Comment: Hg CEMS. Commenters raised a number of technical concerns about Hg CEMS. Many commenters requested modifications so that the requirements would be more consistent with Part 75 monitoring requirements. Some commenters questioned the ability of the technology to demonstrate compliance with emission limits at very low levels especially for new sources. Commenters also opposed high data availability requirements given that the technology is new and difficult to operate and maintain.
Response: We indicated in the proposed rule the intent to adopt the CAMR-based requirements for Hg monitoring in place of the general 40 CFR Part 63 standards. With CAMR, these operating and reporting requirements for Hg CEMS went through notice and comment rulemaking for the same sources as covered by this final rule. Although CAMR was set aside on other grounds, these technical specifications and QA requirements reflect significant input from stakeholders and analysis by the EPA to establish an appropriate foundation for Hg monitoring at electric utilities under the CAA. For the final rule, we have made conforming changes to ensure that this intent is carried out effectively throughout the rule text and Appendix A, as well as including certain additional clarifications based on the input received in response to the proposed rule. We have also removed a cycle time test as unworkable for certain types of Hg CEMS.
      The final rule provides the option for use of either Hg CEMS or sorbent trap monitoring systems. We believe the record clearly shows these to be proven technologies each providing certain advantages. For existing and some of the new unit standards, the level of the NIST-traceable Hg standard will be adequate and consistent with existing applications of Hg CEMS. For the lowest limits and other applications where the system offers advantages, affected facilities may opt to use sorbent trap monitoring systems to comply. As noted in a previous response above, there are data in the recent draft report entitled "Determining the Variability Of CMMS At Low Hg Levels," that demonstrate reasonable performance of at least one Hg CEMS at Hg levels below 1.0 microgram per cubic meter (ug/m[3]) down to approximately 0.1 ug/m[3]. Finally, there is no specific minimum data availability requirement for Hg CEMS (or any other CMS required under this final rule). This issue is discussed further below.
Comment: SO2 CEMS: Although commenters were generally supportive of the ability to use SO2 CEMS for units with FGD installed as a surrogate for HCl, there were some concerns with aspects of the proposal. First, commenters requested that the requirements rely on Part 75 given that their sources were already meeting those requirements and not establish new requirements, especially a fourth linearity level and the application of 7-day calibration error tests for units with low concentrations (where Part 75 provides an exemption). Commenters were also concerned that the rule language only allows the option where the FGD is operated "at all times" which seems to imply that the option is not allowed if the source ever bypasses the FGD for start-up, shutdown, or malfunction reasons.
Response: After reviewing the comments and assessing the need for an additional calibration gas at the emissions limit, we have removed this requirement from the final rule while retaining a requirement for a linearity check even for SO2 monitors with low span values (<= 30 ppm). You can already report linearity tests for these units within the context of the existing ECMPS reporting without triggering any critical errors. This test can be accommodated within the current framework without causing issues for Part 75 reporting. The 7-day calibration error test is removed. For the "at all times" language, we have clarified this in the final rule. The intent is that the FGD be operated during all routine boiler operations, and not operated intermittently, seasonally, or on some other non-fulltime basis.
Comment: HCl CEMS. In general, commenters argued that HCl CEMS do not have an approved performance specification and are not widely demonstrated as a proven technology. That concern was also mentioned for HF CEMS.
Response: We disagree with commenters' contention that continuous HCl monitoring is premature or not available for the measurement at the limits set in the final standard. HCl CEMS are being used on source categories such as municipal waste combustors and EGUs. We have reviewed HCl CEMS vendor technology claims and found sufficient capability to support this rule requirement. We are engaged with representative stakeholders to develop a performance specification for HCl CEMS scheduled for completion in time to be responsive to compliance with this rule.
      The final rule provides several options for HCl and/or HF monitoring including:
      1) Using HCl CEMS and/or HF CEMS for compliance including CEMS complying with PS 15,
      2) Seeking approval for an alternative HCl monitoring procedure through 40 CFR 63.7(f),
      3) Monitoring SO2 continuously as a surrogate for acid gas HAP at facilities equipped with FGD technology for SO2, and
      4) Frequent reference method testing.
      Including these options in the final rule provides flexibility to adopt CEMS monitoring options as the technology continues to mature and the EPA performance specifications become available.
Comment: Bypass Stacks: Several commenters raised concerns about the technical feasibility of monitoring bypass stacks with a CEMS.
Response: We have modified the bypass stack monitoring requirements. Under 40 CFR Part 75, we allow the use of a maximum potential concentration value on a bypass stack. That approach works within the broad context of an emissions trading program, but does not work when evaluating compliance with a specific emission limit over a shorter period. Thus, we have provided two other options. One is to monitor the bypass stack, consistent with the proposed rule. The other is to treat any hours of bypass stack emissions as periods of monitor downtime. In general, this is consistent with our approach to startup, shutdown, and malfunction periods in that we treat those periods as subject to a work practice standard. That generally obviates the need to monitor the bypass stack as the emission limit does not apply during such periods when your source is likely to operate a bypass stack.
Comment: Part 75 Issues. There were a number of general comments about the value of generally relying on Part 75 requirements, including elements such as conditional data validation. The commenters generally agreed that the Part 75 bias test and bias adjustment factor, and the Part 75 substitute data provisions should not apply. Instead of substitute data, many commenters suggested that we needed to clarify the valid reasons for monitor downtime and establish an appropriate minimum data availability requirement.
Response: We have attempted to harmonize the CEMS requirements in this final rule with those under Part 75 where appropriate. One of those examples is the inclusion of conditional data validation for Hg CEMS. One area of departure is that this final rule needs a minimum data availability requirement. We have not included any specific minimum data availability requirement for CEMS or other monitoring in this final rule nor do we provide a specific tool for data substitution. We believe that there are other provisions in the final rule to provide incentives to conduct monitoring in a manner consistent with good air pollution control practices and to provide data sufficient to demonstrate compliance with a relatively long-term emissions rate limit (e.g., lb/MMBtu or lb/MWh). We agree that data quality certainty associated with any calculated value decreases with the collection of fewer data such as would occur with extended periods of monitoring system downtime. Even so, we believe also that it is necessary and critical to compliance with the regulation that a source uses all measured data collected during an averaging period to assess compliance regardless of any periods of missing data. Sources should not disqualify any data otherwise meeting required data quality requirements simply because there were data missing for other hours or days of the averaging period.
      Instead of a minimum data availability threshold that would invalidate data collected for some averaging periods because one did not collect data for at least x percent of an averaging time, the final rule requires that a source report as deviations to the rule failure to collect data during required periods and that are not covered by exceptions allowed in the final rule.
      On the issue of applying a data substitution procedure to represent actual emissions or pollution control performance, we believe that defensibility concerns make it incumbent on you to collect and evaluate other information in accordance with 40 CFR section 63.6(f)(3) during periods of monitoring downtime to assure compliance with the applicable emissions limitations and standards.
      We believe that enforcement authorities also can and should determine whether a source is meeting any monitoring system operating requirements. Should the source or the enforcement authority be concerned about the representativeness of data such as during periods of missing data, either may consider collecting information through other means (e.g., supplemental emissions testing) to fill data gaps not only because such gaps are deviations from the rule but such gaps can lead to uncertainty about compliance status.
      We further believe that the final rule provides sufficient means to ensure CMS performance and ongoing compliance without specifying an arbitrary numerical minimum data availability or data substitution requirement. We believe that specifying that failure to collect required or otherwise excepted data is a deviation from the rule will provide the necessary incentive to collect data sufficient to demonstrate compliance with the limits in the final rule.
Comment: Recordkeeping. Several commenters opposed the requirements related to maintaining records on site and for 5 years.
Response: We believe the record keeping and retention requirements are consistent with other requirements already in place, specifically 40 CFR Part 63.10 (b) "General recordkeeping requirements. (1) The owner or operator of an affected source subject to the provisions of this part shall maintain files of all information (including all reports and notifications) required by this part recorded in a form suitable and readily available for expeditious inspection and review. The files shall be retained for at least 5 years following the date of each occurrence, measurement, maintenance, corrective action, report, or record. At a minimum, the most recent 2 years of data shall be retained on site. The remaining 3 years of data may be retained off site. Such files may be maintained on microfilm, on a computer, on computer floppy disks, on magnetic tape disks, or on microfiche."
      In addition, the 5-year retention period is the general rule for all recordkeeping for all sources under the Part 70 operating permits program. Given that the general provisions for 40 CFR Part 63 and Part 70 already establish a 5-year retention period, we believe it is justified in using those precedents for the retention periods under this subpart. If we stayed silent on retention period in this subpart, the general provisions would provide for the 5-year retention as would the Part 70 requirements. Thus, this action does not establish any new retention requirements, but merely confirms that the existing retention requirements apply.
Comment: Electronic Reporting. In the proposed rule, we requested comment on using ECMPS for reporting under this rule, as well as other options including the ERT. Commenters generally supported the use of ECMPS, especially for CEMS data. Some commenters requested an additional rulemaking on the specific data elements to be collected. There were some concerns raised about the ERT given experience during the 2010 ICR process during the development of this rule.
Response: We recognize that emissions reporting for continuously measured pollutants (SO2, NOx, etc.) and for periodically measured pollutants (PM, HAP metals, etc.) have different data demands. We recognize that minor revisions of the ECMPS will fulfill our data needs for continuously measured pollutants and we will make these minor modifications for receipt of the additional data demands. We also recognize the need for substantial modifications to the ECMPS to accommodate the data needs for periodically measured pollutants. Although major modifications of the ECMPS would be required for periodic compliance tests by isokinetic and instrumental test methods, minor revisions are required of the ERT to receive these tests. We are implementing the changes in the ERT that are required to provide the software tools to implement the delivery of these performance test data to us.
      The electronic submission of compliance test reports to us through the Central Data Exchange (CDX) is not solely for the purpose of developing improved emissions factors as some commenters assert. Although populating WebFIRE will allow us to improve emissions factors, we intend to use data stored in WebFIRE as the primary location for compliance test reports for use by regulatory authorities. The electronic submission of compliance test reports is a continuation of our efforts to bring the submission and sharing of environmental data into the modern age. The storage of this compliance data in our WebFIRE provides a convenient location which is already used to store source test data.
      As our and state and local agencies data systems mature, information provided through the ERT will be used to populate these data systems. We are currently upgrading the AIRS Facility System and expect to replace manually entered information with electronic population from the ERT. We are also working with several state and local agencies to adopt the use of the ERT for delivery of compliance test reports. The ERT is also much improved since the version used during the 2010 ICR process, and there is no expectation that the information to be reported under this final rule will be as extensive as some of the data reported for the 2010 ICR purposes.
      We disagree that a separate and independent regulatory action is required to implement electronic reporting for selected regulated sources. Each of these regulatory actions for selected source categories provides ample notice and the opportunity for individuals to provide comment. We also disagree that the system to receive the compliance data must be operational prior to establishing the requirement for regulated sources to submit compliance data electronically. We are on track to have the capability to receive electronic compliance tests through our CDX in sufficient time to receive all utility source test reports required by this final rule.
      We do plan a separate and independent regulatory action to implement electronic reporting for regulated entities which are covered by past and future rules. Although we have provided draft procedures for the development of emissions factors, that effort is an ancillary effort to the electronic delivery of compliance test reports. It is our intention to convert to the electronic delivery and storage of all air emissions compliance source test data. With this transition, we believe this valuable information will be more readily available not only for compliance purposes but also for a variety of other uses.
 VIII. Background Information on the NSPS
 A. What is the statutory authority for this final NSPS?

