Summary of Interagency Working Comments on Draf t Language under EO 12866 Interagency Review. Subject to Further Policy Review.

Page 1 of 41 This summary of interagency comments contains comments on the EGU MACT Preamble, RIA, the October 2002 EPA Study, and the TSD titled “ RESOURCE ADEQUACY AND RELIABILITY IN THE IPM PROJECTIONS FOR THE TOXICS RULE .” Comments on Chapter 9 of the RIA are forthc oming. These comments are subject to further policy review. **Ap plicability**  The preamble indicate s that only coal

-fired and oil

-fired EGUs are covered under the EGU MACT. Is this correct, or are other fuels (e.g., biofuels, etc.) and co

- firing also covered by these standards ? If other fuels are not covered by these standards , how will EPA hand le units firing multiple fuels? Could fuel mix be a control strategy for meeting the emissions standards to be developed under this rule? 

### Response: EPA has addressed this issue through its proposed definition of “fossil fuel

- fired” where a defined amount of coal or oil must be fired in order for a unit to be considered “fossil fuel

- fired and, thus, subject to the rule. **Compliance Timeframe and Reliability** Attention needs to be given to the required industrial capacity and the time needed for electric generating units (EGU’s) to comply with the full spectrum of proposed and pending EPA regulations. Issues associated with the short time frame allowed by law for compli ance with this rule will be compounded by the need for the electric power sector to install environmental compliance equipment to meet other pending regulations during the same time period. Factors that need to be addressed are the supply chain and work force issues associated w ith future retrofits of EGUs. A comprehensive assessment of all regulations (for all media air, water, and solids

– including greenhouse gas regulations) requiring installation of new equipment or modification of existing equipment at EGU’s needs to be conducted to determine if there is sufficient time to allow utility companies to secure equipment (often from foreign suppliers), in a cost effective manner (supply/demand pricing for the equipment) while also having sufficient skille d labor available to install it. For example, welders and other trades are in short supply in some regions. The impact of the statutory requirement to comply with the Toxics Rule within 3 to 4 years on the reliability of the electric grid also needs to be determined. Assumptions about when retrofits could be completed may impact the availability of power plants and reserve margins due to the maintenance outages, potential for permit violations, and delays caused by labor shortages or delayed delivery of e quipment. **Therefore, it could be useful for EPA to**  **describe its options for addressing the operation of non -**  **compliant plants at the end of the compliance period. For example, if NERC issues an advisory**  **that taking the plant offline could create a justifi**  **ed reliability concern, what options would EPA**  **have for implementing the policy at that point?**  

### Response: With regards to further analysis of issues related to industrial capacity and the time needed for EGUs to comply, while we believe that our analysis does show that based on historical installations, the variety of options for compliance and large reserve margins that there are enough resources and time. However we are happy to continue to work with you onSummary of Interagency Working Comments on Draf t Language under EO 12866 Interagency Review. Subject to Further Policy Review.

Page 2 of 41 

### these issues between the proposal and final to further investigate these issues. With regard to describing options for addressing the operation of non

- compliant plants, i f we properly understand your question, the answer in short is that EPA’s options depend upon the specific circumstances. There ar e many different kinds, and degrees of significance, of reliability issues. The more significant reliability issues in each system are well known by both the generation sources and system operators and are specifically addressed in system operating plans. With the three years (or four years for installation of controls at the discretion of the permitting authority) that power plants have to determine and install their selected method of compliance with the Utility MACT, it is our expectation that most, if not all, of the reliability issues that are related to whether a specific unit will comply through unit retirement will be identified and addressed by the system operator and the source prior to the compliance deadline
. We recognize that it is possible t hat a reliability issue may arise close to the MACT compliance deadline
. Again, our expectation is that normal prudent system planning activities will both identify these issues as well as a solution in time to allow for any necessary unit retirement with out unacceptable impacts on reliability. Where an operator continues to operate a unit after the MACT deadline without meeting the requirements of the Rule, it is subject to enforcement action. If NERC issues an advisory that taking the plant offline cou ld create a justified reliability concern, EPA would work with NERC (and any other pertinent regulatory bodies) and together look to the statutory criteria set out in the Clean Air Act and other applicable statutes and implementing regulations and evaluate all relevant factors including any whether the unit is required for reliability and the steps taken by the owner/operator of the unit to come into compliance. EPA cites assurances that the industry can fully install all necessary equipment within three y ears, and separately states that outages usually occur during off

- peak seasons when reserves are higher. However, the two statements don’t necessarily relate to each other. If over 88% of the productive generating capacity must be upgraded within three y ears, will EGUs have the luxury of waiting until off

- peaks seasons to perform the upgrade? Constraints in the production of emissions control equipment may require year

- round upgrades and may even encourage incentives to schedule upgrades during peak peri ods to maintain a constant workflow. 

### Response: Historically companies have scheduled outages for control installations during off

-peak seasons. We have done analysis showing that there is enough capacity to allow this to happen if all of the installatio ns occur within a one year period. Because some of these installations may in fact beSummary of Interagency Working Comments on Draf t Language under EO 12866 Interagency Review. Subject to Further Policy Review.

Page 3 of 41 

### completed early (because for certain options lead times are shorter and based on the CAIR experience we believe that many companies have already begun planning) and ther e is flexibility with the permitting extension for some of these installations to occur in the fourth year, we believe it is reasonable to assume that companies will continue to conform to their historical practice of installing controls during off peak pe riods.

o EPA states: “Reliability concerns cause by local transmission constraints can be addressed through a range of solutions including the development of new generation and/or demand side resources, and/or enhancements to the transmission system.” **Has EPA**  **developed cost estimates with these local constraints in mind? To what extent do the reserve**  **margins cited else where account for local variability**  **?** 

### Response: As explained in the preamble, given the relatively small number of retirements that EPA pro jects, we believe that there are likely to only be a small number of areas where this is an issue.

o Current “large” reserve margins may be a function of the economic downturn. **If the economy** 

**picks up in 2012, what are the projections for the reserve margi n? Is there**  **any sensitivity** 

**analy sis of the reserve margins? How are the projected reserve**  **margins adjusted to reflect other concurrent regulatory programs that may** 

**lead to retirement or time off** **- line to comply, e.g., 316(b) and GHG NSPS?**  

### Response: The projections for the reserve margin incorporate EIA projections for electric demand growth that account for economic growth. Although neither of the other two regulations have been proposed, the timeframe for installing controls is likely to be after 2015
. Along with the statement made atop page 464 that EPA will coordinate with DOE and FERC, **the preamble for the rule can include more discussion of ho w e**  **lectric reliability w**  **ould be considered during implementation of the regulation.**  For instance, EPA can acknowledge that as multiple facilities make major modifications to meet new regulatory requirements, extensive and ongoing regional coordination between the industry, electric reliability organizations, and EPA will be required to ensure adequate generat ion is available to meet load

. Adequate safeguards must be in place throughout the policy implementation to achieve both the intended environmental protection and to maintain electric reliability. 

### Response: New language has been added. **Permitting A utho**  **rities’ Discretion to Grant One**

**- Year Extension**  **-** Under Section 112, existing sources may be granted up to 3 years to comply with the final rule. A permitting authority has the discretion to grant a 1

- year extension, on a case

- by

- case basis, if such additio nal time is necessary for installation of controls. There could be situations in which a source operating a coal

-fired facility subject to this MACT rule may find it expedient to replace the coal

-fired unit with gas

-fired simple cycle or combined cycle tur bine facility. Any suchSummary of Interagency Working Comments on Draf t Language under EO 12866 Interagency Review. Subject to Further Policy Review.

Page 4 of 41 replacement could be driven by factors such as proximity to supply of natural gas, the large costs associated with the operation of an older coal

- fired facility, and other factors unique to that facility. For such a facility, replac ement of the coal

- fi red unit with a gas turbine may not only be cost effective, but also beneficial to the environment in terms of lower emissions of HAPs. However, the construction of any such replacement facility may take longer than three years af ter th e effective date of this MACT. **Ac cordingly**  **, w e recommend that EPA**  **recognize in the preamble or else** **where in the rulemaking record that the one**

**- year extension for**  **installation of controls should be made available to sourc es that have decided to replace** 


### Response: EPA is still evaluating this issue. **Delay s Due to NSR Permitting** 

- The pollution control equipment constructed to comply with the proposed MACT rule has the potential to trigger NSR permitting, posing further challenges to industry’s ability to me et the 3 year compliance schedule. Accordingly, the rule should recognize that the time required to obtain any such NSR permit should be one factor that permitting authorities take into account in granting the 1

- year extension to demonstrate comp liance with the MACT standards. 

### Response: EPA believes that inherent in the installation of controls is compliance with applicable permitting requirements prior to installation of such controls; therefore, permitting iss ues that delay installation of controls could be considered by a state in evaluating whether to provide an extension of time to comply with the final rule. Sources should, however, quickly evaluate to potential need for a permit to avoid if possible any d elays in obtaining the permits necessary to install controls to comply with the standards. **Time to Install Controls** I n the preamble on page 467, EPA states: “Although EPA assessed the ability to install the controls in 3 years (and determined that the co ntrols could be installed in that time

-frame), this would require the control technology industry to ramp up quickly”. (emphasis added) The attached report entitled Issues Associated with the Acceleration of Tennessee Valley Authority’

s Clean Air Program, prepared by a TVA expert in conjunction with the nuisance lawsuit ( North Carolina v. TVA ), sheds light on scheduling issues relating to the construction of FGDs and SCRs. The report states in pertinent part: A typical FGD project installation duration fr om conceptual design to commercial operation averages 5 years. A typical SCR project installation duration from conceptual design to commercial operation averages 3 to 4 years depending on the size of the unit and complexity with the retrofit installation. There are also schedule implications of the SNCR and SO3 mitigation projects that must be worked in conjunction with the new installation of FGDs and SCRs. TVA is confident in our projections for the time needed to complete FGD and SCR projects, which are based on TVA’ s actual experience to install FGDs and SCRs on several units, input from Advatech (TVA’ s FGD partner), benchmarking with other utilities and an extensive program review on cost and schedule conducted by Bechtel Power Corporation. (Executive Summary, p. 5)Summary of Interagency Working Comments on Draf t Language under EO 12866 Interagency Review. Subject to Further Policy Review.

Page 5 of 41 The above expert report was prepared in February 2007, a period when CAIR was being implemented. The report explains that the scheduling pressures placed on utilities by CAIR stretched the market capacity for many critical resources. The rigorous schedules of the proposed EGU MACT Rule and that of proposed Transport Rule would further stretch the market capacity for these resources to an unsustainable level. The schedules assumed by the EGU MACT Rule for construction of SCRs and FGDs are i n fact impractical and unachievable. As an example, TVA completed the installation of the FGD on Paradise Fossil Plant Unit 3 in approximately 5 years, considering the time from conceptual design to commercial operations. The actual project schedule for th e Paradise FGD is shown as Figure 3 in the attached expert report. Even this schedule may not be achievable at some sites due to space and other site specific constraints. For plants requiring installation of both FGD and SCR, physical site constraints com monly result in sequencing the installations and lengthening schedules approximately 2 years. Since the Paradise FGD was completed and TVA’s expert report finalized, the pollution control project exclusion in EPA’s NSR regulations was vacated by the United States Court of Appeals for the D.C. Circuit in New York v. EPA , 413 F.3d 3 (D.C. Cir. 2005). This vacatur adds additional pre
- construction air permitting requirements for those air pollution control projects that may result in significant emission increases of regulated pollutants. TVA estimates that it would take 9 to 12 months (and possibly longer) to develop a permit applicat ion and obtain a permit for an air pollution control project that has the potential for significant emission increases. The permitting process would add several months to the overall project schedule. Further, permitting and construction of scrubber by

- p roduct disposal areas is required for most FGD projects, and for virtually all where the FGD is the first FGD for a particular facility. Typically this work can be completed concurrently with the normal 5 year period for FGD design and construction. If EPA determines, as identified as an option in EPA’s proposed Coal Combustion Residuals Rule, that scrubber by

- product must be disposed of as hazardous waste in landfills permitted under subtitle C requirements, more time will be required. Subtitle C landfills have often required 6 to 8 years for permitting and construction. Moreover, schedules must also be adjust ed to accommodate the permitting process for any modifications to the facility’s NPDES permit for the wastewater discharge from the scrubber. Also, as a federal agency, TVA must comply with the environmental review requirements under the National Environme ntal Policy Act, Endangered Species Act, National Historic Preservation Act and other environmental statutes prior to undertaking these projects, often resulting in additional time necessary to complete the projects. The controls and new capacity require d nationwide to comply with the proposed EGU MACT Rule will require a significant increase in skilled labor, manufacturing, and material resources for the construction of pollution control equipment and will cost billions of dollars. W e anticipate scheduli ng impacts and cost increases due to resource constraints. Unit outages for controls installations must be staggered and avoid peak demand seasons to ensure reliability. W ith the final EGU MACT Rule expected in late 2011, the earliest that construction of the required FGDs, SCRs, and new gas fired units could be achieved is late 2016. The resource and schedule constraints described above, including permitting and environmental review, may result in even later completion dates for many pollution control proj ects. If the rule becomes final in November 2011, the final compliance date would be in 2015. W e believe this compliance date is not achievable even with the CAA provision which allows permitting authorities the discretion to grant extensions to the compli ance time

- line of up to 1 year for installation of controls.Summary of Interagency Working Comments on Draf t Language under EO 12866 Interagency Review. Subject to Further Policy Review.

