could even include zero...” (Source: EPRI PM2.5 Reductions and Impact on Premature Death: An EPRI perspective; Issue Brief 1018632.) Also, the same EPRI briefing states the EPRI

- Washington Univers ity Veterans Study did not find any statistically significant mortality associations with PM2.5, but found some PM components that were significantly associated with mortality. The EPRI briefing goes on to say: “Of great significance for CAIR, this study did not find a significant association between the sulfate component of PM and mortality...if this study were used to derive estimates of health benefits attributable to reductions in SO2 emissions, the numbers would differ from those derived from the Pope e t al...some studies have shown that estimated impacts of PM diminish when other co

- pollutants are considered in the analyses. If the co

- pollutants are indeed associated with increased mortality and are correlated with PM levels, then the PM effects estimat ed from this single pollutant model approach can be biased upwards.”

 Page 628: We refer to the statement on this page: “The fourth value is the 95 th percentile of the SCC from all three models at a 3 percent discount rate.” Why not include a fifth value at the 5 th percentile in order to represent lower

-than

- expected impacts from temperature change

 We strongly recommends that EPA provide a much clearer explanation regarding the mercury benefits of this rule. The mercury benefits quantified in the cost/benefit sections include only a small portion of the total benefits of the mercury reductions projected from the rule

– o nly the IQ loss from children exposed to recreationally

- caught freshwater fish. It is entirely unclear from the preamble to the rule, the executive summary in the RIA and other summaries of the costs/benefits of the rule that the “Hg

- related benefits” rep resent such a small subset of the Hg benefits. We strongly suggest clarification of these benefits by, for example, changing tables to read “Partial Hg

- related benefits (recreational freshwater fish IQ effects only)” or some other similarly explicit langu age.
**Comments on the Regulatory Impact Analysis**
 Industry does not make retirement decisions based upon one regulation, but on the entire group of regulations. Therefore, a more accurate and comprehensive RIA would look at the aggregate effect of proposed and recently promulgated EPA rules. EPA should include these aggregate costs for all proposed and recently promulgated rules. Executive Order 13563 directs each agency to tailor its regulations to take into account the costs of cumulative regulations.

 E PA may want to include in the RIA an analysis of the effect of the regulation on U.S. Gross Domestic Product (GDP). Such an analysis would be a useful measure of whether the policy is cost

- effective. Similarly, it would also be useful to estimate the eco nomic effect of the rule at the state level (e.g., state GDP). This would serve to satisfy Executive Order 13563, which states that the regulatory system should promote economic growth.

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Page 28 of 38  Employment Impacts Due to Increases in Electricity Prices Are Not Accounted For The Executive Summary (ES) of the RIA (and ensuing portions of subsequent chapters of the RIA) discuss two types of employment impacts stemming from these regulations

– see pg. 14 of the ES. The first type is changes in employment over time in the effected industry, in this case the electric utility industry. The second type is short term increases in employment for construction of pollution control equipment prior to compliance dates. These impacts are summarized in Table ES