      New source performance standards implement CAA section 111(b), and are issued for categories of sources which cause, or contribute significantly to, air pollution which may reasonably be anticipated to endanger public health or welfare. Section 111 of the CAA requires that NSPS reflect the application of the best system of emissions reductions which (taking into consideration the cost of achieving such emissions reductions, any non-air quality health and environmental impact and energy requirements) the Administrator determines has been adequately demonstrated. This level of control is commonly referred to as best demonstrated technology (BDT). Section 111(b)(1)(B) of the CAA requires EPA to periodically review and revise the standards of performance, as necessary, to reflect improvements in methods for reducing emissions.
B. What is the regulatory authority for the final rule?
      The current standards for steam generating units are contained in the NSPS for EGUs (40 CFR Part 60, subpart Da), industrial-commercial institutional steam generating units (40 CFR Part 60, subpart Db), and small industrial-commercial-institutional steam generating units (40 CFR Part 60, subpart Dc). The NSPS for EGUs (40 CFR Part 60, subpart Da) were originally promulgated on June 11, 1979 (44 FR 33580) and apply to units capable of firing more than 73 megawatts (MW) (250 MMBtu/h) heat input of fossil fuel that commenced construction, reconstruction, or modification after September 18, 1978. The NSPS also apply to industrial-commercial-institutional cogeneration units that sell more than 25 MW and more than one-third of their potential output capacity to any utility power distribution system. The most recent significant amendments to emission standards under 40 CFR Part 60, subpart Da, were promulgated in 2006 (71 FR 9866) resulting in new PM, SO2, and NOX limitations for 40 CFR Part 60, subpart Da, units. The NSPS for industrial-commercial-institutional steam generating units (40 CFR part 60, subpart Db) apply to units for which construction, modification, or reconstruction commenced after June 19, 1984, that have a heat input capacity greater than 29 MW (100 MMBtu/h). Those standards were originally promulgated on November 25, 1986 (51 FR 42768) and also have been amended since the original promulgation to reflect changes in BDT for these sources. The NSPS for small industrial-commercial-institutional steam generating units (40 CFR Part 60, subpart Dc) were originally promulgated on September 12, 1990, (55 FR 37674) and apply to units with a maximum heat input capacity greater than or equal to 2.9 MW (10 MMBtu/h) but less than 29 MW (100 MMBtu/h). Those standards apply to units that commenced construction, reconstruction, or modification after June 9, 1989.
IX. Summary of this Final NSPS
      The final rule amends the emission standards for SO2, NOX, and PM for 40 CFR Part 60, subpart Da. Only those units that begin construction, modification, or reconstruction after May 3, 2011, will be affected by the final rule. Compliance with the emission limits of the final rule will be determined using similar testing, monitoring, and other compliance provisions set forth in the existing standards. In addition to the emissions limits contained in the final rule, we also are including several technical clarifications and corrections to existing provisions of the subparts.
A. What are the requirements for new EGUs (40 CFR Part 60, subpart Da)?
      The filterable PM emissions standard for new and reconstructed EGUs is 11 nanograms per joule (ng/J) (0.090 pound per megawatt hour (lb/MWh)) gross energy output regardless of the type of fuel burned. The PM emissions standard for modified EGUs is unchanged from the existing requirements of 6.4 ng/J (0.015 lb/MMBtu) heat input or 99.8 percent reduction regardless of the type of fuel burned. Compliance with this emission limit can be determined using similar testing, monitoring, and other compliance provisions for PM standards set forth in the existing rule. While not required, PM CEMS may be used as an alternative method to demonstrate continuous compliance and as an alternative to opacity and parameter monitoring requirements.
      The SO2 emission limit for new and reconstructed EGUs is 130 ng/J (1.0 lb/MWh) gross energy output or 97 percent reduction regardless of the type of fuel burned with one exception. The SO2 emission limit for new and reconstructed EGUs that burn over 75 percent coal refuse (by heat input) on an annual basis is 180 ng/J (1.4 lb/MWh) gross energy output or 94 percent reduction. The SO2 emission limit for modified EGUs burning any fuel is 180 ng/J (1.4 lb/MWh) gross energy output or 90 percent reduction with one exception. The SOs emission limit for modified EGUs that burn over 75 percent coal refuse (by heat input) on an annual basis is 190 ng/J (1.5 lb/MWh) gross energy output or 90 percent reduction. Compliance with the SO2 emission limit is determined on a 30-day rolling average basis using a CEMS to measure SO2 emissions and following the compliance provisions in the proposed rule.
      The NOX emission limit for new and reconstructed EGUs is 88 ng/J (0.70 lb/MWh) gross energy output regardless of the type of fuel burned with one exception. The NOX emission limit for new and reconstructed EGUs that burn over 75 percent coal refuse (by heat input) is 110 ng/J (0.85 lb/MWh) gross energy output. The NOX limit for modified EGUs is 140 ng/J (1.1 lb/MWh) gross energy output regardless of the type of fuel burned in the unit. Compliance with this emission limit is determined on a 30-day rolling average basis using similar testing, monitoring, and other compliance provisions in the proposed rule.
      As an alternate to the NOX standard, owners/operators of new and reconstructed EGUs may elect to comply with a combined NOX/CO standard of 140 ng/J (1.1 lb/MWh) with one exception. The NOX/CO emission limit for new and reconstructed EGUs that burn over 75 percent coal refuse (by heat input) on an annual basis is 160 ng/J (1.3 lb/MWh) gross energy output. Finally, owners/operators of modified EGUs may elect to comply with a combined NOX/CO standard of 190 ng/J (1.5 lb/MWh).
B. Additional Amendments
      See the Response to Comments document.
X. Summary of Significant Changes Since Proposal
 A. Emission Limits
      The proposal included a combined (filterable plus condensable) PM standard. The final standard is based only on filterable PM. No standard is being established for condensable PM.
      The proposal included requested comment on if the final standard should include a standalone NOX standard or a combined NOX/CO standard. The final standard includes a standalone NOX standard and an optional, but not required, combined NOX/CO standard as an alternative to the amended NOX standard. Similarly, the proposal included a request for comment on if the standard should be based on gross or net output. The final standards are based on an amended definition of gross output with an optional net output based standard.
      The proposal included alternate emission standards for commercial demonstration projects. Proposed commercial demonstrations included pressurized fluidized beds, multi-pollutant control technologies, and advanced combustion controls. The final rule includes the commercial demonstration permit exemption for pressurized fluidized beds and multi-pollutant control technologies, but not advanced combustion controls.
B. Requirements during Startup, Shutdown, and Malfunction
      For startup and shutdown, the requirements for PM have changed since proposal. For periods of startup and shutdown, the EPA is finalizing work practice standards, which require following manufacturers specifications for minimizing periods of startup and shutdown, in lieu of numeric emission limits. For malfunctions, the EPA is finalizing affirmative defense language to this final rule for exceedances of the numerical emission limits that are caused by malfunctions.
XI. Public Comments and Responses to the Proposed NSPS
      See the Response to Comments document.
XII. Impacts of These Final Rules
 A. What are the air impacts?
       The EPA anticipates significant emission reductions under the final rule from coal-fired EGUs, which are of particular interested due to their share of total power sector emissions. In 2015, annual HCl emissions are projected to be reduced by 88 percent, Hg emissions reduced by 68 percent, and PM2.5 emissions reduced by 20 percent from coal-fired EGUs greater than 25 MW. In addition, the EPA projects SO2 emission reductions of 41 percent, and annual CO2 reductions of 1 percent from coal-fired generation greater than 25 MW by 2015, relative to the base case. See Table 7.
 TABLE 7. SUMMARY OF EMISSIONS REDUCTIONS FROM COAL-FIRED EGUS GREATER THAN 25 MW (TPY)