Page 6 of 41 

### Response: EPA’s analysis suggests that most of the controls to be installed will be, dry scrubbers, sorbent injection, activated carbon injection, baghouses and particulate device upgrades. Th ese typically take less time to install than the SCRs and wet FGDs cited in the report. **Ar ea Sources**  The SBAR SERs recommended that EPA consider a GACT alternative, but this has not been addressed. Althoughwe do not know that a GACT would benefit small entities, it is a legitimate significant regulatory alternative that should be considered for its impact on small entities. This is particularly true given EPA’s assertion that there are relatively few sources that would qualify as area sources. Werecom mend that EPA do the following:

 Specify regulatory details of a GACT alternative for area sources.

 Identify natural and synthetic area sources that could be subject to a GACT alternative.

 Compare the costs and benefits of imposing a MACT on these sources instead of a GACT. 

### Response: In the preamble, we note that the Small Entity Representatives (SERs) serving on the Small Business Advocacy Review Panel (SBAR) established under the Small Business Regulatory Enforcement Fairness Act (SBREFA) suggested that EPA consider developing an area

- source (i.e., those EGUs emitting less than 10 tpy of any one HAP or less than 25 tpy of any combination of HAP) vs. major

- source (i.e., those EGUs emitting 10 tpy or more of any one HAP or 25 tpy of more of any combination of HAP) distinction for this source category. The proposed r ule treats all EGUs the same. In section 112(a)(8), Congress defined an EGU as “... any fossil fuel fired combustion unit...” (Emphasis added)
. A reasonable interpretation of this definition i s that Congress intended the Agency to regulate EGUs together in the same manner, if we determined that regulation under CAA section 112 was appropriate and necessary
. In this case, we are proposing to set MACT standards for all EGUs. In any event, not hing in the CAA requires that we issue GACT standards for area sources. Indeed, here, the data show that similar HAP emissions and control technologies are found on all sources greater than 25 MWe. In fact, because of the significant number of well

- contr olled EGUs of all sizes, we believe it would be difficult to make a distinction between MACT and GACT. Moreover, EPA believes the standards for area sources should reflect MACT, rather than GACT, because there is noSummary of Interagency Working Comments on Draf t Language under EO 12866 Interagency Review. Subject to Further Policy Review.

Page 7 of 41 

### essential difference between area sourc e and major source EGUs with respect to emissions of HAP
. There are EGUs that are physically quite large that are area sources, and EGUs that are small that are major sources. Both large and small EGUs are represented in the MACT floor pools for acid gas , Hg, and non

- Hg metal HAP. Given that EPA is developing major and area source standards at the same time in this rulemaking, a common control strategy consequently appears warranted for these emissions
. Accordingly, we believe it is appropriate to set M ACT standards for both major and area source EGUs
. EPA is soliciting comment on its proposed approach. Further, the sources preliminarily identified as being natural and synthetic area sources are both large and small EGUs owned by both “large” and “smal l” entities. Commenter has not indicated how EPA could make a meaningful distinction between large EGUs (e.g., 500+ MWe) that are owned in small proportion (e.g., 1.5%) by a number of small entities along with entities that are not “small” vs. single EGUs , regardless of unit size, that are owned entirely by small entities. **HBEL** EPA’s authority to establish health

- based emission limits under Section 112(d)(4) is discretionary. It would be appropriate for EPA to use this discretion to establish a health

- based emission limit for HCl and other acid gases. The compliance cost savings from establishing such a health

- ba sed standard would be substantial. **In fact, we suggest estimate the costs and environmental effects of a health** 

**- based emission limit compared to the conventional**  **MA CT standard that it has proposed.**  The current economic climate dictates a balancing of econ omic and environmental interests. EPA presents a number of reasons it does not develop a regulatory alternative under 112(d)(4), including the presence of cumulative emissions from entities not regulated by this rule and the substantial co

- benefits.

o EPA cites to the significant co

- benefits as a basis for declining to use the Administrator’s discretion. If the Administrator has the discretion to consider factors other than the level of HAP emissions from the regulated industry, then EPA should be complyin g w ith EO 12866, EO 13563, and the RFA and considering costs and benefits of this regulatory alternative.

o EPA asserts very firmly that it does not have the discretion to decline to regulate, even when allowed to consider cost, where there are lower cost a lternatives affecting different sectors of the economy. However, here, emissions from other sources not regulated by this rulemaking are presented as crucial to the Admin i strator’s ability to exercise this discretion. This appears to be a statement that (d)(4) can only be usedSummary of Interagency Working Comments on Draf t Language under EO 12866 Interagency Review. Subject to Further Policy Review.

Page 8 of 41 when every sector of the economy can meet a health based standard. Since (d)(4) is not supposed to be NAAQS for HAPs, there must be a way of regulated only one set of facilities at a time.

o If proximity to other HAP sources is the basis for refusing to set health

- based standards, then EPA should be open to an optional standard at the facility boundaries. Some EGUs won’t be able to use the standard because of their neighbors, but others may be able to.

o It is unfortunate that EPA de cided early on that it would not exercise (d)(4) discretion because of the massive co

- benefits, particularly since it gave EPA a reason to not seek the information it now states it would need. As the preamble confirms (p. 438), EPA has already created re gulatory precedence for addressing HCl as a threshold pollutant in developing the Pulp and Paper NESHAP (1998) and the Lime Manufacturing NESHAP (2002). In those earlier instances, EPA exercised its discretion to exempt HCl from the MACT requirement altog ether. Here, EPA should use its discretion to set an emission standard based on the health threshold in view of EGUs being the largest anthropogenic emitters of HCl in the United States. Such regulation based on health thresholds would be far more preferable to the proposed approach of setting MACT standards for acid gases regardless of the incremental health benefits. Likewise, while accrual of collateral benefits from the control of criteria pollutants is noteworthy, other provisions of the CAA, such a s Sections 108 to 110 addressing the establishment and achievement of National Ambient Air Quality Standards, are the proper vehicles for mitigating the impacts of e mission of criteria pollutants. 

### Response: We address in the preamble the factual, legal , and policy

- related issues associated with the establishment of health based emission standards for the acid gas HAP (HCl, HF, HCN, and SeO 2 

### ). **Re gulatory** 

**Flexibility**

**Compliance** EPA does not appear to have considered regulatory flexibilities for small enti ties, as required by the Regulatory Flexibility Act and the President’s Memorandum of January 18, 2011 (“. . . I hereby direct executive departments and agencies and request independent agencies, when initiating rulemaking that will have a significant eco nomic impact on a substantial number of small entities, to give serious consideration to whether and how it is appropriate, consistent with law and regulatory objectives, to reduce regulatory burdens on small businesses, th rough increased flexibility.”) E ven in those circumstances where statutory authority or practical requirements make flexibilities difficult, EPA should directly address them. In particular, EPA has not consider different compliance standards, different reporting recordkeeping requiremen ts, compliance date extensions for small entities (except through the case

- by

- case discretionary review available to all), or exemptions for small entities. Wesuggest that EPA address this by considering alternatives.Summary of Interagency Working Comments on Draf t Language under EO 12866 Interagency Review. Subject to Further Policy Review.

Page 9 of 41 It appears that EPA has rejected si gnificant regulatory alternatives identified by the SBAR panel SERs and Advocacy without reference to the benefits such alternatives may have for small entities and without explaining how the alternatives would fail to accomplish the “stated objectives” of the CAA. 

### Response: EPA has considered alternatives “consistent with law and regulatory objectives,” and is proposing several of them that we believe are within our statutory authority and consistent with our regulatory objectives. Some of the alternat ives that are being, or have been, considered include: a. Statutorily mandated “floor” alternative for each HAP or HAP group and subcategory

-- proposing and taking comment. b. Beyond

- the

- floor alternative for mercury emissions from lignite

- fired units

-- proposing and taking comment. c. Consideration of beyond

- the

- floor for the remaining HAP or HAP groups and subcategories

-- considered and not proposing, but taking comment. d. Use of HBEL's

-- considered and not proposing, but taking comment. e. Dis tinction between area and major sources

-- considered and not proposing, but taking comment. f. Additional subcategories

-- considered and not proposing, but taking comment. g. Emissions averaging within affected facilities

-- considered and proposing. h. Reduced emissions testing for “low emitting EGUs ” (LEEs)

– considered and proposing. As noted by the commenter, we are not considering any compliance date extensions beyond those being considered for all sources. Section 112(i)(3) sets clear limits o n the compliance time frames and EPA cannot deviate from those time frames for any subcategories or regulated entities. Absent legal basis for the regulatory alternatives, there is little merit in assessing benefit. Unfortunately, where EPA does discuss regulatory alternatives, it does not provide sufficient information for a regulated entity to evaluate the alternative, either for costs or fidelity to the statute, making public comment on the flexibilities and the IRFA extremely difficult. 

### Response: We are not sure to what alternatives the comment refers. The description of “any significant alternatives” is missing from the IRFA in Chapter 10 of the RIA. The block quote of chapter 9 of the panel report does not fulfill this obligation. The panel rep ort describes mostly factors for EPA to consider in its rulemaking, not “any significantSummary of Interagency Working Comments on Draf t Language under EO 12866 Interagency Review. Subject to Further Policy Review.

Page 10 of 41 alternatives to the proposed rule which accomplish the stated objectives of applicable statutes and which minimize any significant economy impact of the proposed rule on small entities.” The description of alternatives in the UMRA section also does not fulfill this IRFA requirement because describes the regulatory alternative selected, with some of the presented options, but not a reasonable range of regulatory altern atives not proposed

. 

### Response: See general answer above, no addition planned
. EPA must provide the IRFA or a summary of the IRFA in the preamble (see 5 USC 603(a)). 

### Response: See general answer above, no addition planned
. Footnote 5 in the IRFA (“Res ults 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.”) should be discussed in more detail. Not all costs can be recovered and not all processes are timely or complete. 

### Response: See general answer above, no addition planned
. **Subcategorizatio n**  EPA’s consideration of alternative sub categorization is lacking. EPA does not present data to support its contentions that no other subcategorization scheme can be supported. In particular, the argument that all various technologies appear in the top 12% is not itself an argument against sub categorization, but rather an argument that subcategorization might generate small emissions control difference between technologies. However, EPA does not present data or alternative emissions standards to support that contention, so EPA’s dismissal of regulatory options is premature. This is particularly pointed in this case, since EPA’s request for comment demands of the public a scope and degree of information EPA itself doesn’t present in support of its own decision. 

### Response: EPA may not subcatego rize strictly on the basis of the use of different control technologies. Therefore, commenter’s suggestion to that extent is unmerited. The fact that all of the various control technologies appear in the top 12% is, in fact, an indication that there are no emissions differences and, thus, no basis for seeking a subcategorization scenario that would be based on control technologies. See preamble section V.A. Where the data indicated such differences (e.g., for mercury and boilers designed to burn lignite coals), EPA developed a subcategory for proposal and comment. All of the 2010 ICR data are currently available to the public and EPA’s analysis spreadsheets will be available at proposal for use by the public. EPA does in fact provide the level of det ail we request from commenters for the subcategories for which we establishedSummary of Interagency Working Comments on Draf t Language under EO 12866 Interagency Review. Subject to Further Policy Review.