- 6. Long term employment changes in the electric utility industry are estimated to be about 8,000 jobs, but the estimate is said to be not statistically different than zero. Short term employment gains are estimated to be about 47,000 jobs. Both these estimates are for increased employment. The comment is that by far the largest employment effect due to the MATS regulation is likely to be a substantial increase in unemployment because of increased electricity prices. Regulations which increase electricity prices resul t in lost jobs because of reduced purchasing power across the economy because of these higher electricity prices. Many firms across the US will do marginally less business because households and businesses will have less disposable income, as a result of paying more for electricity. And when these firms do less business, they need fewer workers. Thus fewer workers will be hired in expanding businesses and more workers will be let go in contracting ones; some such firms will close down. Deschenes (2010) finds that every 1% increase in electricity prices causes a nationwide reduction in employment of between 0.1% and 0.16%. The total US civilian labor force as of Oct. 2011 is 154.2 million. In his preface, Deschenes thanks Michael Greenstone, the Obama Administration’s first Research Director of the Council of Economic Advisors for helpful advice. The RIA ES states (pg. 14): “Retail electricity prices are projected to increase in the contiguous US by an average of 3.0% in 2015 with the final MATS Rule.” It also states that natural gas prices will be higher than they would otherwise be, but we do not try to estimate unemployment impacts of higher natural gas prices. Multiplying 154 million US workers by 0.3% and by 0.48% (three times 0.1% to 0.16% to re flect the estimated 3% increase in electricity prices) gives a total unemployment increase of from 462,000 (low end) to 739,000 workers (high end). These would be the dominant estimated unemployment effects caused by the MATS regulations. If instead of t otal number of employed people, the 154 million person civilian work force, we used Full Time Equivalent (FTE), as in Deschenes (2010), the unemployment estimates would be lower by about 43%; however, FTE would not include self employed workers (Deschenes, 2010), so FTE estimates of unemployment would be biased low. Thus the estimate of the number of unemployed workers as a result of the higher electricity prices stemming from MATS would be between the FTE and Civilian Work Force estimates. Presumably ther e are other estimates of the cross elasticity of unemployment with respect to energy prices, so these estimates using cross elasticities from Deschenes (2010) may be low or high. The important point is that the unemployment created by higher electricity

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Page 29 of 38 p rices should be included in the RIA. Reference: Deshenes, O. 2010. Climate Policy and Labor Markets. Working Paper 16111. National Bureau of Economic Research.

 Electricity Price Increases (and thus Increased Unemployment) from MATS May Be Understated When Interaction with Other Electricity Rate Impacts from Other Regulations are Taken Into Account According to the ES, only 5.5 MW of coal units are expected to retire as a result of the MATS rule (pg. 14). Does this estimate include retirements which m ight occur when a unit which must comply with the new MATS rule must also comply with other new air quality and water quality rules, including (for air quality) rules regarding (1 through 3) NO 2, SO 2, and PM National Ambient Air Quality Standards, (4) Visi bility Rule, and (5) Cross State Air Pollution Rule? Some EGUs which might be able to continue to operate economically while installing technology to meet MATS may no longer be able to operate economically if they also have to add additional technologies to meet other rules noted above. If each rule analyze s coal unit retirements based upon the impact of each rule only by itself, e.g., if the MATS rule does not take into account costs that will occur due to other regulations, then plant retirements due to the combination of new regulations, and thus electric ity price increases, may both be greater than impacts analyzed for MATS alone, or on a rule by rule basis. It would therefore be crucial for EPA to estimate the number of coal units retired based upon the combined rules, and the resulting electricity pri ce increases. Further, the increase in unemployment as a result of the combined rules should also be calculated. Pg. 14 (not a typo) of the RIA for the Cross State Air Pollution Rule states: “Retail electricity prices are projected to increase nationally by an average of 2.5 % in 2012 and 1.5 % in 2014 with the proposed Transport Rule.” This appears to be an additional 4% increase in electricity costs, relative to the MATS rule. Would these costs increase, and added coal plants (other than those assumed to be retired in the Cross State [Transport] rule) retire, when MATS requirements are added to those of the Cross State rule on a plant by plant basis? The same argument pertains when other air quality rules (such as the upcoming PM rule) are promulgated . Thus the actual electricity price increases, and the actual unemployment estimates due to higher electricity prices, may be understated when interactive effects are considered. We would like to ask EPA to clarify whether costs impacts on individual EGU s from rules other than MATS are considered when determinations are made as to whether MATS will cause such units to retire. If the answer is affirmative, which of the new rules are considered in this context? If the answer is negative, would EPA be will ing to consider joint effects, in order to re

- estimate the number of coal units retired, and the resulting additional electricity price increases?