                              SO2
(million tons)
                              NOX
(million tons)
                                Mercury
(tons)
                              HCl
(thousand tons)
                             PM2.5
(thousand tons)
                          CO2 (million metric tonnes)
Base Case
                                      3.3
                                      1.7
                                      27
                                      45
                                      270
                                     1,906
MATS
                                      1.9
                                      1.7
                                       8
                                       6
                                      215
                                     1,881
Change
                                     -1.4
                                      0.0
                                      -18
                                      -40
                                      -54
                                      -25

 Note: Numbers may not add due to rounding.
       The reductions in this table do not account for reductions in other HAP which will occur as a result of this rule. For instance, the fine particulate reductions presented above only partly reflect reductions in many heavy metal particulates, and the HCl reductions above only partly reflect reductions of all acid gasses. This rule will also result in additional HAP reductions from oil-fired EGUs, which are covered by the rule but are not included in the EPA's analysis of emissions reductions.
  B. What are the energy impacts?
      Under the provisions of this proposed rule, the EPA projects that approximately 5.5 GW of coal-fired generation (less than 2 percent of all coal-fired capacity and 0.5 percent of total generation capacity in 2015) may be uneconomic to maintain and removed from operation by 2015. These units are predominantly smaller and less frequently used generating units dispersed throughout the country. If current forecasts of either natural gas prices or electricity demand were revised in the future to be higher, that would create a greater incentive to make further investments in these facilities and keep these units operational.
       There are other important energy market implications of the final rule. Average nationwide retail electricity prices are projected to increase in the continental U.S. by 3 percent in 2015. The average delivered coal price increases by less than 2 percent in 2015 as a result of shifts within and across coal types. The EPA also projects that electric power sector-delivered natural gas prices will increase by about 0.7 percent over the 2015 to 2030 timeframe, on average, and that natural gas use for electricity generation will increase by less than 200 billion cubic feet (BCF) in 2015. These impacts are well within the range of price variability that is regularly experienced in natural gas markets. Finally, the EPA projects coal production for use by the power sector, a large component of total coal production, will decrease by 11 million tons in 2015 from base case levels, which is about 1 percent of total coal produced for the electric power sector in that year.
 C. What are the cost impacts?
       The power industry's "compliance costs" are represented in this analysis as the change in electric power generation costs between the base case and policy case in which the sector pursues pollution control approaches to meet the MATS emission standards. In simple terms, these costs are the resource costs of what the power industry will directly expend to comply with the EPA's requirements.
       The EPA projects that the annual incremental compliance cost of MATS is $9.2 billion in 2015 ($2007). The annualized incremental cost is the projected additional cost of complying with the rule in the year analyzed, and includes the amortized cost of capital investment and the ongoing costs of operating additional pollution controls, needed new capacity, shifts between or amongst various fuels, and other actions associated with compliance.
 D. What are the economic impacts?
       For this final rule, EPA analyzed the costs using IPM. IPM is a dynamic linear programming model that can be used to examine the economic impacts of air pollution control policies for a variety of HAP and other pollutants throughout the contiguous U.S. for the entire power system.
       Documentation for IPM can be found in the docket for this rulemaking or at http://www.epa.gov/airmarkets/progsregs/epa-ipm/index.html.
 1. EPA performed a screening analysis for impacts on small entities by comparing compliance costs to sales/revenues (e.g., sales and revenue tests). EPA's analysis can be found in Chapter 7 of the RIA for this rule. EPA has also prepared a Final Regulatory Flexibility Analysis (FRFA) that discusses that discusses alternative regulatory or policy options that minimize the rule's small entity impacts.
 2. Although a stand-alone analysis of employment impacts is not included in a standard cost-benefit analysis, the current economic climate has led to heightened concerns about potential job impacts. Such an analysis is of particular concern in the current economic climate as sustained periods of excess unemployment may introduce a wedge between observed (market) wages and the social cost of labor. In such conditions, the opportunity cost of labor required by regulated sectors to bring their facilities into compliance with an environmental regulation may be lower than it would be during a period of full employment (particularly if regulated industries employ otherwise idled labor to design, fabricate, or install the pollution control equipment required under this final rule). For that reason, EPA also includes estimates of job impacts associated with the final rule, where possible. EPA presents an estimate of short-term employment opportunities as a result of increased demand for pollution control equipment. Overall, the results suggest that the final rule could support a net of roughly 47,000 job years in direct employment impacts in 2015.
 3. The basic approach to estimate these employment impacts involved using projections from IPM from the final rule analysis, in particular the amount of existing coal-fired capacity that is projected to be retrofit with pollution control technologies. This data, along with data on labor and resource needs of new pollution controls and labor productivity from engineering studies and secondary sources, is used to estimate employment impacts for the pollution control industry in 2015. For more information, please refer to the Chapter 6 and appendix 6B the RIA for this analysis.
 4. The EPA relied to Morgenstern, et al. (2002), identify three economic mechanisms by which pollution abatement activities can indirectly influence jobs:
      higher production costs raise market prices, higher prices reduce consumption, and employment within an industry falls ("demand effect");
      pollution abatement activities require additional labor services to produce the same level of output ("cost effect"); and
      post regulation production technologies may be more or less labor intensive (i.e., more/less labor is required per dollar of output) ("factor-shift effect").
      Using plant-level Census information between the years 1979 and 1991, Morgenstern, et al., estimate the size of each effect for four polluting and regulated industries (petroleum, plastic material, pulp and paper, and steel). On average across the four industries, each additional $1 million spending on pollution abatement results in an small net increase of 1.6 jobs; the estimated effect is not statistically significant different from zero. As a result, the authors conclude that increases in pollution abatement expenditures do not necessarily cause economically significant employment changes. The conclusion is similar to Berman and Bui (2001) who found that increased air quality regulation in Los Angeles did not cause large employment changes.  For more information, please refer to the RIA for this final rule.
      The ranges of job effects calculated using the Morgenstern, et al., approach are listed in Table 8.
TABLE 8. RANGE OF JOB EFFECTS FOR THE ELECTRICITY SECTOR

                  Estimates using Morgenstern, et al. (2001)

                                 Demand Effect
                                  Cost Effect
                              Factor Shift Effect
                                     Net
                                    Effect
Change in Full-Time Jobs per Million Dollars of Environmental Expenditure[a]
                                    −3.56
                                     2.42
                                     2.68
                                     1.55
Standard Error
                                     2.03
                                     0.83
                                     1.35
                                     2.24
EPA estimate for Final Rule[b]
                              -38,000 to +2,100
                               +4,000 to +20,000
                                +200 to +27,000
                              -14,000 to +30,000
[a] Expressed in 1987 dollars. See footnote a from Table 6-3 of the RIA for inflation adjustment factor used in the analysis.
[b] According to the 2007 Economic Census, the electric power generation, transmission and distribution sector (NAICS 2211) had approximately 510,000 paid employees.