Page 11 of 41 

### standards. EPA could not reasonably evaluate all of the potential different subcategory options and, because we believe the data do not support additional subcategories, we dete rmined not to evaluate in detail other subcategories. However, if a commenter has a specific subcategory they would like considered, the data are available for the commenter to evaluate the subcategory and provide the information we request in the propose d rule. We are not requiring commenters to evaluate all of the potential subcategories in detail before they comment. EPA has proposed to subcategorize coal

-fired EGUs into two categories based on the calorific value, using 8300 BTU/lb as the demarcating point. The MACT standard is 1 lb/TBTU for existing coal

-fired boilers designed for coal ≥ 8300 BTU/lb, and 2 lb/TBU for existing coal

-fired boilers designed to burn coal ≤ 8300 BTU/lb. There is a wide range (a 2:1 ratio) between the standards for Hg in th ese two subcategories, based merely on a rough categorization relying on calorific value. One commenter believes it would be more appropriate to subcategorize EGUs based on the type of coal being fired. Further, the categorization should be based on the co al fi red historically instead of the coal designed to be fired. **Can EPA propose or solicit**  **comment on this subcategorization approach?** 

### Response: It is the Agency’s policy that the rank of the coal being used (or other material input) not be the basis fo r subcategorization. This is consistent with the approach taken in the Portland Cement NESHAP where a separate subcategory was not developed for separate feedstocks. Consideration has also been given to comments received during and subsequent to the CAMR rulemaking that the use of coal rank alone as a basis for subcategorization is illegal. In addition, the data are not showing a difference in emissions among the various coal ranks except for Hg emissions from the subcategory at issue, thus we do not thi nk additional subcategorization based on coal rank would be consistent with the statute. EPA has selected the ASTM designation of lignite vs. subbituminous coal (i.e., the less than or greater than 8,300 Btu/lb designation) as the basis for subcategorizat ion because units that are designed to burn the lower Btu coal are larger and thus of a different type. EPA is taking comment on this approach. EPA has reassessed its analysis of the lignite data and has made the appropriate changes in the preamble. **MA C**  **T Standards**
**– Existing Units**  EPA’s discussion of setting the MACT floor is ambiguous as to how it treated the ICR data to ensure that the top 12% represented the top 12% of all EGUs in the subcategory rather than only the 12% of those that provided data in response to the 2010 ICR. This issue was addressed in the SBAR panel report, and EPA’s response should be clearer to avoid controversy.Summary of Interagency Working Comments on Draf t Language under EO 12866 Interagency Review. Subject to Further Policy Review.

Page 12 of 41 

### Response: EPA does not believe that there is any ambiguity in its selection of the top performing units. The sel ection was fully explained in the Supporting Statement to the ICR and reiterated in the preamble. Further information on the use of the 2010 ICR data is provided in the MACT Floor TSD. In previous MACT rules, there has been concern from industry that the data sample did not provide an accurate analysis of the ‘12% floor ’. Essentially, the claim was that the 12% was cherry

- picked from the “best of the best” and not actual technologies in use at a given location. How was the data collected for this rule, a nd can the analytical approach taken here be subject to similar cr iticism? Did desired outcomes (i.e. co

- benefits) impact the MACT floor that has been established? 

### Response: As noted in the previous response, EPA believes that it has fully and adequatel y described how it selected the units for testing for the 2010 ICR. It did, in fact, make an attempt to select the “best of the best” for three groups of HAP from coal

- fired EGUs

- acid gas HAP, non

- mercury metal HAP and non

dioxin/furan organic HAP

- so as to be able to use a number of units equal to 12% of the entire population in the MACT floor pool, rather than just use 12% of the data obtained. We in fact intend to propose standards based on data from sources representing 12% of the category for acid gas HAP and non

mercury metal HAP consistent with the statements in the ICR (we intend to propose work practice standards for organic HAP, including dioxin/furan). The control technologies in the MACT floor pool are technologies that are in use throughou t the industry. Co

- benefit impacts had no bearing in the selection of the units to be tested or in selection of the MACT floor pool of sources. Notwithstanding EPA’s adjustment for variability, the MACT floors still appear to be too stringent since they have been established on a pollutant

- by

- pollutant basis. The use of a pollutant

- by

- pollutant approach results in the creation of hypothetical standards that bear little resemblance to standards achieved in practice by existing facilities. 

### Response: EPA maintains that the pollutant

- by

-pollu tant approach is consistent with the CAA. We are currently defending the approach in the U.S. Court of Appeals for the D.C. Circuit. The proposed formula for calculation of 30 day averages sums the hourly emission rates for the 30 day period, and then di vides by the number of hours in the period. This equally weights each hour’s emission rate. Hours of low load operation and startup are at reduced levels of fuel burn and should not be weighted equally with full load operation. The appropriate 30 day avera ge calculation method should be the sum of the emissions for each hour of operation divided by the number of hours of operation

.Summary of Interagency Working Comments on Draf t Language under EO 12866 Interagency Review. Subject to Further Policy Review.

Page 13 of 41 

### Response: The ICR sought and obtained data over a 30 boiler operating day period (where a boiler operating day is any 24 hour period in which fuel is combusted) , in order to obtain variable emissions performance data across many periods of operation, including periods of changing loads. To the extent these periods occurred

– and they should have, if EGU operation and associated emissions performance is variable

– the emissions performance data were collected and included in developing the MACT floors. The proposed formula

- in which 30 boiler operating day average rates are calculated from daily rates based on mass emissions ra tes, flow rates, and heat input or electrical output from each hour that fuel is combusted

– represents exactly how the data were produced from representative sources over representative periods of operation. There is no need to revise this formula to com pute a 30 boiler operating day average. **Is it possible that EPA intended to propose a mercury**  **MA CT standard for ne** **w sources of 0.00001 lb/MWh rather than 0.00001/GWh**  ? Based on a quick analysis, this standard appears to be three orders of magnitude more s tringent than the standard for existing plants and would require greater than 99% total mercury removal at all new PC

- fired power plants. **This proposed standard is also below the detection limit of CEMS instrumentation** 
**– has EPA**  **considered this in requiri ng Hg CEMS?**  

### Response: There are four new source mercury MACT emissions limits; 0.00001 lb/GWh is the correct value for coal

- fired units designed for coal with heat contents equivalent with or greater than 8,300 Btu/lb and for IGCC units. The fact that t he proposed new

- source limit is three orders of magnitude more stringent than the limit for existing sources is a reflection of the data. The fact that the new

- source limit is significantly more stringent should be expected given the language of the statu te (i.e., “average of the top performing 12%” for existing sources vs. “emission limitation exhibited by the best performing similar source” for new sources) and the differential becomes larger the more data that are included in the existing source MACT fl oor pool. Further, based on the data received through the 2010 ICR, greater than 99% mercury removal is being achieved by many EGUs within (and outside) the MACT floor pool. Further, based on the data received through the 2010 ICR, greater than 99% mercu ry removal is being achieved by many EGUs within (and outside) the MACT floor pool. As explained in the preamble, the Agency applied a technique to adjust MACT floor levels

– when necessary

– to improve measurement accuracy near detection levels to a valu e consistent with accuracy values for other measurement techniques, so thatSummary of Interagency Working Comments on Draf t Language under EO 12866 Interagency Review. Subject to Further Policy Review.

Page 14 of 41 

### existing instrumentation can be used to demonstrate compliance with emissions limits. Should an owner or operator of an affected EGU believe that a mercury CEMS would be unable to detect emissions at or below the proposed standards, the proposal allows him the ability to choose another measurement technology, such as the sorbent trap monitoring system, that is able to detect emissions at or below the proposed standards. There app ears to be little justification for an averaging period of only 30 days for the mercury standard. The health effects for mercury are those resulting from bio

- accumulation occurring over a long period. Accordingly, **we suggest an annual averaging period for Hg seem to be**  **more appropriate**

. 

### Response: An averaging period of longer than 30 days for mercury emissions was considered but rejected. Although some may claim that health effects of mercury occur over a long period, devices that control mercury emissions are in continuous use during EGU operation. Without frequent checks of appropriate and continuous control device operation, such as the amount of activat ed carbon injection, EGU owners or operators could find themselves spending too much money for mercury emissions control, either through the use of too much sorbent or through neglect of performing routine maintenance or repair. Moreover, by lengthening t he period over which compliance is averaged, EGU owners or operators could increase their risk of non - compliance and the liability associated with that non

compliance. A problem of insufficient mercury control device operation found and corrected within 3 0 days poses less environmental impact and source cost than the same problem found and corrected over a 12

- month period. The decision to set beyond

- the

- floor mercury MACT standards for existing sources designed for coal < 8,300 Btu/lb (i.e., lignite

-fi red units) is based on limited data that includes only six lignite

fi red units (5 FBCs; 1 PC) and based on the assumption that ACI systems were not operated at their full capability

. **We suggest EPA provide more data is needed to support the rationale**  **for a beyond**  **- the**  **- floor standard and seek comment on this, along with a request for more**  **data.** 

### Response: EPA is providing more rationale and taking comment on this. However, through the 2010 ICR, EPA required EVERY EGU (including lignite EGUs) to provide all data, including that for mercury, obtained over the past 5 years. Thus, sources will likely have to test their units to provide additional data for the Agency to consider. **Floor Determination**
**– New** **Units**Summary of Interagency Working Comments on Draf t Language under EO 12866 Interagency Review. Subject to Further Policy Review.

Page 15 of 41 Section 112(d)(2) instructs the Administrator to take into consideration the cost of achieving emission reductions. However, EPA’s discussion in the preamble cites to and relies solely on (d)(3) to set a standard based on the sole best

- performing unit. EPA needs to demonstrate that it has considered th e cost of Hg

- emissions controls down to such an extreme level (given the high level of variability identified in the Existing Unit MACT Floor) and whether it is, in essence, mandating a particular emissions control technology and particular fuel source in order to meet this standard. 

### Response: The statute authorizes consideration of costs in the beyond

- the

- floor analysis under section 112(d)(2), which occurs after EPA has established the MACT floor consistent with section 112(d)(3). Wesuggest EPA consid er whether the subcategorizations for new u nits should be different than those for existing units if the performance standard is to be based on the single best performer in each subcategory. The argument that multiple different technologies appear in the top 12% doesn’t mean anything when only the top performer is relevant to the standard. 

### Response: EPA does not believe that more subcategories are either warranted or appropriate for new sources vs. existing. New sources are starting from scratch wherea s existing sources are tied to their current location, physical structure, etc. Therefore, new sources can be sited at a location most advantageous to their compliance with the standards, can construct a unit and controls that will most likely lead to the ir compliance with the standards, and can contract for the fuel that will most likely lead to their compliance with the standards. Emission limits for new units are so stringent we expect they will effectively stop new coal unit construction, an impact no t adequately addressed in the impact analysis

. **Can EPA include a**  **discussion of this outcome and its likelihood?** 

### Response: Based on the 2010 ICR data, the proposed new

- source limits for coal

- fired EGUs are currently being met by a number of existing uni ts for each of the HAP groups, thus we do not think the limits will stop the construction of new coal

- fired EGUs. The decision to set beyond

- the

- floor mercury MACT standards for new IGCC and lignite

- fired power plants is not supported by the data

– in par ticular, the MACT floor for new IGCC plants is more stringent than the Taylorville IGCC permit, which EPA references in the preamble. **Can EPA**  **explain why**

**the new IGCC and lignite -** **fired plants limits are so stringent?** 

### Response: The new source limit is to be set based on the “emission limitation exhibited by the best performing similar source”. We did not feel that the existing IGCC sources were representative of the performance of a new constructed IGCCSummary of Interagency Working Comments on Draf t Language under EO 12866 Interagency Review. Subject to Further Policy Review.

Page 16 of 41 

### facility. In general, new IGCC facilities are expec ted to have emissions that are as low as, or even lower, than newly constructed coal

- fired EGU facilities. We have reques ted comment on this approach. **Startup/Shutdo wn**  It is not clear that continuous emission monitoring (CEM) data for all the HAPs covered by this rulemaking were available for 12 percent of the best performing units. If CEMS data were not available for all HAPs for 12% of best performing units in setting particular standards for existing facilities, **we recommend that accommodation for the higher emissions during startups**  **and shutdo wns be built into those standards.**  Such accommodation would be necessary for standards based on intermittent data generated during normal operation of a facility. 