 Estimated Benefits in MATS Include Reduction in Mortality from PM 2.5 at Levels Below the National Ambient Air Quality Standard (NAAQS) for PM 2.5 The current NAAQS as well as the new NAAQS that is under consideration both set levels for

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Page 30 of 38 daily and annual PM 2.5 concentrations which are said to be protective of public health. If PM 2.5 concentrations are above either the daily or annual level in a given locality, states must create a plan to reduce concentrations down to that regulatory permissible level. If PM 2.5 concentrations are below these legal concentrations, then nothing more need be done to protect the publi c health. NAAQS standards are subject to public review. In estimating benefits from MATS, EPA assumes that PM 2.5 concentrations at levels well below the NAAQS standards, down to nearly background levels, cause premature mortality. In making this assumpti on, EPA essentially changes the level of harm in the PM 2.5 NAAQS to levels far below those in the NAAQS. Two questions thus arise:

 Should the assumption of a linear dose

- response function down to roughly background levels be subject to public review befor e being used in a RIA?

 What would be the benefits (and cost to benefit ratios) in the RIA if only mortality above, but not below, the NAAQS were included?

 Determining Toxicity of Individual PM 2.5 Species, Relevance to MATS RIA

 Since 1996, scientific adviso ry bodies to EPA (such as the National Research Council of the National Academy of Sciences) have suggested that different PM 2.5 species are likely to have different toxicity, and that EPA should use toxicology and other means to determine which PM 2.5 spec ies are most, or least harmful. In March, 2009, on

-the

- record public comments were submitted to EPA by DOE/FE staff suggesting a means by which toxicity of specific PM 2.5 species could be determined. In the 2009 Integrated Science Assessment (ISA) for PM, EPA has established several excellent criteria for judging the degree to which PM 2.5 may be causally related to various health endpoints. The comments suggested that EPA could take advantage of the large number of new studies available, then and especial ly now, and use the criteria in the ISA to estimate the degree to which individual PM 2.5 species may be causally related to the health endpoints considered (such as cardiovascular mortality). To be clear, the suggestion was not that EPA create “speciated standards” for particularly toxic PM 2.5 species (e.g., black carbon). To do so might take several years. Rather, the suggestion was that EPA use its excellent criteria to determine the strength of evidence for the toxicity of important PM 2.5 species. To do so would enable states, in developing plans to reduce PM 2.5 concentrations, to preferentially reduce the most toxic species. The suggestions made in March 2009 are relevant to the MATS RIA, because only particular PM 2.5 species are reduced using the t echnologies needed to reduce mercury emissions by 90%. These species are largely inorganic salts. Should an EPA analysis of the degree to which individual PM 2.5 species may be related to mortality be undertaken, the results could have relevance to the be nefits estimates in the MATS RIA.

 We will not repeat in detail here why it is crucial to utilize studies which include many PM 2.5 species (if an important PM 2.5 species is not included in a study, different PM 2.5 species might rise to the level of a statis tically significant risk only in the absence of such species). Nor will we repeat in detail why it is important to use pollution data that reflects subject exposure reasonably accurately (without good subject exposure, the significance and levels of healt h

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Page 31 of 38 risks for pollutants whose concentrations are variable across a city will likely be understated, and risks might be “transferred” to pollutants with less spatial variability). We merely note the importance of these issues for reference.

**Additional RIA Comments**  **Section ES.2, Page ES -**  **8:** “EPA believes these unquantified benefits are substantial...” It is not clear what value signifies a cutoff between what is substantial and what is insubstantial **Page ES -**  **3: “**We also include in our monetized benefits estimat es the effect from the reduction in CO 2 emissions resulting from this rule.” EPA repeatedly makes a point of not analyzing the impacts of other emission rules on coal retirements, but does not seem to have a problem assigning the benefits to other emission s from this rule. **Table ES**
**- 3:**  there appears to be discrepancies in the calculated monetary value of avoided IQ loss that should be reconciled. Table ES

- 3 states that, at the 7% discount rate, the estimated monetary value of avoided IQ loss associated with methylmercury exposure from self

- caught fish consumption among recreational anglers is reported between $0.000005

–$0.000009 (in billions of 2007$). The Table also states that, at the 3% discount rate, the value is reported between $0.004