      The EPA recognizes there may be other job effects which are not considered in the Morgenstern, et al., study. Although EPA has considered some economy-wide changes in industry output as shown earlier with the Multi-Market model, we do not have sufficient information to quantify other associated job effects associated with this rule. The EPA solicits comments on information (e.g., peer-reviewed journal articles) and data to assess job effects that may be attributable to this rule.
E. What are the benefits of this final rule?
1. Benefits of Reducing HAP Emissions
a. Human Health and Environmental Effects Due to Exposure to MeHg. In this section, we provide a qualitative description of human health and environmental effects due to exposure to MeHg. In 2000, the NAS Study was issued which provides a thorough review of the effects of MeHg on human health (NRC, 2000). Many of the peer-reviewed articles cited in this section are publications originally cited in the MeHg Study. In addition, the EPA has conducted literature searches to obtain other related and more recent publications to complement the material summarized by the NRC in 2000.
b. Neurologic Effects of Exposure to MeHg. In its review of the literature, the NAS found neurodevelopmental effects to be the most sensitive and best documented endpoints and appropriate for establishing an RfD (NRC, 2000); in particular NAS supported the use of results from neurobehavioral or neuropsychological tests. The NAS report (NRC, 2000) noted that studies in animals reported sensory effects as well as effects on brain development and memory functions and support the conclusions based on epidemiology studies. The NAS noted that their recommended endpoints for an RfD are associated with the ability of children to learn and to succeed in school. They concluded the following: "The population at highest risk is the children of women who consumed large amounts of fish and seafood during pregnancy. The committee concludes that the risk to that population is likely to be sufficient to result in an increase in the number of children who have to struggle to keep up in school."
c. Cardiovascular Impacts of Exposure to MeHg. The NAS summarized data on cardiovascular effects available up to 2000. Based on these and other studies, the NRC (2000) concluded that "Although the data base is not as extensive for cardiovascular effects as it is for other end points (i.e. neurologic effects) the cardiovascular system appears to be a target for MeHg toxicity in humans and animals." The NRC also stated that "additional studies are needed to better characterize the effect of MeHg exposure on blood pressure and cardiovascular function at various stages of life."
      Additional cardiovascular studies have been published since 2000. The EPA did not to develop a quantitative dose-response assessment for cardiovascular effects associated with MeHg exposures, as there is no consensus among scientists on the dose-response functions for these effects. In addition, there is inconsistency among available studies as to the association between MeHg exposure and various cardiovascular system effects. The pharmacokinetics of some of the exposure measures (such as toenail Hg levels) are not well understood. The studies have not yet received the review and scrutiny of the more well-established neurotoxicity data base.
d. Genotoxic Effects of Exposure to MeHg. The Mercury Study noted that MeHg is not a potent mutagen but is capable of causing chromosomal damage in a number of experimental systems. The NAS concluded that evidence that human exposure to MeHg caused genetic damage is inconclusive; they note that some earlier studies showing chromosomal damage in lymphocytes may not have controlled sufficiently for potential confounders. One study of adults living in the Tapajós River region in Brazil (Amorim et al., 2000) reported a direct relationship between MeHg concentration in hair and DNA damage in lymphocytes; as well as effects on chromosomes. Long-term MeHg exposures in this population were believed to occur through consumption of fish, suggesting that genotoxic effects (largely chromosomal aberrations) may result from dietary, chronic MeHg exposures similar to and above those seen in the Faroes and Seychelles populations.
e. Immunotoxic Effects to Exposure to MeHg. Although exposure to some forms of Hg can result in a decrease in immune activity or an autoimmune response (ATSDR, 1999), evidence for immunotoxic effects of MeHg is limited (NRC, 2000).
f. Other Hg-Related Human Toxicity Data. Based on limited human and animal data, MeHg is classified as a "possible" human carcinogen by the International Agency for Research on Cancer (IARC, 1994) and in IRIS (USEPA, 2002).The existing evidence supporting the possibility of carcinogenic effects in humans from low-dose chronic exposures is tenuous. Multiple human epidemiological studies have found no significant association between Hg exposure and overall cancer incidence, although a few studies have shown an association between Hg exposure and specific types of cancer incidence (e.g., acute leukemia and liver cancer) (NAS, 2000).
      There is also some evidence of reproductive and renal toxicity in humans from MeHg exposure. However, overall, human data regarding reproductive, renal, and hematological toxicity from MeHg are very limited and are based on either studies of the two high-dose poisoning episodes in Iraq and Japan or animal data, rather than epidemiological studies of chronic exposures at the levels of interest in this analysis.
g. Ecological Effects of Hg. Deposition of Hg to watersheds can also have an impact on ecosystems and wildlife. Mercury contamination is present in all environmental media with aquatic systems experiencing the greatest exposures due to bioaccumulation. Bioaccumulation refers to the net uptake of a contaminant from all possible pathways and includes the accumulation that may occur by direct exposure to contaminated media as well as uptake from food.
      A review of the literature on effects of Hg on fish reports results for numerous species including trout, bass (large and smallmouth), northern pike, carp, walleye, salmon, and others from laboratory and field studies. The effects of MeHg in fish are reproductive in nature. Although we cannot determine at this time whether these reproductive deficits are affecting fish populations across the U.S. it should be noted that it would seem reasonable that over time reproductive deficits would have an effect on populations.
      Mercury also affects avian species. In previous reports much of the focus has been on large piscivorous species in particular the common loon. Significant adverse effects on breeding loons from Hg have been found to occur including behavioral (reduced nest-sitting), physiological (flight feather asymmetry) and reproductive (chicks fledged/territorial pair) effects and reduced survival. Additionally, Evers, et al. (see footnote 5), report that they believe that the weight of evidence indicates that population-level effects occur in parts of Maine and New Hampshire, and potentially in broad areas of the loon's range.
      Recently attention has turned to other piscivorous species such as the white ibis, and great snowy egret. These wading birds have a very wide diet including crayfish, crabs, snails, insects and frogs. The white ibis has been observed to have decreased foraging efficiency and have been shown to exhibit decreased reproductive success and altered pair behavior. In egrets, Hg has been implicated in the decline of the species in south Florida and Hoffman has shown that egrets show liver and possibly kidney effects. Although ibises and egrets are most abundant in coastal areas and these studies were conducted in south Florida and Nevada the ranges of ibises and egrets extend to a large portion of the U.S.
      Insectivorous birds have also been shown to suffer adverse effects due to Hg exposure. These songbirds such as Bicknell's thrush, tree swallows, and the great tit have shown reduced reproduction, survival, and changes in singing behavior. Exposed tree swallows produced fewer fledglings, lower survival, and had compromised immune competence. The great tit has exhibited reduced singing behavior and smaller song repertoire in areas of high contamination.
      In mammals adverse effects have been observed in mink and river otter, both fish eating species. For otter from Maine and Vermont, maximum concentrations on Hg in fur nearly equal or exceed a concentration associated with mortality and concentration in liver for mink in Massachusetts/Connecticut and the levels in fur from mink in Maine exceed concentrations associated with acute mortality. Adverse sublethal effects may be associated with lower Hg concentrations and consequently be more widespread than potential acute effects. These effects may include increased activity, poorer maze performance, abnormal startle reflex, and impaired escape and avoidance behavior.
h. Methodology for Hg Benefits Estimation. The EPA has conducted a national-scale analysis the benefits to recreational anglers of avoided IQ loss that reductions of Hg emissions and subsequent deposition required by this rule will achieve. Because the primary measurable health effect of concern  --  developmental neurological abnormalities in children  --  occurs as a result of in-utero exposures to Hg, the specific population of interest in this case is prenatally exposed children. To identify and estimate the size of this exposed population, the benefits analysis focused on pregnant women in freshwater recreational angler households. Estimating Hg exposures for this exposure pathway and population of interest requires three main components: 1) the size of the exposed population of interest (annual number of pregnant women in freshwater angler households during the year), 2) the average concentration of MeHg in noncommercial freshwater fish filets consumed, and 3) the average daily consumption rate of noncommercial freshwater fish. The Hg concentrations of fish in the waterbodies where the fish are caught are modeled using Mercury MAPS to project the decline in concentrations due to the rule. To approximate the percentage freshwater fishing trips (and exposed individuals) from each census tract matched to each waterbody type, the EPA used state-level averages. These averages were calculated for each state, based on the portion of residents' freshwater fishing trips that are to each waterbody type, based on 2001 FHWAR data.
      Data from NSRE 1994 were used to approximate the percentage of freshwater fishing trips (and exposed individuals) matched to different distances from anglers' residential location.
      To determine an appropriate daily fish consumption rate for the analysis, the EPA conducted an extensive review of existing literature characterizing self-caught freshwater fish consumption. Based on this review, it was decided that the ingestion rates for recreational freshwater fishers, specified as "recommended" in the EPA's "Environmental Exposure Factors Handbook" (EPA, 1997), represented the most appropriate values to use in this analysis.
      Estimating the IQ decrements in children that result from mothers' ingestion of Hg required two steps. First, based on the estimated average daily maternal ingestion rate, the expected Hg concentration in the hair of exposed pregnant women was estimated. Second, to estimate the expected IQ decrement in offspring resulting from in-utero exposure to Hg through mothers' fish consumption, the following dose-response relationship based on the summary findings reported in Axelrad et al. (2007).
      The valuation approach used to assess monetary losses due to IQ decrements is based on an approach applied in previous EPA analyses (EPA, 2008). The approach expresses the loss to an affected individual resulting from IQ decrements in terms of foregone future earnings (net of changes in education costs) for that individual.
      The estimate for Present Value of Lifetime Earnings is derived using earnings and labor force participation rate data from the 2006 Current Population Survey. Estimates of the average effect of a 1-point increase in IQ on lifetime earnings range from a 1.76 percent increase (Schwartz, 1994) to a 2.379 percent increase (Salkever, 1995). The percentage increases in the two studies reflect both the direct impact of IQ on hourly wages and indirect effects on annual earnings as the result of additional schooling and increased labor force participation. The estimate for years of additional schooling is based on Schwartz (1994) who reports an increase of 0.131 years of schooling per IQ point.
      In addition to this positive net effect on earnings, an increase in IQ is also assumed to have a positive effect on the amount of time spent in school and on associated costs. To incorporate (1) uncertainty regarding the size of the percentage change in future earnings and (2) different assumptions regarding the discount rate, the resulting value estimates for the average net loss per IQ point decrement are expressed as a range. Assuming a 3 percent discount rate, value IQ ranges from $8,013 (using the Schwartz estimates) to $11,859 (using the Salkever estimates). With a 7 percent discount rate assumption, the value IQ estimates range from $893 to $1,958.
      The EPA analyzed the aggregate national IQ and present-value loss estimates for two base case and three emission control scenarios. The highest losses are estimated for the 2005 base case. For the population of prenatally exposed children included in the analysis (almost 240,000), Hg exposures under baseline conditions during the year 2005 are estimated to have resulted in more than 25,500 IQ points lost. Assuming a 3 percent discount rate, the present value of these losses ranges from $204.8 million to $292.5 million. These losses represent expected present value of declines in future net earnings over the entire lifetimes of the children who are prenatally exposed during the year 2005. With a 7 percent discount rate, the present value range is considerably lower: $22.8 million to $50.0 million.
      For the five emission reduction scenarios, the EPA generated estimates of aggregate nationwide benefits associated with reductions in Hg exposures and resulting reductions in IQ losses. Most importantly, the benefits of the 2016 Toxics Rule scenario (relative to the 2016 base case) are estimated to range between $4 million and $6 million (assuming a 3 percent discount rate), because of an estimated 511 point reduction in IQ losses.
2. Health and Welfare Co-Benefits
      Emission controls installed to meet the requirements of this rule will generate co-benefits by reducing criteria pollutants including PM2.5, ozone, NOX, and SO2, as well as CO2. For this rule, we were only able to estimate the mortality benefits of PM2.5 reductions due to changes in emissions of SO2 and direct PM2.5 and climate benefits resulting from CO2 reductions. Additional co-benefits are expected to result from decreases in PM2.5 morbidity impacts, decreases in nitrogen and sulfur deposition, and improvements in visibility in national parks and wilderness areas. Total co-benefits are thus expected to be higher than the partial estimates of co-benefits provided here. We estimate the monetized health and climate co-benefits of this rule in 2016 at a 3 percent discount rate are $37 billion to $91 billion or $33 billion to $82 billion at a 7 percent discount rate (2007$), given uncertainty about the relationship between PM2.5 concentration and health effects. Using alternate relationships between PM2.5 and premature mortality supplied by experts, higher and lower health co-benefits estimates are plausible, but most of the expert-based estimates fall between these two estimates.
a. Human Health Co-Benefits. To estimate the human health co-benefits of this rule, the EPA used benefit-per-ton factors to quantify the changes in PM2.5-related health impacts and monetized benefits based on changes in SO2 and direct PM2.5 emissions. These benefit-per-ton factors were based on an interim baseline and policy scenario for which full-scale ambient air quality modeling and air quality based human health benefits assessments were performed. This general approach and methodology is laid out in Fann, et al. (2009), but here the air quality modeling used a better spatial representation of the emission changes from EGUs. For more details on the creation of the benefit-per-ton factors and their application to emission reductions under this rule, please refer to the RIA for this rule in the docket.
      Table 9 presents the estimates of reduced annual incidences of PM2.5-related health effects in 2016 resulting from this rule. Table 10 presents the estimated annual monetary value of reduced incidence of quantified health endpoints in 2016 resulting from this rule.
      The reduction in premature fatalities each year accounts for between 93 and 97 percent of the monetized health co-benefits.
TABLE 9. ESTIMATED REDUCTIONS IN INCIDENCES OF PM2.5-RELATED HEALTH EFFECTS IN 2016[a]