### Response: CEMS data for HAPs were not included in the floor analysis because no such data were provided by units in the MACT floor pool, despite requests for such data. EPA believes that the size of the MACT floor pool of sources along with the use of the 99% UPL and the 30

- day averaging period provid es the necessary “cushion” for periods of startup and shutdown; however, should commenters provide relevant data during the comment period, we will review it to determine its impact, if any, on the 30

- day averaging period. EPA has not addressed the full SBAR panel recommendation: “The panel members recommend that the Agency evaluate whether establishing work practice requirements during periods of startup and shutdown would be consistent with CAA section 112(h) . . . .” **Can EPA explain why** 

**this recommend ation has not been addressed?**  

### Response: Section 112(h) requires the Agency to find that “the application of measurement methodology to a particular class of sources is not practicable due to technological and economic limitations” before the Agency may e stablish a work practice standard in lieu of a MACT standard. EPA cannot satisfy that requirement for emissions during startup and shutdown, in part, because as the commenter notes CEM S can function during startup and shutdown periods
. Even though CEMS c an function during these periods, without use of default values, calculations can prove problematic in that denominators tend to approach zero, yielding infinite emissions. For the purposes of this rule, we propose use of a default diluent value of 10.0 p ercent O 2 

### or the corresponding fuel specific CO 2 

### concentration for calculating emissions in units of lb/ MMBtu or lb/TBtu during startup or shutdown periods. For calculating emissions in units of lb/ MWh or lb/GWh, we propose source owners use an electrical production rate of 5 percent of rated capacity during periods of startup orSummary of Interagency Working Comments on Draf t Language under EO 12866 Interagency Review. Subject to Further Policy Review.

Page 17 of 41 

### shutdown. We are request ing comment and suggestions for resolving this concern. [Page 322, Section IV.G, Last Paragraph]: It is indicated that CEMS data were used in establishi ng the emission limits, which apply to all unit operating modes, including startup and shutdown. **How much of such data reflect startup and shutdown of the tested units?**  It is we ll known that certain emissions will be higher during shutdown and startup pe riods. Since the future mix of power generators (including renewables) may make it necessary for the fossil units to cycle more frequently, some units may not be able to maintain the emission limits, even if averaged over a period of 30 days. 

### Response: Although EPA received CEM data from over 100 units, none of these units were among the top performing 12 percent and, thus, were not used in the data analysis. **Discounting factor in averaging** [Page 461] Please clarify how this 10% discount factor would apply. W ould this require the average emission rate measured to be 90% of the required emission rate? This provision does not seem to be necessary to ensure averaging is at least as stringent as the MACT floor. In fact, it seems to be an unnecessary pen alty on averaging, particularly when combined with the anti

- backsliding measure. W hat is the basis for this penalty? 

### Response: The use of the 10% discount factor has been removed from the draft preamble, so the comment is moot. We are requesting commen t on whether or not the use of a discount factor is appropriate, as well as the appropriate value of a discount factor.
**Al ternative Equivalent SO2 Limit to Control A** **cid Gases** EPA is proposing to set an alternative equivalent SO2 emission limit for coal

- fired EGUs with some form of FGD system because (1) the controls for SO2 are also effective controls for acid gases, and (2) most EGUs already have SO2 CEMS in place. EGUs without an FGD system installed would not be able to use this alternative emission limit. The preamble grafts the additional requirement that “EGUs must operate their FGD at all times to use the alternate SO2 emission limit.” (p. 388) **The basis for the latter requirement (to operate the FGD “at all times”) is not clear.**  It is conceivable that a source may not be able to operate the FGD at optimum levels, or at all, for short periods because of conditions beyond its control. However, the mere fact that the FGD was not operated for a short period should not be a basis to make the source ine ligible to use the alternate SO2 limit so long as the source demonstrates that this alternate SO2 limit is met. This is all the more true since demonstration of compliance with the SO2 alternate limit is on the basis of a monthly average. 

### Response: The b asis for establishing SO 2 

### as a surrogate for the acid gas HAP (e.g., HCl, HF) is the fact that FGD systems remove not only SO 2 

### but also the acid gas HAP. There is, however, no correlation between the sulfur content of a coal and theSummary of Interagency Working Comments on Draf t Language under EO 12866 Interagency Review. Subject to Further Policy Review.

Page 18 of 41 

### chlorine and fluorine content of coal. Therefore, in order for SO 2 

### to be “available” as a surrogate, some form of FGD control must be employed at all times. The CAA requires continuous compliance with standards and rules often have continuous parametric monitoring requirement s for pollution control equipment. We see no basis for a different approach in this case. **Controls for Hg and SO2 Standards** One reviewer agrees with EPA that the proposed DSI (direct sorbent injection) system is applicable, especially for plants with fe w years of remaining operation and plants with readily available facilities to handle ash storage leachate, but questions its application to the large number of facilities being considered by EPA. **We recommend that EPA investigate this**  **issue further as we ll as raise it for public comment.**  

### Response: The Agency is aware of concerns about DSI effects on fly ash leaching characteristics and usability when sodium

- based sorbents (e.g., trona, sodium carbonate) are used primarily for SO 2 

### control. In those case s, much more sorbent must be added than when HCl is the target pollutant because of the increased reactivity with HCl. EPA IPM modeling runs used sorbent injection rates that specifically targeted HCl emission limits. EPA is also aware of existing facili ties that are using sodium based sorbents for SO 3 

### mitigation and are storing the fly ash and, in some cases, selling the fly ash for concrete manufacturer. **Monitoring Requirements** Weare not aware of any HCL monitors that are commercially available and c an measure in the range of the proposed limit of .002 lb/MMBtu for existing EGUs, and we are not aware of any currently being installed at utilities to measure HCl in utility boiler flue gas. The proposed new unit limit is even lower. Did EPA consider the availability of these monitors when setting the standards or determinin g the compliance requirements? 

### Response: Yes, as mentioned earlier (and in the preamble), the proposed emissions limits were adjusted, when necessary, to account for measurement instr ument capabilities. Should an owner or operator find that an HCl CEMS is unable to make these measurements, he will be able to demonstrate compliance via surrogate monitoring (e.g., SO 2 

### CEMS or parametric monitoring, where applicable) fuel analysis, or em issions testing. It is our understanding that analyzer type mercury CEMs have proven much less reliable than CEMs for conventional pollutants. Wesuggest that mercury monitor requirements should be based on demonstrated mercury monitor availability for a significant number of monitors operating in both wet and dry stacks

– is this true for this rule?Summary of Interagency Working Comments on Draf t Language under EO 12866 Interagency Review. Subject to Further Policy Review.

Page 19 of 41 

### Response: We disagree with the assertion that mercury CEMS are viewed as being less reliable than other CEMS, noting that as with any newly

- acquired measur ement system, it can take owners or operators some time to become familiar with their equipment. As mentioned earlier, should an owner or operator of an affected EGU believe that a mercury CEMS would be unable to detect emissions at or below the proposed standards or be concerned with the reliability of an Hg CEMS, the proposal allows him the ability to choose to use a sorbent trap monitoring system. **Work Practice Standards** EPA’s proposal subjects EGUs to work practice standards for controlling organic HAPs. This standard requires the source to conduct an annual inspection and performance tune

- up of the EGU. The burner inspection may be delayed until the next scheduled outage, but must be conducted at least once every 12 months. Utility units routinely operate continuously for many months and in many cases over 12 months. **Ac cordingly**  **, we sug gest that these standards be so written that all burner inspection**  **and repair may**

**be conducted annually or during the next scheduled planned outage,**  **wh ichever is later. Inspection of other components that can be conducted without**  **shutting do wn the boiler m**  **ay still be conducted on an annual basis**

. 

### Response: Many, if not most, EGUs have planned annual outages. The inspection and tune up procedure was designed to occur during this normal occurrence. We will to extend the time between inspection and tune up s from 12 to 18 months to account for those EGUs with an unusual planned outage schedule, and we will take comment on the appropriateness of this period. **GHG Emission**  **s Increase as a Result of Compliance** The preamble and the RIA make reference to the electricity requirements for emissions control technology and the possibility that some equipment would increase GHG emissions. Wh ere is that information presented? 

### Response: Chapter 8. **Ap propriate and Necessary**  **Finding** Unless EPA is seeking comment on it s new and reasserted necessary and appropriate finding, EPA should remove this discussion (parts of section II and section III) from the preamble. It is confusing, and distracts from the major points of the preamble, which should be the regulatory decision s surrounding the establishment of emission standards and the data used to support them. EPA should outline the major points and finding of the previous rulemakings and court cases, then proceed from the assumption that the 2000 finding is current law bec ause of the court cases. The additional information and new necessary and appropriate finding can be a separate documented finding for the docket.Summary of Interagency Working Comments on Draf t Language under EO 12866 Interagency Review. Subject to Further Policy Review.

Page 20 of 41 

### Response: EPA will seek comment on all aspects of the appropriate and necessary finding. We think it is i mportant to include this in the preamble given the history of this finding and the fact that the finding and attendant listing will be subject to judicial review when the final rule is issued. **PRE AM**  **BLE Specific Comments**  **: Section IV. Summary**  **of this Prop osed NESHAP**  [ Page 317, Section IV.G, First Paragraph ] EPA has used the boiler height

- to

- depth ratio for establishing unit categories. **Please provide a clear definition of ho w s**  **uch a ratio would be measured.**  In general, the overall height and depth of a boiler are set based on the number of burners, burner spacing, required furnace residence time, fuel characteristics, etc. It may be possible that a unit with less than a 3.82 ratio used by EPA and firing a coal with less than 8,300 Btu/lb heating value would have the same problem controlling Hg as do the boilers with a ratio greater than 3.82. It may also be possible that the tested units were unable to show high Hg removal rates, because of certain fuel characteristics. Also, by using this same ratio for setting emission limits for new units, EPA appears to be assuming that the boiler design standards will not change in the future. **We also recommend that EPA**  **seek comments on this issue.** 

### Response: The ratio is based on information provided in an ind ustry comment made during the CAMR effort and is premised on the fact that low Btu coal boilers are physically larger than those for use with higher Btu coals. The industry comment provided a diagram of a boiler designed to burn each rank of coal. EPA is basing its definition on “information available to the Administrator” and solicits additional means for “defining” a unit designed to burn low Btu coal vs. one designed for high Btu coal. EPA is soliciting comment on all of its subcategory determinations
. [ Page 318, Section IV.G, Table 14 ] Please note the following comments on this Table:

 Wh at is the basis for the output

- based limits: gross or net unit output capacity? Does EPA plan to have both input

- and output

- based limits for the existing units i n the final rule?

 Wh at conversion factors (heat rates) are used for converting from input to output based limits?

 It appears that inconsistent input

- to

- output conversion factors have been used for different pollutants for the same boiler category. In ad dition, some conversion rates reflect unit heat rates that cannot be justified because they are well below what ca n be achieved by these plants.Summary of Interagency Working Comments on Draf t Language under EO 12866 Interagency Review. Subject to Further Policy Review.

Page 21 of 41  Wh y are both floor and below

- the

- floor Hg limits shown for the new coal

- fired units firing coals less than 8,3 00 Btu/lb? How can a below

- the

- floor limit that is three orders of magnitude smaller than the floor limit be justified?

 The emission limits selected for new units appear to be far more stringent than those imposed in recent air permits. Has EPA taken th e data from these permits into consideration before se tting the limits for this rule? 

### Response: The proposed output

- based emission limits are based on gross capacity. EPA plans on proposing that an existing EGU could select from either the input

- or the output

- based emission limits (as was done with CAMR). No conversion factor was used in establishing the output

- based emission limits; the limits were based on data provided through the 2010 ICR and developed independently of the input

- based emission limi ts (although the pool of top performing units is similar). Both floor and beyond

- the

- floor limits for mercury are shown for the <8,300 Btu/lb subcategory because we have in the past consistently shown both limits and are taking comment on both limits. EP A does not use permit levels in establishing MACT floors but, rather, the emission data provided. The emissions data reflects what is “achieved in practice” whereas the permit levels may be desired goals that may be bettered in practice. [ Page 331, Sect ion IV.I .5.b] **Please clarify**  **what pressure drop and flowrate are being measured for the wet scrubber.**  The pressure drop would normally change with flowrates, and the operator may not have any control over them. The sorbent may not be directly injected in to the scrubber, as it may be added to the system as a makeup stream, which will vary. 

### Response: The comment is not clear. The proposed rule contains operating parameter monitoring for two types of wet scrubbers (PM and acid gas) as well as for dry scru bbers (or dry sorbent injection). Proposed operating parameters include the pressure drop across and the liquid flow rate going through the wet PM scrubber; the liquid flow rate going through and the pH of the liquid in the wet acid gas scrubber; and the sorbent injection rate for the dry scrubber. For acid gas HAP control, determination of and maintenance of the pH of the wet acid gas scrubber liquid or the sorbent injection rate for the dry scrubber should address the locational concern expressed by the commenter. [ Page 332, Section IV.I.5.c] This section describes a procedure for establishing the minimum sorbent injection rate, which must be the average of the maximum injection rates during the performance tests

. **As suming that the maximum injection ra**  **tes w ould occur at the**  **maximum operating loads, using the same rates at lo w loads may**  **result in unreacted sorbent in the flue gas stream** 

**. This will increase costs and may be environmentally**  **harmful.**Summary of Interagency Working Comments on Draf t Language under EO 12866 Interagency Review. Subject to Further Policy Review.