–$0.006. The value s at 3% and 7% appear to be inconsistent with each other. **Section ES.4, Page ES -**  **15:** “Of the 83 small entities affected, 49 are projected to have costs greater than 1 percent of their revenues.” Perhaps EPA should implement a policy to help protect these 49 small entities from proportionally large cost increases. **Chapter 3: Page 3**  **- 5: “**  Mercury emissions are modeled as a function of mercury content of the fuel type(s) consumed at each plant in concert with that plant’s pollutant control configuration.” Assu ming that EPA uses the USGS’ COALQUAL database, there a some issues that could arise from the use of this data. First, COALQUAL is over 10 years old (1998) and second, it does not account for Hg reductions that could occur from coal washing, and only has the Hg content of coal as it is in the ground. **Page 3 -**  **5:** “Total PM emissions are calculated exogenously to IPM, using EPA’s Source Classification Code (SCC) and control

- based emissions factors.” Combined with ES

- 1 “The great majority of the estimates are attributable to co

- benefits from 4,300 to 11,000 fewer PM 2.5 - related premature mortalities.” There seems to be a large disconnect between the fact that PM emissions are exogenously calculated and the fact that they show the largest portion of the benefits. **Page 3 -**  **7: “**As noted above, IPM has been used for evaluating the economic and emission impacts of environmental policies for over two decades.” Has any retrospective analysis been done comparing IPM projections and actual reality? There is no indication t hat even though the model has been used for decades that is does a good job predicting what will really happen. **Page 3 -**  **12, Figure 3 -**  **6:** Based on information presented during the discussions on the proposed rule, EPA was showing a substantial number of existing FGD upgrades resulting from this rule. These upgrades have not been mentioned in the preamble or in the RIA. If the number of these upgrades is substantial, they should be shown in Figure 3

- 6 and their impact should be discussed in detail. In the I PM manual documents, a cost of a scrubber upgrade is shown as an allowance of $100/kW. However, this cost is shown only as a fixed O&M cost. We do not agree with this, since a scrubber upgrade would involve expenditure of capital. Such an upgrade would normally require modifications to the scrubber vessel, replacement of auxiliary equipment, etc. If a substantial number of such upgrades are required under this rule, these capital costs cannot be ignored. In addition, the fixed O&M costs will go up as w ell

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Page 32 of 38 as there would be additional variable O&M costs, since sorbent injection rates would generally have to be increased and/or injection of additives may be required. Page 3

- 12, Figure 3

- 6: Since ESP upgrade was not an option used in the analyses for the proposed rule, we recommend that additional information be provided on this option, either here or in the IPM manual document. We would like a confirmation that only those ESP upgrade techniques have been used that do not require extended plant outages to install. For example, a project involving extension of ESP surface area may require an outage lasting more than two years. Such long outages may become another factor contributing to the grid reliability issue. **Page 3 -**  **12, Figure 3 -**  **6** : Please provide the updated IPM manual document that shows how the costs of ESP upgrade were estimated. **Page 3 -**  **25: “**The direct private compliance cost includes, but is not limited to, capital investments in pollution controls, operating expenses of th e pollution controls, investments in new generating sources, and additional fuel expenditures.” No accounting for reliability measures in the compliance costs. **Section 4.1, Page 4 -**  **1, Paragraph 2** : “It is not expected that mercury benefits would be substanti ally changed, and given the small magnitude of the benefits...” It seems odd that the majority of the benefits of the rule do not come from Mercury, since a major goal of the rule is to reduce mercury. Since the vast majority of benefits come from reducing PM 2.5, is there a more cost

- effective approach to reducing PM 2.5 than the Mercury and Air Toxics Standard? This would serve to satisfy Executive Order 13563, which indicates regulations should be chosen that maximize net benefits. **Section 5.2.2, Page 5 -**  **11: “The appropriate economic measure is therefore ex ante Willingness to Pay (WTP) for changes in a risk.”**  In general, willingness to pay (WTP) is problematic because there are an infinite number of areas individuals could be asked to place a value on, ye t individuals have a finite budget; thus, it seems likely that WTP would likely overstate what an individual would actually be willing and able to pay. Therefore, WTP should be constrained to not exceed a typical individual's budget. **Section 5.3, Pages 5 -**  **19 and 5**
**- 20:**  The assumption that all fine particles are equally potent in causing premature mortality is important, as changes to premature mortalities make up the vast majority of total benefits. Since some studies have found no significant effect of PM2 .5 on mortality, perhaps zero should be included in the range of PM2.5 benefits, as Electric Power Research Institute has suggested. EPRI indicated: “Since some models in some studies do not find a statistically significant effect of PM2.5 on mortality, th e effects range could even include zero...” (Source: EPRI PM2.5 Reductions and Impact on Premature Death: An EPRI perspective; Issue Brief 1018632.) Also, the same EPRI briefing states the EPRI