                                 Health Effect
                            Number of Reduced Cases
Adult Premature Mortality

Pope et al. (2002) (age >30)
                                     4,300
                               (1,200 to 7,300)

Laden et al. (2006) (age >25)
                                    11,000
                               (5,000 to 17,000)

Infant Premature Mortality
(< 1 year)
                                      20
                                  (-22 to 62)

Chronic Bronchitis
                                     2,900
                                 (88 to 5,600)

Non-fatal heart attacks
(age > 18)
                                     4,800
                                (710 to 5,000)

Hospital admissions -- respiratory
(all ages)
                                      840
                                (330 to 1,300)

Hospital admissions -- cardiovascular
(age > 18)
                                     1,800
                               (1,300 to 2,200)

Emergency room visits for asthma
(age < 18)
                                     3,200
                               (1,600 to 4,700)

Acute bronchitis
(age 8-12)
                                     6,300
                              (-1,400 to 14,000)

Lower respiratory symptoms
(age 7-14)
                                    81,000
                              (31,000 to 130,000)

Upper respiratory symptoms
(asthmatics age 9-11)
                                    61,000
                              (11,000 to 110,000)

Asthma exacerbation
(asthmatics 6-18)
                                    130,000
                              (4,500 to 450,000)

Lost work days
(ages 18-65)
                                    550,000
                             (460,000 to 630,000)

Minor restricted-activity days
(ages 18-65)
                                   3,200,000
                           (2,600,000 to 3,800,000)

[a] Values rounded to two significant figures. Co-benefits from reducing exposure to ozone, other criteria pollutants, and HAP, as well as reducing visibility impairment and ecosystem effects are not included here.

TABLE 10. ESTIMATED MONETARY VALUE (BILLIONS 2007$) OF PM2.5-RELATED HEALTH BENEFITS IN 2016[a]

                                 Health Effect
                              Monetized Benefits
Adult Premature Mortality

Pope, et al. (2002) (age >30)

3% discount rate
                                      $34
                                ($2.7 to $100)

7% discount rate
                                      $31
                                 ($2.4 to $93)

Laden, et al. (2006) (age >25)

3% discount rate
                                      $88
                                ($7.6 to $250)

7% discount rate
                                      $79
                                ($6.8 to $230)
Infant Premature Mortality
(< 1 year)
                                     $0.2
                                ($-0.2 to $0.8)
Chronic Bronchitis
                                     $1.4
                                ($0.1 to $6.4)
Non-fatal heart attacks (age >18)

3% discount rate
                                     $0.5
                                ($0.1 to $1.3)

7% discount rate
                                     $0.4
                                ($0.1 to $1.0)
Hospital admissions -- respiratory (all ages)
                                     $0.01
                               ($0.01 to $0.02)
Hospital admissions -- cardiovascular (age > 18)
                                     $0.03
                             (<$0.01 to $0.05)
Emergency room visits for asthma
(age < 18)
                                   <$0.01
Acute bronchitis (age 8-12)
                                   <$0.01
Lower respiratory symptoms
(age 7-14)
                                   <$0.01
Upper respiratory symptoms (asthmatics age 9-11)
                                   <$0.01
Asthma exacerbation
(asthmatics 6-18)
                                   <$0.01
Lost work days (ages 18-65)
                                     $0.1
                                ($0.1 to $0.2)
Minor restricted-activity days (ages 18-65)
                                     $0.2
                                ($0.1 to $0.3)
Monetized Health Co-Benefits

Pope, et al. (2002)

3% discount rate
                                      $37
                                 ($2.8 - $110)

7% discount rate
                                      $33
                                 ($2.5 - $100)

Laden, et al. (2006)

3% discount rate
                                      $90
                                 ($7.7 - $260)

7% discount rate
                                      $81
                                 ($7.0 - $240)
a Values rounded to two significant figures. Co-benefits from reducing exposure to ozone, other criteria pollutants, and HAP, as well as reducing visibility impairment and ecosystem effects are not included here.