Page 22 of 41 

### Response: Sorbent rates can be defined to be independe nt of the load
. For example, activated carbon injection rates are often reported in mass of sorbent per volume of flue gas (e.g., pounds per million actual cubic feet of flue gas). This sorbent rate

– as opposed to a mass per time (e.g., pounds per hour) rate

– should be independent of load and can, thus, avoid overuse of sorbent. Moreover, EGU owners or operators establish the minimum hourly average sorbent injection rate for each sorbent as measured during performance testing; should the owners or oper ators desire to have differing average sorbent injection rates depending on load, they are able to conduct testing at those other loads to determine those other rates. [ Page 333, Section IV.I.5.e ] This section requires that precipitator voltage and curren t of each collection field be measured during the performance tests to establish the minimum voltage and current values that must be maintained during all precipitator operation. Please note that the secondary current and voltage in each electrical bus se ction of a precipitator do change with the flue gas characteristics, and the operator may not have any control over these parameters. Also, most precipitators are built with design margins, which may allow them to take one or more mechanical fields or ele ctrical bus sections out of service and still maintain the stack limits. **Does the requirement in this section require that all precipitator fields be operational at all time? By** 

**default, this may**

**amount to mandating tighter controls than the MA CT**  **limits.** 

### Response: The proposal has been revised so that data on the number of fields in operation is no longer required. Rather, minimum hourly average secondary voltage and secondary amperage data, as well as a calculation of the total secondary power, is req uired in the proposal. **Section V. Rationale for this Proposed NESHA**  **P** [P ages 394

- 395 and 418

- 421 ] EPA rejects the option of fuel switching based its concerns about natural gas availability and environmental impacts of hydraulic fracturing associa ted wit h shale gas production. FERC’s seasonal market reports have found adequate natural gas supplies to meet U.S. generation requirements. **We suggest that EPA acknow**  **ledge FERC’s forecasts**  **and clarify**

**the concerns about long**  **- term availability** 

**.** 

### Response: EPA co uld remove this from the justification for the rejecting the beyond

- the

- floor analysis if FERC believes there is sufficient gas for all coal

- and oil

- fired electric generation to be replaced by natural gas wit hout the use of hyd r aulic fractur ing. [ Page 4 0 8, Section V.D, Last Paragraph] **Did EPA consider any** 

**measurement uncertainty in the instruments that were used during the ICR performance tests?**  Th ese uncertainty values are easi ly available in the industry. In addition, there are large measurementSummary of Interagency Working Comments on Draf t Language under EO 12866 Interagency Review. Subject to Further Policy Review.

Page 23 of 41 unce rtainties in the methods plants generally use for establishing parameters, such as fuel flowrates, etc. If EPA has used such data received from the plants for establishing heat rates, etc., there is a potential for large inaccuracies in these values.


### Response: Yes, as discussed in the preamble, the proposed MACT floors were adjusted as necessary to provide a measurement uncertainty (or accuracy) of the methods used consistent with the measurement uncertainties of other established Agency methods. [ Page 411, Section V.D., First Paragraph ] **Please clarify how variability in fuel**  **- related HA**  **P inputs was taken into account in establishing the emission limits.**  If EPA has only relied on the data collected during the short

- term ICR tests, such data may not acco unt for the variation in the characteristics of the fuels being burnt in power plants affected by this rule. EPA does cite some data that lists US coal characteristics affecting PM, HCl, and Hg emissions (ref. Documentation Supplement for the IPM Case v.4 .10), and such data can be used to verify the reasonableness of the emission limits being proposed. For example, a review of these data for HCl reveals that, for certain coals, the proposed emission limits require as much as 99.9% HCl removal for new unit s and 97% and higher removal for existing units. **Reviewers are n ot**  **aw are that such reduction levels are achievable with technologies being considered in**  **this rule. This is an important issue that should be raised when seeking public comments.**  

### Response: EPA did not have every EGU test for everything over a long period of time so as to fully be able to characterize fuel

related HAP variability. Absent that, we have incorporated such variability through use of as much of the data provided as allowed by th e statute. That is, we have used either 131 units (for the acid gas and non

- mercury metallic HAP) or 40 units (for the mercury) in the MACT floor pool. We have, therefore, incorporated as much fuel

- related variability as possible, to the extent it is exh ibited either across the 131/40 units or across the additional variability data used for a given unit within the MACT floor pool. EPA does not believe that it can use historic coal constituent data (e.g.,1999 ICR) absent corresponding emissions data for t hose same units. However, we did require that EGUs conduct fuel sampling concurrent with their 2010 ICR emissions testing. Based on that data, EGUs among the MACT floor pool are achieving in excess of 99.9% HCl removal (and units in the MACT floor pool a re meeting the proposed limit without achieving 99.9% HCl removal). [Page 427] The methodology used to set the mercury MACT floor for new sources, which uses individual emission test runs rather than the 3

- run average, may be flawed. This approach yields a MACT floor of 0.00001 lb/G Wh for all new coal

- fired power plants. Based on a quick analysis, this would require greater than 99% total mercury removal at all new PC

- fired power plants. In addition, the 0.00001 lb/G Wh limit is well below the detection limit for CEMS. In a recently completed DOE project, this detection limit was set from 0.1 to 0.4 micrograms perSummary of Interagency Working Comments on Draf t Language under EO 12866 Interagency Review. Subject to Further Policy Review.

Page 24 of 41 dry normal cubic meter of flue gas. The 0.00001 lb/G Wh emission limit equates to 0.0015 micrograms per dry normal cubic meter of flue gas. Is it possible that EPA intended the MACT floor for new sources to be 0.00001 lb/M Wh rather than 0.00001 lb/G Wh ? 

### Response: EPA conducted these analyses consistent with the approach taken on other NESHAP actions (e.g., Portland Cement, Industrial Boilers). As noted in the response to an earlier question, the proposed 0.00001 lb/GWh value is correct and is based on the data available to the Agency. If EPA were to only use a 3

- run average for new sources, there would be no basis for accounting for variabilit y and, thus, the resultant emission limit would be even more stringent than it is now. Also, as noted earlier, the 2010 ICR data indicate that there are EGUs in the MACT floor pool achieving greater than 99% mercury reduction. [P age 430, Table 17 ] The m ercury data provided below raises a couple of questions. For sources designed for coal ≥ 8,300 Btu/lb, the top performer average is equivalent to the proposed MACT floor (0.00001 lb/G Wh ), which raises the concern that this MACT floor is based on a single data point. At the very least, t he MACT floor appears to be based on limited sampling at a single top

- performing source. This is concerning because this MACT floor will apply to all new coal

-fired power plants (IGCC and PC regardless of coal rank), wh ich may be unrealistic for complianc e across the entire fleet of new coal plants. 

### Response: In fact, the proposed new

- source mercury floor value for this subcategory is based on data from six individual runs from the given EGU (i.e., the unit provided two data sets). However, the commente r is correct in that some of the proposed new

- source MACT floors are based on data from a single set of three runs. However, EPA is constrained to use the data it has. For sources designed for coal < 8,300 Btu/lb, a mercury emission level of 0.000007 lb/ GW h is provided for the top performer average. However, no EGUs in this category were among the top 12% performers, and this is the lowest mercury emission level provi ded anywhere in the preamble. 

### Response: As noted in the response to a previous questio n, EPA has reassessed its analysis of the MACT floor for mercury for this subcategory and has made the appropriate changes in the preamble. Using Aspen models developed by DOE/NETL for the Bituminous and Low

- Rank Baseline studies, the percent total mercury removal required at representative coal

- fired power plants to meet the proposed MACT floor was calculated. These representative coal

- fired power plants are designed for a net output of 550 M W and are equipped with the latest air pollution control device s. The following table provides the percent total mercury removal required to achieve the proposed MACT floors for new and existing sources. To align thisSummary of Interagency Working Comments on Draf t Language under EO 12866 Interagency Review. Subject to Further Policy Review.

Page 25 of 41 analysis with the source categories proposed by EPA, the MACT floor assigned to units fi ring bitumi nous and PRB coals correspond to sources designed for coal ≥ 8,300 Btu/lb, wh ile the MACT floor assigned to the ND lignite

- fired unit corresponds to sources designed for coal < 8,300 Btu/lb.

Coal Btu/lb (as received) Inlet

Hg (lb/hr) Outlet

Hg (lb/TBtu) O utlet

Hg (lb/G Wh ) % Total

Hg Removal Illinois #6 Bit

– Existing 11,666 0.058 1 0.008685 91.25% Illinois #6 Bit

– New 11,666 0.058 0.0011 0.00001 99.99% Rosebud PRB

– Existing 8,564 0.034 0.997 0.008294 85.8% Rosebud PRB

– New 8,564 0.034 0.0007 0.00001 99.99% ND Lignite

– Existing 6,617 0.056 1.995 0.01706 82.2% ND Lignite

- New 6,617 0.056 0.0011 0.00001 99.99% As shown in the table, the percent total mercury removal required at existing sources (91.25% for bituminous; 85.8% for PRB; 82.2% for ND l ignite) is stringent, but achievable at we ll

- controlled coal

-fi red units. However, the proposed MACT floor of 0.00001 lb/G Wh for new coal

- fired power plants would require greater than 99% total mercury removal at these representative units, which seems im practical under real

- world operating conditions. This is especially true in light of the fact that new EGU’s will need to meet this extremely high level of performance during periods of startup, shutdown and malfunction (SSM). 

### Response: Based on the dat a received through the 2010 ICR, EGUs using bituminous and subbituminous coal ranks are achieving in excess of 99.9% mercury removal and lignite

fired EGUs are achieving in excess of 95% mercury removal. As noted elsewhere, EPA has reassessed its MACT flo or analysis for the <8,300 Btu/lb subcategory and made the appropriate changes in the preamble. [ Page 452, Section V.K, Last Paragraph ] : Do the requirements for monitoring operating parameters apply to units that are already utilizing CEMS? If so, why would EPA need this information when CEMS are already there? As indicated in previous comments, establishing minimum values for these parameters would raise several operating issues and would result in unnecessary costs. 

### Response: Yes, as discussed in th e preamble, the proposed MACT floors were adjusted as necessary to provide a measurement uncertainty (or accuracy) of the methods used consistent with the measurement uncertainties of other established Agency methods. [ Page 463 ] EPA says it will work wit h DOE, FERC and others to reduce the adverse health impacts of power generation “while continuing to assure electric reliability is achieved .” GivenSummary of Interagency Working Comments on Draf t Language under EO 12866 Interagency Review. Subject to Further Policy Review.

Page 26 of 41 that FERC generally use s the term “maintain” with respect to reliability, we suggest EPA use this as well ( since we cu rrently “achieve” reliability)

. 

### Response: We will edit the text. [ Page 46 5, Section V.M, First Paragraph] EPA describes the “public health impacts of power generation” as “very significant adverse.” Recognizing that there are very significan t public health benefits of the proposed rule, this terminology may unwittingly be establishing a burden of proof for the agency, and suggest that the sentence could accomplish its purpose by deleting “very significant” and using the phrase “adverse public health impacts i n the power generation sector.” 

### Response: We will make this edit. [ Page 465, Section V.M, Second Paragraph ] EPA’s analysis shows a large number of new baghouses being retrofitted for compliance with this rule and while baghouses may be necessary for many units to comply with the required emission limits, we note the following concerns regarding the use of baghouses:

 The proposed rule does not indicate that EPA has confirmed that sufficient space exists in plants to install baghouses. M any plants may have used available spaces around the chimney to install scrubbers required by previous rules.

 The plants that have installed wet scrubbers around the chimney may have space available behind these scrubbers. However, a baghouse cannot be i nstalled downstream of a wet scrubber, due to the potential for pluggage of bags, etc. This is especially an issue for plants that have scrubbers but no SCRs and that may require baghouses for control of Hg.