- Washington University Veterans Study did not find any statistically significant mortality associations with PM2.5, but found some PM components that were significantly associated with mortality. The EPRI briefing goes on to say: “Of great significance for CAIR, this study did not find a significant associati on between the sulfate component of PM and mortality...if this study were used to derive estimates of health benefits attributable to reductions in SO2 emissions, the numbers would differ from those derived from the Pope et al...some studies have shown that estimated impacts of PM diminish when other co

- pollutants are considered in the analyses. If the co

- pollutants are indeed associated with increased mortality and are correlated with PM levels, then the PM effects estimated from this single pollutant model approach can be biased upwards.” **Section 5.4.2.5, Page 5 -**  **35:** “Although the association was not statistically significant for cough, the results were still positive and close to significance; consequently, we decided to include this endpoint...” It does not m ake sense to use a statistically insignificant result in deriving estimates. If the sign had been negative, would it have been included? **Section 5.4.4.1, Page 5 -** **42:** “Given the mixed theoretical finding and empirical evidence regarding adjustments to VSL for risk and population characteristics, we use a single VSL for all reductions in

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EO s 12866 and 13563 Interagency Review. Subject to Further Policy Review.

Page 33 of 38 mortality risk.” It seems more logical to use a range of value of statistical life (VSL) estimates, rather than a single value, in order to account for the uncertainty in the measure. **Section 5.4.4.1, Page 5 -** **43** : “An ideal benefits estimate of mortality risk reduction would reflect these human characteristics, in addition to an individual’s WTP to improve one’s own chances of survival plus WTP to improve other individuals’ surv ival rates.” Capturing the WTP to improve other individuals’ survival rates would be an example of a non

- use value, thus creating a bias. Individuals likely also place a value on non

- use things such as less government regulation; for instance, Executive O rder 13563 directs Agencies to “identify and consider regulatory approaches that reduce burdens and maintain flexibility and freedom of choice for the public.” **Section 5.4.4.2, Page: 5 -** **46** : WTP for avoiding chronic bronchitis ($340,000) likely exceeds an a verage individual’s budget, especially after considering essentials such as food, clothing, housing, etc. $340,000 is greater than six years of income for an individual earning $50,000 per year. **Section 5.4.4.1, Pages 5 -** **40, 5 -** **42:** “The VSL approach is a summary measure for the value of small changes in mortality risk experienced by a large number of people.” On page 5

- 42, EPA indicates it uses a VSL of $6.3 million. This seems to be an unreasonably large value. A more practical measure of the value attr ibuted to an increase in expected life for the affected individuals would be the amount of income these individuals could expect from living longer due to the rule. This would have the effect of preventing the number from exceeding an individual’s remainin g lifetime income, since one cannot pay more than that amount. So, if the average affected individual could be expected to earn $250,000 more during his or lifetime, multiplying $250,000 by 11,000 (number of premature deaths), would result in an upward bo und of total benefits of the rule due to premature deaths of $2.75 billion. **Section 5.4.5.2, Page 5 -**  **50, Table 5**
**- 12:**  Willingness to pay (WTP) is problematic because there are an infinite number of areas individuals could be asked to place a value on, yet individuals have a finite budget; thus, it seems likely that WTP would likely overstate what an individual would actually be willing and able to pay. Therefore, WTP should be constrained to not exceed a typical individual's budget. **Section 5.6, Page 5 -** **88, middle paragraph**  : “The fourth value is the 95 th percentile of the SCC from all three models at a 3% discount rate. It is included to represent higher