      It is important to note that the magnitude of the PM2.5 co-benefits is largely driven by the concentration response function for premature mortality. Experts have advised the EPA to consider a variety of assumptions, including estimates based both on empirical (epidemiological) studies and judgments elicited from scientific experts, to characterize the uncertainty in the relationship between PM2.5 concentrations and premature mortality. For this rule we cite two key empirical studies, one based on the American Cancer Society cohort study and the other based on the extended Six Cities cohort study. The analyses upon which this rule is based were selected from the peer-reviewed scientific literature. We used up-to-date assessment tools, and we believe the results are highly useful in assessing this rule.
      These models assume that all fine particles, regardless of their chemical composition, are equally potent in causing premature mortality because the scientific evidence is not yet sufficient to allow differentiation of effects estimates by particle type. Even though we assume that all fine particles have equivalent health effects, the benefit-per-ton estimates vary between precursors because each ton of precursor reduced has a different propensity to form PM2.5.
      Every benefit analysis examining the potential effects of a change in environmental protection requirements is limited to some extent by data gaps, model capabilities (such as geographic coverage), and uncertainties in the underlying scientific and economic studies used to configure the benefit and cost models. Gaps in the scientific literature often result in the inability to estimate quantitative changes in health and environmental effects, or to assign economic values even to those health and environmental outcomes that can be quantified. The uncertainties in the underlying scientific and economics literatures (that may result in overestimation or underestimation of the co-benefits) are discussed in detail in the RIA. Despite these uncertainties, we believe the benefit analysis provides a reasonable indication of the expected health co-benefits of the rulemaking in future years under a set of reasonable assumptions.
      When characterizing uncertainty in the PM-mortality relationship, the EPA has historically presented a sensitivity analysis applying alternate assumed thresholds in the PM concentration-response relationship. In its synthesis of the current state of the PM science, the EPA's 2009 Integrated Science Assessment for Particulate Matter concluded that a no-threshold log-linear model most adequately portrays the PM-mortality concentration-response relationship.
      In the RIA accompanying this rulemaking, rather than segmenting out impacts predicted to be associated levels above and below a "bright line" threshold, the EPA includes a "lowest measured level" (LML) analysis that illustrates the increasing uncertainty that characterizes exposure attributed to levels of PM2.5 below the LML of each epidemiological study used to estimate PM2.5-related premature death. Figures provided in the RIA show the distribution of baseline exposure to PM2.5, as well as the lowest air quality levels measured in each of the epidemiology cohort studies. This information provides a context for considering the likely portion of PM-related mortality benefits occurring above or below the LML of each study; in general, our confidence in the size of the estimated reduction PM2.5-related premature mortality diminishes as baseline concentrations of PM2.5 are lowered.
      Based on the modeled interim baseline which is approximately equivalent to the final baseline (see Appendix A of the RIA), 11 percent and 73 percent of the estimated avoided mortality impacts occur at or above an annual mean PM2.5 level of 10 ug/m3 (the LML of the Laden et al. 2006 study) 7.5 ug/m3 (the LML of the Pope, et al., 2002 study), respectively. Although the LML analysis provides some insight into the level of uncertainty in the estimated PM mortality benefits, the EPA does not view the LML as a threshold and continues to quantify PM-related mortality impacts using a full range of modeled air quality concentrations.
      It is important to note that the monetized benefits include many but not all health effects associated with PM2.5 exposure. Benefits are shown as a range from Pope, et al. (2002), to Laden, et al. (2006). These models assume that all fine particles, regardless of their chemical composition, are equally potent in causing premature mortality because there is no clear scientific evidence that would support the development of differential effects estimates by particle type.
      It should be emphasized that the monetized co-benefits estimates provided above do not include benefits from several important benefit categories, including exposure to other air pollutants, ecosystem effects, and visibility impairment.
b. Non-Climate Welfare Co-Benefits. Emission controls installed to meet this rule will also generate co-benefits by improving visibility. We anticipate that improvements in visibility in Class I areas as well as residential areas where people live, work, and recreate could be substantial. Because full-scale air quality modeling was not performed for this rule, we are unable to quantify these visibility co-benefits for this rule. However, the estimated value of visibility benefits calculated from the modeled interim baseline and policy scenario was $1.1 billion (in 2007$). Since the distribution of emission reductions did not change substantially in the visibility regions studied, visibility benefits of the final policy scenario are likely to be of a similar magnitude.
      Ecosystem and other welfare effects include reduced acidification and, in the case of NOX, eutrophication of water bodies; possible reduced nitrate contamination of drinking water; ozone vegetation damage; the role of sulfate in Hg methylation; and reduced acid and particulate deposition that causes damages to cultural monuments, as well as, soiling and other materials damage. To illustrate the important nature of benefit categories the EPA is currently unable to monetize, we discuss four categories of public welfare and environmental impacts related to reductions in emissions required by this rule in the RIA.
c. Climate co-benefits. This rule is expected to reduce CO2 emissions from the electricity sector. The EPA has assigned a dollar value to reductions in CO2 emissions using recent estimates of the "social cost of carbon" (SCC). The SCC is an estimate of the monetized damages associated with an incremental increase in carbon emissions in a given year or the per metric ton benefit estimate relating to decreases in CO2 emissions. It is intended to include (but is not limited to) changes in net agricultural productivity, human health, property damages from increased flood risk, and the value of ecosystem services due to climate change.
      The SCC estimates used in this analysis were developed through an interagency process that included the EPA and other executive branch entities, and concluded in February 2010. We first used these SCC estimates in the benefits analysis for the final joint EPA/DOT Rulemaking to establish Light-Duty Vehicle Greenhouse Gas Emission Standards and Corporate Average Fuel Economy Standards; see the rule's preamble for discussion about application of the SCC (75 FR 25324; 5/7/10). The SCC Technical Support Document (SCC TSD) provides a complete discussion of the methods used to develop these SCC estimates.
      The interagency group selected four SCC values for use in regulatory analyses, which we have applied in this analysis: $5.9, $24.3, $39, and $74.4 per metric ton of CO2 emissions in 2016, in 2007 dollars. The first three values are based on the average SCC from three integrated assessment models, at discount rates of 5, 3, and 2.5 percent, respectively. Social cost of carbon values at several discount rates are included because the literature shows that the SCC is quite sensitive to assumptions about the discount rate, and because no consensus exists on the appropriate rate to use in an intergenerational context. The fourth value is the 95[th] percentile of the SCC from all three models at a 3 percent discount rate. It is included to represent higher-than-expected impacts from temperature change further out in the tails of the SCC distribution. Low probability, high impact events are incorporated into all of the SCC values through explicit consideration of their effects in two of the three models as well as the use of a probability density function for equilibrium climate sensitivity. Treating climate sensitivity probabilistically results in more high temperature outcomes, which in turn lead to higher projections of damages.
      Applying the global SCC estimates using a 3 percent discount rate, we estimate the value of the climate related benefits of this rule in 2016 is $350 million (2007$), as shown in Table 11. See the RIA for more detail on the methodology used to calculate these benefits and additional estimates of climate benefits using different discount rates and the 95[th] percentile of the 3 percent discount rate SCC. Important limitations and uncertainties of the SCC approach are also described in the RIA.
TABLE 11. ESTIMATED MONETARY VALUE (BILLIONS 2007$) OF PM2.5-RELATED HEALTH BENEFITS AND CLIMATE BENEFITS IN 2016[a]

                                    Effect
                              Monetized Benefits
Monetized Health Co-Benefits

Pope, et al. (2002)

3% discount rate
                                      $37
                                 ($2.8 - $110)

7% discount rate
                                      $33
                                 ($2.5 - $100)

Laden, et al. (2006)

3% discount rate
                                      $90
                                 ($7.7 - $260)

7% discount rate
                                      $81
                                 ($7.0 - $240)
Climate-related Co-Benefits (3% discount rate)
                                     $0.35
Monetized Total Co-Benefits

Pope, et al. (2002)

3% discount rate
                                      $37
                                 ($3.2 - $110)

7% discount rate
                                      $33
                                 ($2.9 - $100)

Laden, et al. (2006)

3% discount rate
                                      $91
                                 ($8.1 - $260)

7% discount rate
                                      $82
                                 ($7.3 - $240)
[a] Values rounded to two significant figures. Co-benefits from reducing exposure to ozone, other criteria pollutants, and HAP, as well as reducing visibility impairment and ecosystem effects are not included here.