 For some plants with scrubbers and firing high

- sulfur coals, sufficient space may be available upstream of the scrubbers to install baghouses (or to upgrade existing ESPs). However, the flue gas temperatures for these plants must be sufficiently high to avoid corrosion and baghouse pluggage issues. This is a significant issue with baghouse application on high

- sulfur coal facilities, because of flue gas temperature stratification caused by air heater rotation

. Usually, these plants may install flue gas mixing devices that cause as much as two inches of pressure drop (mainly an O&M cost item). **We suggest EPA**

**investigate the above issues and suggest that a dditional information**  **should also be sough t as part of public comments.**  

### Response: We will continue to look at these issues between proposal and fin al. [ Page 465, Section V.M, Second Paragraph ] EPA’s analysis shows a large number of units incorporating a trona

- based dry sorbent injection (DSI) system for controlling HCl. Wh ile this type of a DSI technology has been available for many decades, its u se in the power plant industry has been restricted to a few plants, because of the high sodium content of trona. Since most of this sodium is collected with ash, it mostly ends up being part of the ash in storage piles. Eventually some of this sodium wil l dissolve in rain water and any leachate thus formed wouldSummary of Interagency Working Comments on Draf t Language under EO 12866 Interagency Review. Subject to Further Policy Review.

Page 27 of 41 be subjected to strict wastewater discharge regulations. In this situation, the ash storage site would be required to install leachate collection and ground water monitoring systems. Ultimately, the collected leachate would have to be treated/destroyed. It may be very difficult or expensive for many plants to find facilities where treatment of this leachate would be feasible. Therefore, while we understand that the proposed DSI system is applic able, especially for plants with few years of remaining operations and plants with readily available facilities to handle ash storage leachate, its application on the large number of facilities being consi dered by EPA is questionable. W e recommend that EPA investigate this issue further as well as raise it for public comments. 

### Response: The Agency is aware of concerns about DSI effects on fly ash leaching characteristics and usability when sodium based sorbents (e.g., trona, sodium carbonate) are used pr imarily for SO 2 

### control. In those cases, much more sorbent must be added than when HCl is the target pollutant because of the increased reactivity with HCl. EPA IPM modeling runs used sorbent injection rates that specifically targeted HCl emission limits
. EPA is also aware of existing facilities that are using sodium based sorbents for SO 3 

### mitigation and are storing the fly ash and, in some cases, selling the fly ash for concrete manufacturer. [ Page 466, Section V.M, First Paragraph ] The three

- year impl ementation period with a potential one - year extension may be adequate for installing the controls described in this section on a single unit. However, some industry participants are concerned that a large number of concurrent retrofits precipitated by mul tiple environmental regulations will be slowed down by bottlenecks in the supply

- chains for equipment and skilled labor. Information related to this issue could be requested as part of seeking public comments on the proposed rule. 

### Response: We will add specificity generally taking comment on the timing issues. [ Page 466 , Section V.M, Last Paragraph ] This section mentions upgrade of existing precipitators (ESPs) to fabric filters (FF) as the main choice for acid gas control. Please note that upgrade of an ESP is a long

- lead construction activity, possibly requiring a unit outage of two or more years. If this option is used for a significant number of units, it is likely to have a large adverse impact on the grid reliability. 

### Response: We believe that there are a number of options to improve ESP performance that can be performed much more quickly. [ Page 476 ] EPA invites comments on the impact of the proposed rule on reliability and the authority available to EPA and other agencies to ensure compliance with EPA requirements wh ile maintaining grid reliability. Similarly, on page 561, EPA in addressing the impact of the regulations on grid reliability, asks for comments on the scope of various authorities to ensure, and to exercise discretion in relation to, compliance with the regulations. Wehave some concern with EPA asking commenters to opine on the scope of our authority to ensure compliance with our regulations.Summary of Interagency Working Comments on Draf t Language under EO 12866 Interagency Review. Subject to Further Policy Review.

Page 28 of 41 

### Response: EPA will remove this request for comment
. **VI. Background Information on the Proposed NSPS**  **(482)** [Page 487] Of the roughly 44 coal

- fired power plants installed in the U.S. since 2003, only 3 have been equipped with wet ESP’s, and none have been in operation longer than 2009. We suggests that this technology has not yet been demonstrated at a sufficient scale to serve as the basis of the rule and EPA should seek comment on this

. Does EPA have any further data to support the discussion of wet ESP? Referenced Text: In addition, both wet ESP and FGD control both filterable and condensable PM emissions and a combined standard allows for optimal design of the control equipment. 

### Response: Multiple existing facilities use WESP inclu ding the AES Deepwater and Xcel E nergy’s Sherco facilities in the U.S. , along with the New Brunswick Power Coleson Cove facility and numerous applications in Japan . In addition , the technology has been used on multiple new facilities and WESP have not been ruled out as a technology choice in preliminary BACT determinations for new facilities. Considere d as a whole, these data adequately support the conclusion that the use WESP has been adequately demonstrated as an appropriate basis for the rule. To the extent we receive comments that it is not a viable technology for new facilities, we will take that into consideration for the final rule. **VII. Summary**

**of the Significant Proposed NSPS A mendments**  [Page 489] Please clarify whether this refers to modifications that would result in an increase in the PM, SO 2 , and/or NO x levels? All three? Only one?


### R esponse: Modifications are pollutant specific and are triggered by an increase in the maximum hourly emissions rate resulting, in general, from any physical or operational change at an existing facility. Upon modification, the facility must comply with t he standard for the pollutant or pollutants for which there has been an emissions increase applicable to new units. [Page 489] The affected units need to be clearly defined. Referenced Text: Only those units that begin construction, modification, or re construction after [INSERT DATE OF PUBLICATION OF THE PROPOSED AMENDMENTS IN THE FEDERAL REGISTER] would be affected by the proposed amendments. 

### Response: The Affected facility is defined in the rule. It essentially is comprised of the utility boiler. Any affected facility on which construction, reconstruction, or modification is commenced after the amendments are proposed is subject to the revised standards per CAA section 111.Summary of Interagency Working Comments on Draf t Language under EO 12866 Interagency Review. Subject to Further Policy Review.

Page 29 of 41 [Page 490] The emission standard of 0.055 Lb/MW h (gross) i s approximatel y equal to 0.006 l b/MMBtu based on a gross heat rate of 8,760 Btu/kW h for subcritical or 8,230 Btu/kW h for supercritical. This level of control is roughly 3

- 4times as stringent as recently permitted coal plants which have been equipped with fabric filters : 1. Council Bluff Unit 4 (MidAmerican Energy)

– 2007 startup

– 0.025 lb/MMBtu PM limit

– FF (B&W) 2. Desert Rock supercritical (New Mexico)

– on hold but permit issued for 0.02 Lb/MMBtu 3. Franklin County CFB (Illinois)

– on hold but permit issued for 0.015 Lb/MM Btu 4. Longview supercritical (W V)

– 2011 startup

– 0.018 Lb/MMBtu 5. Matagorda County (TX)

– 2015 startup, permit for 0.016 Lb/MMBtu 

### Response: We are requesting comment on a range for the final rule, but believe, based on the data which we currently have, tha t the proposed emission standard is achievable by a properly constructed and operated facility. [Page 491] Should this be 0.7 l b/M Wh instead of 0.07? 0.7 is referred to elsewhere in this document. Referenced Text: Alternatively, we are proposing to am end the NO X emission standard for new, modified, and reconstructed electric utility steam generating units to 90 ng/J (0.070 lb NO

X /M Wh) gross energy output regardless of the type of fuel burned. 

### Response: Yes, and the error has been corrected. [Page 49 2] Please clarify criteria that can identify when an “innovative” technology becomes “proven”. At that point, do the more stringent limits kick in? Referenced Text: We are proposing several amendments that would exempt owners/operators from certain of the proposed amendments. First, we are proposing that owners/operators of innovative emerging technologies that apply for and are granted a commercial demonstration permit by the Administrator be exempt from the proposed amended standard. 

### Response: The alternative standard is permanent for an affected facility for which it is approved regardless of whether the technology becomes “proven.” The standard applicable when a commercial demonstration permit is issued would be updated similar to other NSPS. [P age 492] Please clarify whether a successful applicant would be granted the higher limit for all 3 (SO 2 , PM, NO x ), or just for the pollutant that their innovative technology addresses. For instance, would a plant with an approved, innovative SO 2 scrubber also be granted higher NO 2 emission limits? Referenced Text: We are proposing several amendments that would exempt owners/operators from certain of the proposed amendments. First, we are proposing that owners/operators of innovative emerging technologies that apply for and are granted a commercial demonstration permit by the Administrator be exempt from the proposed amended standard. 

### Response: Commercial demonstration permits are granted on a case - by

- case basis and the alternative limit(s) in the perm itSummary of Interagency Working Comments on Draf t Language under EO 12866 Interagency Review. Subject to Further Policy Review.

Page 30 of 41 

### are pollutant specific based on the pollutant or pollutants controlled by the innovative technology. **VIII. Rationale for this Proposed NSPS**  [Page 500]: Wesuggest EPA release the emissions data used to establish the standards, and encourage EPA to s eek public comment on whether transient operations have been treated appropriately in the floor calculation. Referenced Text: To establish a robust data set on which to base the proposed amendments, we analyzed emissions data from both older plants that h ave been retrofitted with controls and recently operational facilities. We did not attempt to filter out periods of startup or shutdown and the proposed standards, there fore, account for those periods. 

### Response: The data will be available in the docket when the proposed rule is published and we are specifically requesting comment on periods of startup/shutdown. [Page 500

- 502] If a mathematical average (steady state and transient activity) was used to determine baseline emissions, then units will almost certainly be out of compliance during startup/shutdown/transient operation. Since the proposed amendments were based on operation that did not attempt to filter out transient periods, there should be concern about a plant’s inability to meeting emission standards during startup and shutdown

– which is a reasonable part of plant operation

– and not operator intoxication or insanity. These are extreme examples and don’t really characterize the nature of startup/shutdown, which will naturally have higher emi ssion rates due to reduced plant efficiency. Referenced Text: Our proposed approach is to not consider malfunctions as a distinct operating mode. Under this approach, all periods would be included when determining compliance with the applicable standard. Neither CAA section 111 nor any case law require that EPA anticipate and account for the innumerable types of potential malfunction events in setting emission standards. See , Weyerhaeuser v Costle , 590 F.2d 1011, 1058 (D.C. Cir. 1978) (“In the nature o f things, no general limit, individual permit, or even any upset provision can anticipate all upset situations. After a certain point, the transgression of regulatory limits caused by ‘uncontrollable acts of third parties,’ such as strikes, sabotage, oper ator intoxication or insanity, and a variety of other eventualities, must be a matter for the administrative exercise of case

- by

- case enforcement discretion, not for specification in advance by regulation.” ) **We recommend that EPA**  **specifically**

**address tre atment of startup and shutdo** **wn and distinguish the basis for that treatment from the discussion of malfunction**  **and seek comment for data on multi**  **- year removal levels from more plants** 

**.** 

### Response: The multi

- year emissions data used to establish the proposed standards includes periods of startup and shutdown in calculating the 30

- day averages. If we filtered out those periods the standards would likely be more stringent. Thus, we believe that the proposed standards adequately account for periods of startup and shutdown. We think that it is clear that the discussion in the referenced text is limited to malfunctions.Summary of Interagency Working Comments on Draf t Language under EO 12866 Interagency Review. Subject to Further Policy Review.

Page 31 of 41 [ Page 506 ] EPA says that potential uncontrolled SO2 emissions were calculated using monthly delivered fuel receipts and fuel quality data from EIA forms EIA

- 923, EIA

- 423 and FERC

- 423

. Wh ile historical data is available from FERC Form No. 423, the Commission discontinued use of the Form in March, 2008, pursuant to Order No. 709. Wesuggest EPA check their data source and clarify this information if necessary. 

### Response: We used delivered fuel data from the 423 forms prior to 2008 and used the 923 data for 2008 & 2009. [Page 512] Some might argue that to propose a broad removal level (97%) that is going to apply to an entire fleet of plants, ba sed on multi

- year performance of only three coal units, is perhaps insufficient background data. **We s trongly**  **suggest gathering more data on multi**   ** year removal levels** **and specifically seek comment on this issue and the need for**  **additional data in the pream ble** 

**.** Referenced Text: Of the identified best performing facilities, we only have multiple years of performance data for the Harrison, Trimble County, and Mountaineer facilities. Based on the performance of these facilities, we have concluded that 97 per cent reduction in potential SO 2 emissions has been demonstrated and is achievable on a long term basis. 