-than

- expected impacts from temperature change further out in the tails of the SCC distribution.” Why not include a fifth value at the 5 th percentile in order to represent lower

-than

- expected impacts from temperature change? **Section 5.8, Page 5 -** **99, first paragraph: We estimate that by 2016 the rule will have reduced the number of PM2.5** 
**- related premature death**  **s by between 4,300 and 11,000...”** It would be useful for EPA to provide an estimate of the average amount of time these 4,300 to 11,000 individuals would live beyond what would otherwise be a premature death without implementation of the rule. **Section 6.1, Page 6**  **- 1:**  “From an economic perspective, labor is an input into producing goods and services. If regulation requires that more labor be used to produce a given amount of output, the additional labor is reflected by an increase in the cost of production.” It should be noted that the decrease in labor productivity would cause the short

- run aggregate supply curve to shift to the left, with the result being that businesses produce less (i.e., lower GDP). **Section 6.1, Page 6 -**  **2:** “With significant numbers of wo rkers unemployed, the opportunity costs associated with displacing jobs in other sectors are likely to be much smaller.” It seems that even at unemployment levels of 9 percent, 91 percent of the labor force is still working and thus the opportunity costs a ssociated with displacing jobs in other sectors is not likely to be much smaller. **Section 6.3, Page 6 -**  **7, first paragraph** : “When a regulation is promulgated, the first response of industry is to order pollution control equipment and services in order to com ply with the regulation when it becomes effective.” It should be noted that an alternative first response is for individual plants to shut down in order to avoid the higher costs associated with the pollution control equipment and services.

## Summary of Interagency Working Comments on Draft Language under

EO s 12866 and 13563 Interagency Review. Subject to Further Policy Review.

Page 34 of 38 **Section 6.3, Pa ge 6**  **- 7, first paragraph: “Revenue and employment in the environmental technology**  **industry...”** A clear definition of what industries (e.g., NAICS codes) are included in the environmental technology industry is needed. **Section 6.2.1, Page 6 -**  **6, Table 6**
**- 2:**  Since the overall results of the Morgenstern et al. study are statistically insignificant, it seems more practical to not provide corresponding job estimates, but to simply indicate the overall employment impacts were found to be statistically insignificant. A dditionally, a summary of other studies that have estimated the effects of regulation on the economy would be useful. **Section 8.1, Page 2, Table 8**
**- 1**  : It may be more clear to the reader to change “+B” to “+NB,” (Net Benefits) because the reader has to searc h through the various footnotes in order to find that “B is the sum of all unquantified benefits and disbenefits.”

## Summary of Interagency Working Comments on Draft Language under

EO s 12866 and 13563 Interagency Review. Subject to Further Policy Review.