      We estimate the monetized total co-benefits of this rule in 2016 at a 3 percent discount rate are $37 billion to $91 billion or $33 billion to $82 billion (2007$) at a 7 percent discount rate, given uncertainty about the relationship between PM2.5 concentration and health effects. These estimates account for the quantified health and climate benefits described above.
 XIII. Statutory and Executive Order Reviews
A. Executive Order 12866, Regulatory Planning and Review and Executive Order 13563, Improving Regulation and Regulatory Review
      Under EO 12866 (58 FR 51735; October 4, 1993), this action is an "economically significant regulatory action" because it is likely to have an annual effect on the economy of $100 million or more or adversely affect in a material way the economy, a sector of the economy, productivity, competition, jobs, the environment, public health or safety, or state, local, or tribal governments or communities. Accordingly, the EPA submitted this action to the OMB for review under EO 12866 and any changes in response to OMB recommendations have been documented in the docket for this action. For more information on the costs and benefits for this rule, please refer to Table 10 of this preamble.
      When estimating the human health benefits and compliance costs in Table 10 of this preamble, the EPA applied methods and assumptions consistent with the state-of-the-science for human health impact assessment, economics and air quality analysis. The EPA applied its best professional judgment in performing this analysis and believes that these estimates provide a reasonable indication of the expected benefits and costs to the nation of this rulemaking. The RIA available in the docket describes in detail the empirical basis for the EPA's assumptions and characterizes the various sources of uncertainties affecting the estimates below. In doing what is laid out above in this paragraph, the EPA adheres to EO 13563, "Improving Regulation and Regulatory Review," (76 FR 3821; January 18, 2011), which is a supplement to EO 12866.
      In addition to estimating costs and benefits, EO 13563 focuses on the importance of a "regulatory system [that]...promote[s] predictability and reduce[s] uncertainty" and that "identify[ies] and use[s] the best, most innovative, and least burdensome tools for achieving regulatory ends." In addition, EO 13563 states that "[i]n developing regulatory actions and identifying appropriate approaches, each agency shall attempt to promote such coordination, simplification, and harmonization. Each agency shall also seek to identify, as appropriate, means to achieve regulatory goals that are designed to promote innovation." We recognize that the utility sector faces a variety of requirements, including ones under CAA section 110(a)(2)(D) dealing with the interstate transport of emissions contributing to ozone and PM air quality problems, with coal combustion wastes, and with the implementation of CWA section 316(b). In developing today's final rule, the EPA recognizes that it needs to endeavor to approach these rulemakings in ways that allow the industry to make practical investment decisions that minimize costs in complying with all of the final rules, while still achieving the fundamentally important environmental and public health benefits that underlie the rulemakings.
      A summary of the monetized costs, benefits, and net benefits for the final rule at discount rates of 3 percent and 7 percent is in Table 10 of this preamble. For more information on the analysis, please refer to the RIA for this rulemaking, which is available in the docket.
B. Paperwork Reduction Act
      The information collection requirements in this rule have been submitted for approval to the OMB under the Paperwork Reduction Act, 44 U.S.C. 3501 et seq. The information collection requirements are not enforceable until OMB approves them.
	The information requirements are based on notification, recordkeeping, and reporting requirements in the NESHAP General Provisions (40 CFR Part 63, subpart A), which are mandatory for all operators subject to national emission standards. These recordkeeping and reporting requirements are specifically authorized by CAA section 114 (42 U.S.C. 7414). All information submitted to the EPA pursuant to the recordkeeping and reporting requirements for which a claim of confidentiality is made is safeguarded according to Agency policies set forth in 40 CFR Part 2, subpart B. This final rule requires maintenance inspections of the control devices but would not require any notifications or reports beyond those required by the General Provisions. The recordkeeping requirements require only the specific information needed to determine compliance.
	The annual monitoring, reporting, and record-keeping burden for this collection (averaged over the first 3 years after the effective date of the standards) is estimated to be $128.6 million. This includes 548,764 labor hours per year at a total labor cost of $36.3 million per year, and total non-labor capital costs of $92.3 million per year. This estimate includes initial and annual performance tests, semiannual excess emission reports, developing a monitoring plan, notifications, and record-keeping. Initial capital expenses to purchase monitoring equipment for affected units are estimated at a cost of $143.1 million. This includes 342,967 labor hours at a total labor cost of $22.7 million for planning, selection, purchase, installation, configuration, and certification of the new systems and total non-labor capital costs of $120.4 million. All burden estimates are in 2007 dollars and represent the most cost effective monitoring approach for affected facilities. Burden is defined at 5 CFR 1320.3(b).
      An Agency may not conduct or sponsor, and a person is not required to respond to, a collection of information unless it displays a currently valid OMB control number. The OMB control numbers for our regulations are listed in 40 CFR Part 9. When this ICR is approved by OMB, the Agency will publish a technical amendment to 40 CFR Part 9 in the Federal Register to display the OMB control number for the approved information collection requirements contained in this final rule.
C. Regulatory Flexibility Act, as Amended by the Small Business Regulatory Enforcement Fairness Act of 1996 (SBREFA), 5 U.S.C. 601 et seq.
      The Regulatory Flexibility Act (RFA) generally requires an agency to prepare a regulatory flexibility analysis of any rule subject to notice and comment rulemaking requirements under the Administrative Procedure Act or any other statute unless the agency certifies that the rule will not have a significant economic impact on a substantial number of small entities. Small entities include small businesses, small organizations, and small governmental jurisdictions.
      For purposes of assessing the impacts of today's rule on small entities, small entity is defined as: (1) a small business that is an electric utility producing 4 billion kilowatt-hours or less as defined by NAICS codes 221122 (fossil fuel-fired electric utility steam generating units) and 921150 (fossil fuel-fired electric utility steam generating units in Indian country); (2) a small governmental jurisdiction that is a government of a city, county, town, school district or special district with a population of less than 50,000; and (3) a small organization that is any not-for-profit enterprise which is independently owned and operated and is not dominant in its field.
      Pursuant to RFA section 603, the EPA prepared an initial regulatory flexibility analysis (IRFA) for the proposed rule and convened a Small Business Advocacy Review Panel to obtain advice and recommendations of representatives of the regulated small entities. A detailed discussion of the Panel's advice and recommendations is found in the Panel Report (EPA-HQ-OAR-2009-0234-2921). A summary of the Panel's recommendations is presented at 76 FR 24975.
      As required by RFA section 604, we also prepared a final regulatory flexibility analysis (FRFA) for today's final rule. The FRFA addresses the issues raised by public comments on the IRFA, which was part of the proposal of this rule. The FRFA is summarized below and in the RIA.
1. Reasons Why Action Is Being Considered
      In 2000, the EPA made a finding that it was appropriate and necessary to regulate coal- and oil-fired EGUs under CAA section 112 and listed EGUs pursuant to CAA section 112(c). On March 29, 2005 (70 FR 15994), the EPA published a final rule (Section 112(n) Revision Rule) that removed EGUs from the list of sources for which regulation under CAA section 112 was required. That rule was published in conjunction with a rule requiring reductions in emissions of mercury from EGUs pursuant to CAA section 111 (CAMR), May 18, 2005, 70 FR 28606). The Section 112(n) Revision Rule was vacated on February 8, 2008, by the U.S. Court of Appeals for the District of Columbia Circuit. As a result of that vacatur, CAMR was also vacated and EGUs remain on the list of sources that must be regulated under CAA section 112. This action provides the EPA's final rule in response to the court's decisions. Under authority of CAA section 112, the EPA is proposing NESHAP for EGUs that will regulate units at both major and area sources, henceforth referred to as the MATS.
2. Statement of Objectives and Legal Basis for Final Rules
      The MATS would protect air quality and promote public health by reducing emissions of the HAP. In the December 2000 regulatory determination, the EPA made a finding that it was appropriate and necessary to regulate EGUs under CAA section 112. The February 2008 vacatur of the Section 112(n) Revision Rule reverted the status to that of the December 2000 regulatory determination. Section 112(n)(1)(A) of the CAA and the 2000 determination do not differentiate between EGUs located at major versus area sources of HAP. Thus, the NESHAP for EGUs will regulate units at both major and area sources. Major sources of HAP are those that have the potential to emit at least 10 tons per year (tpy) of any one HAP or at least 25 tpy of any combination of HAP.
3. Summary of Issues Raised during the Public Comment Process on the IRFA
      The EPA received a number of comments related to the Regulatory Flexibility Act during the public comment process. A consolidated version of the comments received is reproduced below. These comments can also be found in their entirety in the response to comment document in the docket.
Comment: Two commenters expressed concern that smaller utilities and those in rural areas will be unable to get vendors to respond to their requests for proposals, since they will be able to make more money serving larger utilities.
Response: The preamble to the proposed rule (76FR 25054, May 3, 2011) provides a detailed discussion of how the EPA determined compliance times for the proposed rule. The EPA has provided pursuant to CAA section 112(i)(3)(A) the maximum 3hree-year period for sources to come into compliance. Sources may also seek a 1-year extension of the compliance period from their Title V permitting authority if the needs that time to install controls. See CAA section 112(i)(3)(B). If the situation described by commenters (i.e., where smaller utilities and those in rural areas are less able to get vendor responses to requests for proposals than larger utilities) results in the source needing additional time to install controls, they would be in a position to request the 1-year extension. The EPA discusses in more detail elsewhere in this notice how the Agency plans to address those units that are still unable to comply within the statutorily mandated period.
Comment: Several commenters expressed concern with the SBAR panel. Some believe Small Entity Representatives (SERs) were not provided with regulatory alternatives including descriptions of significant regulatory options, differing timetables, or simplifications of compliance and reporting requirements, and subsequently presented with an opportunity to respond. One commenter believes the EPA's formal SBAR Panel notification and subsequent information provided by the EPA to the panel did not include information on the potential impacts of the rule as required by CAA section 609(b)(1). Additional commenters suggested that the EPA's rulemaking schedule put pressure on the SBAR Panel through the abbreviated preparation for the Panel. Two commenters stated that the EPA did not identify regulatory alternatives for the SBAR Panel to consider. Commenters also expressed concerns that the EPA did not provide participants more than cursory background information on which to base their comments. One commenter stated that the EPA did not provide deliberative materials, including draft proposed rules or discussions of regulatory alternatives, to the SBAR panel members. One commenter stated the SBAR Panel Report does not meet the statutory obligation to recommend less burdensome alternatives. The commenter suggested the EPA panel members declined to make recommendations that went further than consideration or investigation of broad regulatory alternatives, with the exception of those recommendations in which the EPA rejected alternative interpretations of the CAA section 112 and relevant court cases. Two stated that the EPA did not respond to the concerns of the small business community, the SBA, or OMB, ignoring concerns expressed by the SER panelists. One commenter believes the EPA failed to convene required meetings and hearings with affected parties as required by law for small business entities. One commenter stated that the SER panel is very important because more than 90 percent of public power utility systems meet the definition and qualify as small businesses under the SBREFA.
Response: The RFA requires that panels collect advice and recommendations from SERs on the issues related to:
- the number and description of the small entities to which the proposed rule will apply;
- the projected reporting, record keeping and other compliance requirements of the proposed rule;