### Response: We are requesting comment on a range for the final rule, but believe that the data we do have adequately supports the proposed standard. We will request comment on the availability of additional data and will review any additional data we receive prior to issuing the final rule. [Page 515] Even though they are both coal

- based technologies, a requirement to switch to IGCC could be viewed as “redefining the source.” Please clarify. Referenced Text: Owners/operators of new and reconstructed facilities burning coals with higher uncontrolled SO 2 emissions would either have to use IGCC with a downstream process to control sulfur prior to combus tion, fluidized bed combustion, or a wet SO 2 scrubbing system to comply with the standard. 

### Response: We are not requiring anyone to specifically consider IGCC, we are merely pointing out a number of options for meeting the standard when using high sulfur coal and one such option is the use of IGCC. [Page 524; Table 24] The four plants referenced in Table 24 represent a total of 1.8 GW of generating capacity, and there are about 339 GW (EIA) of installed coal capacity in the United States. It appears th at EPA is establishing an emission limit that is based on the performance of only 0.5% of the capacity. More data would help support the policy conclusion that 1.2 lb/M Wh is an appropriate figure for the standard. Referenced Text: Although 2 of the faci lities shown in Table 25 are operating below 1.0 lb/MWh, there are 4 that are operating in the 1.1 to 1.2 lb/MWh range. To provide a compliance margin and to account for situations where NO X might be more of a priority pollutant than CO, we are proposing a combined standard of 1.2 lb/MWh. 

### Response: Certified CO CEMS data has been challenging to find and we are specifically requesting additional data. We believe,Summary of Interagency Working Comments on Draf t Language under EO 12866 Interagency Review. Subject to Further Policy Review.

Page 32 of 41 

### however, that the data considered adequately supports the proposed standard. Additional dat a will be considered as it is available. [Pages 524

- 525] The performance of 4 units may be inadequate to serve as a basis for setting an emissions limit applicable to the entire fleet. Referenced Text: All 4 of the WA Parish facilities have demonstrate d a standard of 230 ng/J (1.8 lb/MWh) is achievable and we are therefore proposing that standard for modified facilities. 

### Response: Same as previous response. [Pages 537

- 538] Does fixed capital cost include installation labor? W ho determines what the cost of a new design is? Also, the term “economically feasible” needs clarification. Referenced Text: Reconstruction means the replacement of components of an affected facility such that; (1) the fixed capital cost of the new components exceeds 50 perce nt of the cost of an entirely new steam generating unit of comparable design, and (2) it is technologically and economically feasible to meet the applicable standard (40 CFR 60.15). 

### Response: This section has been deleted since we are not proposing chang es to the general provisions. [Page 540]: EPA asks for comments on the impact of reliance on combined heat and power and whether it is appropriate to recognize the environmental benefit of distributed generation in reducing line losses. Line loss has be en a controversial issue in our wholesale markets and it isn’t clear whether EPA intends to make recommendations to FERC on wholesale market design based on comments in this rulemaking. Wesuggest that EPA clarify why it is asking this question. 

### Respons e: We do not intend to make any recommendations to FERC. The proposed approach would divide the electrical output of CHP facilities by 0.95 (increasing the electric output used in determining compliance) and make compliance “easier” for owner/operators o f CHP facilities. **IX. Summary**

**of Cost, Environmental, Energy , and Economic Impacts of the Proposed**  **NSPS** [General Comment] Has EPA conducted a review to verify whether or not the required plant modifications under this rule would trigger NSR for certain plants? There is a potential for this to occur, since some emission increases may result from the increased parasitic loads. A unit triggering NSR may be a candidate for improving plant efficiency (upcoming GHG BACT) and for converting from once through c ooling to closed cooling [recently proposed 316 (b) rule]. Cost implications of such impacts could be very high. 

### Response: We will consider these issues as we move forward with all three actions. [General Comment] Many reviewers would like to have fur ther discussion of the compliance costs of this proposed rule. In particular, cost estimates for upgrading existing scrubbers is ofSummary of Interagency Working Comments on Draf t Language under EO 12866 Interagency Review. Subject to Further Policy Review.

Page 33 of 41 interest. Also, installing multiple controls in series downstream of the boiler would subject the flue gas system to highe r pressures, and this could require structural strengthening, which EPA has considered in previous rules. 

### Response: We are happy to further consider these issues between proposal and final. [General Comment] The use of a multi

- market model does not see m appropriate for the social cost estimates. W e suggest that EPA discuss why they did not use CGE modeling, and commit to issuing a NODA with the CGE model results within the next few months. Wealso suggest that EPA seek comment on alternative approache s for estimating the social cost of the rule. 

### Response: EPA used the multi

- market model for the boilers rule
. We preferred to used our CGE model (EMPAX) for this rule but recent advice from our SAB about the need to incorporate the benefit

- side effects caused us to defer use of the EMPAX model
. We explain this in the revised RIA chapter and plan to use the upgraded E

MPAX model for the final RIA. We do n o t expect the model to be updated in time for a NODA. [Page 551; Paragraph 1] EPA states that owners/operators of new EGUs subject to the requirements of the Clean Air Transport Rule will likely elect to minimize operating costs by operating at SO 2 and NO X emission rates lower than what is required by the existing NSPS. Accordingly, EPA believes the EG U NESHAP PM and SO 2 standards for new facilities are as stringent or more stringent than the proposed NSPS amendments so they have concluded that there are no costs or benefits associated with these amendments. These statements need to be confirmed by spe cif ically requesting public comment on these issues. 

### Response: We will specifically request comment on these issues. [Page 552; P aragraph 1] Analysis of the proposed rule predicts 2,000 M W o f new near term (by 2015) coal

-fired capacity additions. All of the capacity is assumed to include carbon capture and storage (CCS) that is funded by some government mechanism but does not get into any details. This assumption is tenuous. Can EPA explain why the CO2 capture status is relevant? Additionally, this b egs the question of what kind of regulatory regime was used in the IPM run

– does it include CO2 or the other regul ations that EPA is developing? 

### Response: These projections are all based on existing ARRA and EISA funding and are consistent with EIA proj ections. We will delete references to CCS because it is not relevant [Page 552] Edit: Should this be “the use of a steam turbine”? Referenced Text: Because the use of natural gas in EGUs is an inefficient use of natural gas to generate electricity...


### R esponse: Yes, use of natural gas in a steam turbine

- based EGU is inefficient. The language will be clarified. **X. Impacts of these Proposed Rules**Summary of Interagency Working Comments on Draf t Language under EO 12866 Interagency Review. Subject to Further Policy Review.

Page 34 of 41 [Page 554] Should air impacts of the proposed rule be discussed here? 

### Response: This section has been added to the 03/10/2011 version of the draft package. [Page 555] Should water and solid waste impacts of the proposed rule be discussed here? 

### Response: This section has been deleted. [Page 555; Paragraph 1] EPA expects an increase in electricity cons umption and total national annual energy usage as a result of the rule but does not detail a specific amount. It would also be insightful to describe how EPA would expect such increased energy usage would be distributed among each category of EGUs subject to the rule (e.g., existing and new sources.) 

### Response: This language was erroneously included in the Toxics Rule and has been replaced with economic impacts language directly tied to RIA Chapter 8 findings. [Page 555] Efficiency projects have been av ailable at existing plants for years, and NSR among other impediments have stymied them. Please clarify the basis for the expectation that work practice standards will improve. The assumption of a percent increase is important, and it may be a point of co ntention. Referenced Text: A dditionally, EPA expects work practice standards such as boilers tune

- ups and combustion controls will improve the efficiency of boilers, resulting in an estimated fuel savings of {__} trillion BTU each year from existing sour ces and an additional {___} million BTU each year

. 

### Response: This language was erroneously included in the Toxics Rule and has been replaced with economic impacts language directly tied to RIA Chapter 8 findings. The Toxics Rule analysis does not assume any efficiency increases at utility boilers. However, the IPM power sector analysis shows an increase of 2,350 GWh in generation in 2015, which is a 0.06% increase over the base case projection. [Page 556; Paragraph 2] EPA assumes the statutory time av ailable (3 years, with discretion for the permitting authority to provide up to 1 additional year) is sufficient to comply with the requirements of this rule yet this timeframe may be unrealistic for industry given grid reliability issues that may result f rom closing old coal

-fired plants, extended periods of down time required to modify equipment, and the availability of labor and materials needed. W e suggest EPA explain their analysis of how many facilities they expect to be in compliance after 3 years a nd how many they expect to need the additional year. 

### Response: EPA’s analysis does not break out these numbers, because of unit

- specific issues, as it is difficult to project how many units may take advantage of the 1

- year compliance extension. [Page 55 7] DOE suggests (and requests ) that the sentence be revised to say, “...will continue to work...” instead of “has worked closely”. DOE has not evaluated the potential impact of theSummary of Interagency Working Comments on Draf t Language under EO 12866 Interagency Review. Subject to Further Policy Review.

Page 35 of 41 rule on the grid, but it has generated some proxy scenarios, which were devel oped before seeing the proposed rule. Referenced Text: In developing this proposed rule, EPA has worked closely with other agencies, including the Federal Energy Regulatory Commission (FERC) and the Department of Energy (DOE), to evaluate the potential i mpact of the final regulation on the grid. 

### Response: We will make the edit. [Page 558; Paragraph 2] To remedy reliability issues, EPA assumes transmission upgrades, targeted demand side management strategies, and construction of new generation; we sugg est that if this discussion remains, EPA should also discuss funding availability or permitting issues associated with such steps and the time that it would take to implement them, as well as seeking comment on this topic. 

### Response: We will add specifi ci ty to language generally taking comment on the timing issues. [Page 561] Should compliance cost be included in this discussion? 

### Response: This will be included. The annual compliance cost is $10.9 billion (2007 dollars). [Page 561; Table 26] The tab le summarizing capital and annual costs is blank in the version of the proposed rule received for interagency review. **Can EPA provide these tables?**  

### Response: Yes, we will. The table will be similar to what is in the executive summary of the RIA. [Page 563] The following sentence appears to suggest that the labor intensity of a power plant increases after it is retrofit (i.e. more jobs to operate the same plant). Presumably, the retrofit plant is operated by staff who already hold the jobs at that pla nt. Referenced Text: The job gains due to new retrofit requirements are likely to be tempered by some job losses due to plant retirements, though, as discussed below, many of these workers who lose their jobs due to plant retirements could find replaceme nt jobs operating these new retrofits at nearby units

. 

### Response: The e ntire employment discussion is being rewritten. [Page 564] It is our understanding that coal mining is more labor intensive than natural gas extraction

– can EPA provide a citation to the following statement “ Finally, job losses due to reduced coal demand are likely to be offset by job gains due to increased natural gas demand, resulting in minimal net change in j obs due to fuel demand changes.” 

### Response: As stated in the Employme nt Effects TSD. [Page 568; Table 28] EPA analysis in Table 28 appears to indicate employment may actually decrease following the rule (possible 68,000 jobs lost due to demand effect), which can be noted in the text.Summary of Interagency Working Comments on Draf t Language under EO 12866 Interagency Review. Subject to Further Policy Review.

Page 36 of 41 

### Response: Such a result will be note d in the text, along with other results. [Page 568; Paragraph 1] Using the Morgenstern, et al. four industry average parameters and standard errors and EMPAX models, it is possible that EPA did not quantify all associated job losses associated with the p roposed rule. Indirect jobs such as industries that use electricity and face higher electricity prices as the result of the proposed rule could reduce output, and demand less labor may not be factored into EPA calculations. 

### Response: We mention the lack of indirect job impact estimates from our analysis in Chapter 9 of the RIA, and we will include such language in the preamble. [Page 568] Even though the impact on jobs of higher electricity prices cannot be easily quantified, the higher prices themselv es should be reported from the results of the IPM analysis Referenced Text: Also, industries that use electricity will face higher electricity prices as the result of the proposed rule, reduce output, and demand less labor. Although EPA has considered s ome economy - wide changes in industry output as estimated using the EMPAX model as shown earlier, we do not currently have sufficient information to quantify these associated job gains and losses for this proposed rule. 

### Response: We will include the elect ricity price changes here that are already reported in the EO 13211 section of the preamble. **REGULA**

**TO RY IMPA** **CTS A NA**  **LYSIS** The emission limit tables in Chapters 2 and 8 are different. The tables in Chapter 8 appear to be the correct limits since they match the limits in the proposed rule. 