Page 35 of 38 SBA Comments : Thank you again for the opportunity to comment on EGU MACT draft final rule. T he Office of Advocacy submitted comm ents on this proposed rule (see http://www.sba.gov/advocacy/816/19191 ). Unfortunately, Advocacy staff believes that EPA has not responded to the many criticisms in our letter nor changed the rule suffici ently to reduce the anticipated significant economic impacts on a substantial number of small entities. Our comments are nonetheless not limited to concerns expressed in our letter. We may also provide additional comments as time allows. As a general theme, however, Advocacy staff notes that EPA has significant discretion in the implementation of the Clean Air Act section 112 as it relates to electric utilities, and that EPA’s approach to this rulemaking defies the Administration’s Regulatory Principle s, as laid out in EOs 12866 and 13562. EO 12866 is very specific about the policy criterion that should be applied when an agency has discretion: “In deciding whether and how to regulate, agencies should assess all costs and benefits of available regulat ory alternatives, including the alternative of not regulating. . . . [I]n choosing among alternative regulatory approaches, agencies should select those approaches that maximize net benefits (including potential economic, environmental, public health and s afety, and other advantages; distributive impacts; and equity), unless a statute requires another regulatory approach.” (Executive Order 12866, Section 1(a).) The Executive Order further requires: “Each agency shall tailor its regulations to impose the least burden on society, including individuals, businesses of differing sizes, and other entities (including small communities and governmental entities), consistent with obtaining the regulatory objectives, taking into account, among other things, and to the extent practicable, the costs of cumulative regulations.” (Section 1(b)(11).) Nonetheless, EPA declines to consider fully regulatory alternatives. The proposed rule was marked by repeated dismissals of legitimate uses of its discretion without develo ping the alternatives sufficiently for the public to comment. In the final rule, EPA disposes of many of these same issues, raised by commenters, without discussing whether the various policy options could maximize net benefits. It is noteworthy that E PA generally does not assert that statute precludes adopting alternate interpretations of the CAA or considering additional factors in its policy decisions, as recommended by commentors. For example, in the discussion of subcategorization, EPA starts the discussion by asserting an obligation (. . . “any basis for subcategorization (i.e., class, type, or size) must be related to an effect on HAP emissions that is due to the difference in class, type or size.”), but it cites support for its position in court cases that emphasize EPA’s discretion to subcategorize. (“The EPA believes it is not reasonable to exercise our discretion without such a difference . . . ” [emphasis added].) Further, EPA emphasizes its discretion to refuse to subcategorize. Similarly, with area sources, EPA “exercised the discretion afforded the Agency under the statute and declined to set separate standards for area source EGUs,” but EPA did not consider net benefits in its decision. (EPA also did not consider public health, distribu tive impacts, or equity.) Overall, EPA continues to assert that the CAA section 112 does not require it to consider costs. Perhaps not, but the Executive Order does.

## Summary of Interagency Working Comments on Draft Language under

EO s 12866 and 13563 Interagency Review. Subject to Further Policy Review.

Page 36 of 38 **Economic Analysis in general:** When EPA cites an annualized compliance cost, what is the discount rate and what is the time frame? RIA Table 3

- 5 is particularly confusing on that point. We continue to be concerned that the primary driver of benefits of the NESHAP is not a HAP at all and that the monetized benefits of the NESHAP portion of this rule are small compared to the costs of controlling for the target HAP. A tailored approach would require EPA to address Hg for Hg sake, and not apply a MACT calculation to PM. We also note co ntinued criticisms of EPA’s PM benefits calculations. How/where does EPA respond to public comments challenging its compliance cost estimates?
**RFA:** It is unclear whether EPA intends its response to Advocacy’s comments to be self

- contained the FRFA (Chapt er 7 of the RIA) or whether EPA is responding to the various points in the preamble of the rule as appropriate. Nonetheless, Advocacy staff is concerned that EPA has not responded to a number of important points. For example, Advocacy states that EPA did not meet the requirements of the RFA. EPA, in response, enumerates actions it did take, but does not respond to Advocacy’s discussion of things it did not do. Advocacy also identified areas of significant statutory discretion that EPA declined to consid er for their impacts on small entities. EPA does not respond to these comments in Chapter 7, and it is difficult to see whether EPA responded elsewhere. EPA has not responded to concerns raised by Advocacy and others that compliance will be significantly more costly for small entities, both because of competition for scarce compliance resources and the potential for penalties (or, in the extreme, shut

- down) if unable to complete compliance in 3 (or 4) years. I’d like to get more information on the reven ue impacts of the rule, particularly the impact on Co

- ops. How much of the increase in revenues is a result of higher electricity rates v. higher production? How did EPA model the different price setting mechanisms for the various ownership structures? EPA notes: “Results for small entities discussed here do not account for the reality that electricity markets are regulated in parts of the country. Entities operating in regulated or cost

- of

- service markets should be able to recover all of their costs of compliance through rate adjustments.” Is this an explanation that compliance costs can be covered or that higher revenue will be taken

- back by the rate setters?
**Area Sources** : As Advocacy stated in our comments and mentioned above, EPA has the discretio n to set GACT for area sources. This discretion is not bound by a consideration of other factors, such as those EPA cites in the preamble. EPA should therefore develop a GACT as a significant alternative and consider it for both its impact on small entit ies and marginal net benefits. In the FRFA, EPA states: “In fact, because of the significant number of well