### Response: The correct emission limits will be included in Chapter 2. **Specific Comments: Chapter 1: Executive Summary**  [Page 0; Section 1.1, through page 1; Section 1.1.1] The findings box and text discussion in Sectio n 1.1.1, do not clearly convey that the vast majority of monetized benefits come from co

benefits of PM. For transparency, this fact should not just reside as a footnote to Table 1

- 1 or within data shown in Table 1

- 3. Additionally, within Table 1

- 3, the monetized value of avoided IQ loss at the 7% discount rate may be erroneous. [Page 5; Table 1

- 3] How do es EPA plan to account for the s ocial cost of carbon? 

### Response: We are upgr ading entire Executive Summary and will clarify the language
. **Chapter 5: Mercury** 

**and other HA P Benefits Analy** **sis**Summary of Interagency Working Comments on Draf t Language under EO 12866 Interagency Review. Subject to Further Policy Review.

Page 37 of 41 [Page 11; Section 5.2.9] The first several sections of Chapter 5 detail numerous studies conducted around the world to determine health related issues associated with MeHg. The only thing certain in all of these s tudies is that they are all inconclusive in their findings and that Me Hg may lead to certain health problems in children and adults. This should be more clear in Chapter 5.


### EPA re sponse: We have streamlined the health effects sections of Chapter 5 to be consistent with the descriptions in Section III.D of the preamble. [Page 6; Section 5.6.2.1.1.2] W hy does the proposed rule single out low

- income subsistence fishers in the southeast region in the proposed rule? 

### EPA response: One of several studies cha racterizing high

- end self

- caught fish consumption rates in the U.S. cited in the RIA provides data that could be used to characterize self

- caught fish consumption rates for these two fisher populations (i.e., poor whites and blacks living in the Southeast) . However, it is important to note that the RIA included a number of additional high

- end self

- caught fish consuming populations (e.g., Laotian, Hispanic and Chippewa /Ojibwe), all of which are supported by high

- quality study data characterizing consumption rates. In addition, consideration for the full set of studies characterizing high

- end self

- caught fish consumption identified in designing the RIA supported modeling a low

- income female recreational/subsistence fisher more broadly across the U.S. In consid ering the nature of risks experienced by high

- end self

caught freshwater fish consumers in the RIA, we consider all of the populations modeled and did not place greater emphasis on blacks and whites in the Southeast. [Page 24; Section 5.8.5] EPA acknowl edges that these findings are not perfect and that many assumptions and information provided from sources (i.e. states, reports, etc.) may overestimate the mercury levels consumed in fish. Can EPA quantify these overestimates or describe th e uncertainty i n the analysis? 

### EPA response: The uncertain ties in the analysis are discussed in section 5.8 of the chapter. Further characterizations of uncertainty have been added in that section, however, we are not able to quantify many of the uncertainties. [Pag es 35

- 45; Section 5.9.1] The proposed rule discusses several other hazards (other HAP than mercury) but does not relate or quantify any findings or studies associated with el ectric generation and the HAP. 

### EPA response: Due to limitations in modeling and availability of concentration

- response information for many HAP, we areSummary of Interagency Working Comments on Draf t Language under EO 12866 Interagency Review. Subject to Further Policy Review.

Page 38 of 41 

### unable to quantify the direct health benefits associated with non - Hg HAP reductions. This is consistent with many recent HAP rulemakings. **Chapter 6: Co -**  **Benefits A nalysis and Results**  [Page 86; Paragraph 2] The study included in determining endpoints used PM 10 unlike all other studies to that point which only focused on PM 2.5 , can EPA explain this? 

### EPA response: When estimating PM2.5

- related health impacts EPA applies risk estimates drawn from epidemiological studies that meet as many of the selection criteria summarized in table 6

- 4 as possible. In rare cases, the epidemiological, clinical and toxicological literature may indicate that a particular health endpoint is causally relate d to PM2.5, but no suitable epidemiological studies exist that report risk estimates based on a PM2.5 indicator. In such situations, EPA will apply risk estimates drawn from epidemiological studies that consider a PM10 indicator. [Page 121; Paragraph 2] The preamble states that nitrogen and sulfur in the troposphere can travel great distances. Has EPA modeled emissions from across US borders? If so, how? 

### EPA response: The air quality modeling chapter describes in detail how the boundary conditions we re modeled. [Page 121; Paragraph 2] Wh en can society expect to receive the detailed benefits in the proposed rule? Is there a difference the timeframe for when the rule will start reducing the environmental and health effects versus when people will s ta rt experiencing the benefits? 

### EPA response: In general, the benefits occur contemporaneously with the year in which the rule requires facilities to reduce emissions of mercury and PM2.5 precursors. In the case of PM mortality, mortality risk reductions are assumed to occur with a distributed lag in the years following the change in PM concentrations, and benefits are discounted over the distributed lag period. Complete information regarding the assumptions and data inputs to the benefits analyses may be found in the benefits chapters. [Page 121] Several sections throughout the chapter are missing (i.e., Sectio ns 1.1.6.1, 1.1.6.2, 1.1.6.4, e t c ) with no indication what the section is expected to contribute to the discussion. **Chapter 8: Cost, Economic, a nd Energy Impacts**  [Page 14; Paragraph 2] Unlike the preamble, EPA projects annual incremental compliance cost of the proposed Toxics Rule to be $12.4 billion in 2015 ($2007). The proposed rule and itsSummary of Interagency Working Comments on Draf t Language under EO 12866 Interagency Review. Subject to Further Policy Review.

Page 39 of 41 RIA would benefit from disclosed documentation about assumptions that went into the IPM model to generate those figures for EPA. 

### Response: IPM modeling assumptions are fully documented and have been circulated in the interagency review process for the Toxics Rule proposal. Some of this documentation is a lready publicly available ( http://www.epa.gov/airmarkt/progsregs/epa

ipm/BaseCasev410.html#documentation ) 

### and the supplemental documentation circulated in th e interagency process will also be published on our website with the release of this proposed rulemaking. [Page 16; Paragraph 1] Analysis of the proposed rule suggests that a vast majority (over 95% according to table 8

- 8) of base case coal capacity woul d remain in service under the proposed Toxics Rule. It is critical that EPA perform comprehensive modeling of the impact that all proposed rules for all media (water, air, and solids

— including greenhouse gases) would have on coal plant retirements. Retirement decisions will not be made on a single rule but on the total expected investment required for compliance. 

### Response: EPA acknowledges this comment and will take it into further consideration. [Page 17; Paragraph 1] The results of the analysis fo r the rule predict 10.2 G W of coal

- fired capacity to be uneconomic to maintain by 2015. How was this determined? Can EPA provide a list of these modeled shutdowns? The assumptions and the analysis should be identified for comment in the preamble. 

### Respo nse: EPA has circulated full documentation of its IPM power sector modeling assumptions and has provided a list of planned and modeled retirements for interagency review. [Page 28; Paragraph 3] How does EPA take into account other associated costs such as emissions monitoring, reporting, record keeping, and administrative costs in their annualized cost estimates? 

### Response: The relatively small cost associated with monit oring emissions, reporting, and record keeping for affected sources is not included in the IPM

-projected annualized cost estimates. Instead, EPA has done a separate analysis of these costs. Estimates of the monitoring, reporting, recordkeeping, and other administrative costs are found in the preamble (Paperwork Reduction Act) and Chapter 10 of the RIA. These costs are estimated separately from the control costs estimated by IPM, and are presented separately. [Page 32; Paragraph 2] The rule analysis pro jects coal production for use by the power sector will decrease by 20 million tons from base case levels by 2015. Did EPA model or consider whether world demand for coal or natural gas (e.g., U.S. becoming an exporter of these resources) could alter calcu lations associated with expected future prices?Summary of Interagency Working Comments on Draf t Language under EO 12866 Interagency Review. Subject to Further Policy Review.

Page 40 of 41 

### Response: EPA did not model any sensitivities based on alternative demand for fuels in foreign countries. [Page 32; Paragraph 1] Natural gas consumption is expected to increase 4 to 6 percent by the power sector from 2015

- 2030 but the proposed rule fails to mention whether the necessary infrastructure is in place or the cost associated with building new pipelines. W e suggest EPA clarify this in the preamble and the RIA. 

### Response: EPA has incorporated th is comment in revised materials. [Table 8

- 13 ] The historical coal production data for the electric power sector for 2007 appear to be incorrect. Although EIA data is referenced, the web page that is sited is probably not the best source for these data. T he value of 350 million short tons for Appalachia appears to be off by the most, being about 70 million short tons too high. The attached file provides estimated data for the years 2007 through 2009. I recommend using more recent EIA data for either 2008 o r 2009. The 2009 coal distribution data were posted at the EIA web on February 18, 2011 ( http://www.eia.gov/cneaf/coal/page/coaldistrib/a_distributions.html ). 

### Response: EPA appreciates these data clarifications and have incorporated them into the revised RIA for Toxics Rule proposal. The historical coal price data fo r 2007 appear to be incorrect. Although EIA data from the Annual Energy Outlook 2011 (AEO2011) Early Release (December 16, 2010) are referenced, it looks like the data for minemouth and delivered prices were p erhaps inadvertently switched. The average minemouth coal price for 2007 from the AEO2011 Early Release should be $1.27 per million Btu (2007 dollars) and the average delivered price of coal to the electric power sector for 2007 should be $1.76 per million Btu. [For the average minemouth and delivered coal prices (2007 dollars) from the AEO2011 Early Release see rows 352 and 361, respectively, in the attac hed spreadsheet.] 

### Response: EPA appreciates this observation and has corrected this in the revised RIA for Toxics Rule proposal. [Table 8

- 17] Although EIA data from the Annual Energy Outloo k 2011 (AEO2011) Early Release are referenced, this table doesn ’t actual ly contain any historical data. 

### Response: EPA appreciates this observation and has corrected this in the revised RIA for Toxics Rule proposal. **OCTOBER 2002 EPA**

**STU DY: “ENGINEERING A**  **ND ECONOMIC FA** **CTORS A FF**  **ECTING THE INSTA**  **LLA**

**TION OF CONTROL TECHN**  **OLOGIES FOR MULTPOLL UTA**  **NT STR** **ATEGIES”** [General Comment] The construction schedules and other technical information (e.g., for mercury controls) in this report are outdated. Some of this information has already been revised by EPA in other previous rules (CAIR and CAMR). Werecommend a revision of this study or a new study concentrating on controls specifically required under the Toxic Rule is recommended.Summary of Interagency Working Comments on Draf t Language under EO 12866 Interagency Review. Subject to Further Policy Review.

Page 41 of 41 

### Response: This e ntire section is being rewritten. Note that ICF 2011 reference updated 2002 repo rt as needed
. **RESOURCE A DEQUA** **CY A ND RELI**  **ABILITY IN THE IPM PROJECTIONS FOR THE TOXICS**  **RULE** "Within each model region, IPM assumes that adequate transmission capacity exists to deliver any resources located in, or transferred to, the region." This is a big assumption that needs to be tested. IPM retires capacity if it is no longer needed to provide energy for load or to provide capacity to meet reserve margin during the planni ng horizon of the projections. But other operational issues need to be consi dered for reliability purposes, such as system stability (inertia, frequency, black start capabilities, etc) outside the reserve margin issue. Coal retirements are distributed throughout the power grid, so there will be only small impacts at the regional level. For example, the coal generating areas in western Pennsylvania, W est Virginia, Ohio and Indiana all have significant excess generation resources: these areas combined see a decrease less than 2% in their reserve margins and the reserve margin for t he co mbined area remains over 20%. This is a skewed result as the exam ple states are in different IPM regions. Very few new capacity additions are needed to accommodate coal retirements, once excess reserves and non

- coal retirements relative to the base case are considered. It is not clear for how long the impact of not adding capacity. This issue needs to be addressed considering the long build times required for new c apacity to be brought on line. In cases where it is economic to transfer reserves f rom a neighboring region rather than supply reserves from within a region, IPM will transfer reserves, subject to summer and winter limits that are designed to ensure that these reserves can be transferred reliably. If transmission has not b een modeled how can this occur? (regarding first bullet above) Some specific IPM regions ha ve known congestion constraints (e .g., NYC, NJ/DE, etc.) so if it is not economical to transfer reserves, what do those dependent regions do to move forward without a reliability event? For example, the retired coal capacity in TVA (1,084 M W)is replaced by a net increase in transfer of reserves to TVA (1,097 M W)

. Wh ere is that capacity transferred from? Is it possible to transfer power into the TVA region? 

### Response: EPA’s pow er sector modeling assumes the ability for firm transfers of capacity between modeling regions subject to interregional firm transfer constraints based on current operation of the grid and known constraints. These assumptions can be found in our modeling documentation at http://www.epa.gov/airmarkt/progsregs/epa

- ipm/BaseCasev410.html#documentation

.