- controlled EGUs of all sizes, we believe it would be difficult to make a distinction between MACT and GACT.” Advocacy staff believes that EPA should revisit its understanding of what “Generally Available” means and whether it in fact would require as stringent a series of technologies as would be mandated under MACT. We also note that GACT may include management practices as an alternative to control technologies. **Subcategorization:** EPA’s discussion of establishing a size subcategory is not convincing. First, EPA states that it performed an analysis based on 125 MW and that the smaller EGUs would have to meet a

## Summary of Interagency Working Comments on Draft Language under

EO s 12866 and 13563 Interagency Review. Subject to Further Policy Review.

Page 37 of 38 MACT floor more stringent than the standard for >8,300 Btu subcategory. This raises an interesting question as to (1) why 125 MW when the commenters requested 100 MW as the cut

- off, (2) why not subcategorize by size and coal type, and (3) how would all of the MACT floor standards be c hanged by making the subcategory? Second, EPA should have performed similar calculations for HCl and PM, because the best

- performing for each pollutant change. And third, the statement “Thus, units of all sizes are capable of achieving the proposed limits . . . .” is not supported by the evidence provided. APPA’s comments provide an alternate set of standards based on subcategories on size and coal type. EPA should respond directly to this proposal. Advocacy staff is also concerned that EPA’s criterion for subcategorization is not appropriate for the setting of new source standards. For existing sources, EPA relies on the prevalence of various types of EGUs in the top 12% to justify a single subcategory. However, when EPA sets new source standards, it looks only at the one top performance unit. The prevalence of other boiler types in the top 12% is irrelevant to whether all of those boiler types can meet a standards set on a single boiler type. Leaving aside whether a new source standard based on a si ngle example is an appropriate means of setting a regulatory standard, the effect of this approach is to limit future investment to the one specified suite of technologies under a specified set of circumstances. When combined with the pollutant

- by

- polluta nt approach, it is reasonable to question whether any one suite of technologies can accomplish all of the various standards. It is not surprising that the EGU GHG NSPS RIA states clearly that EPA does not anticipate any future investment in coal

-fired EGU s. EPA should dispose of its artificial test of subcategories, exercise the discretion granted by statute, and examine possible subcategories based on difference in boiler design and operation, rather than just the emissions profile of the top 12%. This would include, for example, a subcategory for CFB units. **Timing:** Advocacy staff is still very concerned about the ability of small entities to meet the compliance timeline. Although sensitive to the limits of EPA’s discretion, we are disturbed by EPA’s a ssurances that “most, if not all, units will be able to comply with the requirements of this rule within 3 years” and that all will be well “with proper planning.” Leavings aside the debate over reliability, EPA does not directly address the comments that challenge its optimism. For example, both the UARG and APPA are very specific in their concerns about the actual amount of time it takes to install the necessary emissions control equipment, and EPA does not appear to address their comments. If EPA’s op timism is misplaced, this will have devastating economic effects on individual entities and expose them to significant legal jeopardy. EPA should also directly address comments raising the possibility of a Presidential delay. Has EPA directly evaluated t he capacity to install the necessary pollution control equipment? The assertions that I can recall in my review appear based on past performance within the industry and evaluations of the time necessary to install equipment on a single unit in the absence of competition. Please correct me if I have missed a more detailed TSD.
**UPL:** Did EPA respond to EPRI’s comments on the UPL calculations (page 2

- 1
– 2

- 12)? See also UARG comments, attachment 3 (memo to UARG from Ralph Robertson).

## Summary of Interagency Working Comments on Draft Language under

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Page 38 of 38 **SO2 Emissions control t echnology:**  I’m a little unclear on DSI. There seems to be a lot of suspicion about it. Commenters seem to be concerned that it is not nearly as successful as EPA has projected, and that there may be a need to install wet FGD, at greater time and expense. What is the effect of the CSPR rule on installation of DSI and/or wet FGD? If DSI isn’t as prevalent, the operating costs rise significantly due to increased demand, or suppliers decline to assure performance, what would be the cost and timing effects o f greater reliance on wet FGD?