- duplication, overlap or conflict between the proposed rule and other federal rules; and
- alternatives to the proposed rule that accomplish the stated statutory objectives and minimize any significant economic impact on small entities.
      The RFA does not require a covered agency to create or assemble information for SERs or for the government panel members. Although CAA section 609(b)(4) requires that the government panel members review any material the covered agency has prepared in connection with the RFA, the law does not prescribe the materials to be reviewed. The EPA's policy, as reflected in its RFA guidance, is to provide as much information as possible, given time and resource constraints, to enable an informed panel discussion. In this rulemaking, because of a court-ordered deadline, the EPA was unable to hold a pre-panel meeting but still provided SERs with the information available at the time, held a standard Panel Outreach meeting to collect verbal advice and recommendations from SERs, and provided the standard 14-day written comment period to SERs. The EPA received substantial input from the SERs, and the Panel report describes recommendations made by the Panel on measures the Administrator should consider that would minimize the economic impact of the proposed rule on small entities. The EPA complied with the RFA.
Comment: One commenter requested that the EPA work with utilities such that new regulations are as flexible and cost efficient as possible.
Response: In developing the final rule, the EPA has considered all information provided prior to, as well as in response to, the proposed rule. The EPA has endeavored to make the final regulations flexible and cost efficient while adhering to the requirements of the CAA.
Comment: One commenter was concerned about the ability of small entities or nonprofit utilities such as those owned and/or operated by rural electric co-op utilities, and municipal utilities to comply with the proposed standards within 3 years. The commenter believes that the EPA disregarded the SER panelists who explained that under these current economic conditions they have constraints on their ability to raise capital for the construction of control projects and to acquire the necessary resources in order to meet a 3-year compliance deadline.
Response: The preamble to the proposed rule (76 FR 25054; May 3, 2011) provides a detailed discussion of how the EPA determined compliance times for the proposed rule. The EPA has provided pursuant to CAA section 112(i)(3)(A) the maximum 3-year period for sources to come into compliance. Sources may also seek a 1-year extension of the compliance period from their Title V permitting authority if the source needs that time to install controls. See CAA section 112(i)(3)(B). If the situation described by commenters (i.e., where small entities or nonprofit utilities constraints on ability to raise capital for construction of control projects and to acquire necessary resources) results in the source needing additional time to install controls, they would be in a position to request the 1-year extension. The EPA discusses in more detail elsewhere in this notice how the agency plans to address those units that are still unable to comply within the statutorily mandated period.
Comment: Several commenters believe the EPA did not adequately consider the disproportionately large impact on smaller generating units. The commenters note the diseconomies in scale for pollution controls for such units. One commenter noted the rule will create a more serious compliance hurdle for small communities that depend on coal-fired generation to meet their base load demand. The commenter notes that by not subcategorizing units, the EPA is dictating a fuel switch due to the disproportionately high cost on small communities. The other commenter believes the MACT and NSPS standards are unachievable by going too far without really considering the impacts on small municipal units, as public powers is critical to communities, jobs, economic viability and electric reliability. One commenter that is a generating and transmissions electric cooperative which qualifies as a small entity and believes the proposed rule will ultimately result in increased electricity costs to its members and will negatively impact the economies of the primarily rural areas that they serve. Another commenter believes there is no legal or factual basis for creating subcategories or weaker standards for state, tribal, or municipal governments or small entities that are operating obsolete units, particularly given the current market situation and applicable equitable factors. The commenter suggests both the EPA's and SBA's analyses focus exclusively on the effects on entities causing HAP emissions and primarily on those operating obsolete EGUs, and fail to consider either impacts on downwind businesses and governments or the positive impacts on small entities and governments owning and operating competing, clean and modern EGUs.
Response: The EPA disagrees with the commenters' belief that the impacts on smaller generating units were not adequately considered when developing the proposed rule. The EPA determined the number of potentially impacted small entities and assessed the potential impact of the proposed action on small entities, including municipal units. A similar assessment was conducted in support of the final action. Specifically, the EPA estimated the incremental net annualized compliance cost, which is a function of the change in capital and operating costs, fuel costs, and change in revenue. The projected compliance cost was considered relative to the projected revenue from generation. Thus, the EPA's analysis accounts not only for the additional costs these entities face resulting from compliance, but also the impact of higher electricity prices. The EPA evaluated suggestions from SERs, including subcategorization recommendations. In the preamble to the proposed rule, the EPA explains that, normally, any basis for subcategorizing must be related to an effect on emissions, rather than some difference which does not affect emissions performance. The EPA does not see a distinction between emissions from smaller generating units versus larger units. Another commenter believes that there is no legal or factual basis for creating subcategories or weaker standards for state, tribal, or municipal governments or small entities that are operating obsolete units. The commenter points out that relaxation in standards would not only harm downwind governments and small businesses who incur higher labor costs due to pollution, but will harm other small businesses and state, tribal and local governments developing or operating generation facilities using modern and less polluting generation technologies. The EPA acknowledges the commenter's assertion.
Comment: One commenter notes that the EPA recognizes LEEs in the rule such that they should receive less onerous monitoring requirements; however, the EPA does not recognize that small and LEEs also need and merit more flexible and achievable pollution control requirements. The commenter notes that  the capital costs for emissions control at small-sized utility units is disproportionately high due to inefficiencies in Hg removal, space constraints for control technology retrofits, and the fact that small units have fewer rate base customers upon which to spread these costs. The commenter cites the Michigan Department of Environmental Quality report titled "Michigan's Mercury Electric Utility Workgroup, Final Report on Mercury Emissions from Coal-Fired Power Plants," (June 2005). The commenter notes that the EPA has addressed such concerns previously, citing the RIA for the 1997 8-hour ozone standard. The commenter also suggests smaller utility systems generally have less capital to invest in pollution control than larger, investor-owned systems, due to statutory inability to borrow from the private capital markets, statutory debt ceilings, limited bonding capacity, borrowing limitations related to fiscal strain posed by other, non-environmental factors, and other limitations.
Response: The EPA acknowledges its proposal of reduced monitoring requirements for existing units that qualify as low emitting EGUs. Although the EPA does not believe that reduced pollution control requirements are warranted for LEEs, including small entity LEEs, we believe that flexible and achievable pollution control requirements are promoted through alternative standards, alternative compliance options, and emissions averaging as a means of demonstrating compliance with the standards for existing EGUs.
Comment: One commenter believes that the EPA should develop more limited monitoring requirements for small EGUs. The commenter notes small entities do not possess the monetary resources, manpower, or technical expertise needed to operate cutting-edge monitoring techniques such as Hg CEMS and PM CEMs. The commenter notes the EPA could have identified monitoring alternatives to the SER panel for consideration.
Response: The EPA provided monitoring alternatives to using PM CEMS, HCl CEMS, and Hg CEMS in its proposed standards. The continuous compliance alternatives would be available to all affected sources, including small entities. As monitoring alternatives to use of PM CEMS and HCl CEMS, sources would be allowed to conduct additional performance testing. Sorbent trap monitoring would be allowed in lieu of Hg CEMS.
Comment: Several commenters believe the EPA has not sufficiently complied with the requirements of the RFA or adequately considered the impact this rulemaking would have on small entities. One commenter believes the EPA has not given itself the opportunity to engage in meaningful outreach and consultation with small entities and therefore recommends that the EPA seek to revise the court-agreed deadlines to which this rulemaking is subject, re-convene the SBAR panel, prepare a new initial regulatory flexibility analysis (IRFA), and issue it for additional public comment prior to final rulemaking. The commenter believes the IRFA does not sufficiently consider impacts on small entities as identified in the SBAR Panel Report. The commenter believes it is not apparent that the EPA considered the recommendations of the Panel. The commenter believes the description of significant alternatives in the IRFA is almost entirely quoted from the SBAR Panel Report, which the commenter does not believe is an adequate substitute for the EPA's own analysis of alternatives. The commenter also notes the EPA does not discuss the potential impacts of its decisions on small entities or the impacts of possible flexibilities. Where the EPA does consider regulatory alternatives in principle, the commenter believes it does not provide sufficient support for its decisions to understand on what basis the EPA rejected alternatives that may or may not have reduced burden on small entities while meeting the stated objectives of the rule. Additionally, the commenter notes that the EPA did not evaluate the economic or environmental impacts of significant alternatives to the proposed rule. One commenter believes that the EPA's stated reasons for declining to specify or analyze an area source standard are inadequate under the RFA. The commenter believes the EPA must give serious consideration to regulatory alternatives that accomplish the stated objectives of the CAA while minimizing any significant economic impacts on small entities and that the EPA has a duty to specify and analyze this option or to more clearly state its policy reasons for excluding serious consideration of a separate standard for area sources. The commenter suggests that the EPA reconvene the SBAR Panel to solicit more meaningful consultation with the SERs; the EPA prepare an IRFA that includes descriptions of specific regulatory alternatives, the effects on small entities of the regulatory alternatives, and the policy reasons for selected among them; and the EPA release the IRFA for additional public comment before making any decisions about the EPA's preferred options for final rulemaking. The commenter recognizes that the EPA will have to request of the litigants and the court an extension of the timeline for final rulemaking but feels strongly that this action is necessary. A commenter believes the EPA did not fully consider the subcategorization of sources such as boilers designed to burn lignite coals versus other fossil fuels, especially in regard to non-mercury metal and acid gas emissions. The commenter references the SBAR Panel Report suggestion provided in the preamble of the proposed rule that the EPA consider developing an area source vs. major source distinction for the source category and the EPA's response. Another commenter is concerned that the recommendations made by the SER participants were ignored and not discussed in the rulemaking. Specifically, the commenter notes the EPA did not discuss subcategorizing by age, type of plant, fuel, physical space constraints or useful anticipated life of the plant. Nor did the EPA provide any opportunity for smaller emitters to use GACT  --  often used in other EPA MACT regulations to alleviate the regulatory costs and operational difficulties that would have burdened other small businesses including dry cleaners, metal fabricating, metal finishing, and others. A commenter believes it is likely that different numerical or work practice standards are appropriate for area sources of HAP, just as in other rulemakings such as the RICE rule, and that the EPA would have provided the opportunity for small entities to make such demonstration had they followed their own regulatory requirements.
Response: The EPA disagrees with one commenter's assertion that the agency has not complied with the requirements of the RFA. The EPA complied with both the letter and spirit of the RFA, even under the court-ordered deadline. For example, the EPA notified the Chief Counsel for Advocacy of the SBA of its intent to convene a Panel; compiled a list of SERs for the Panel to consult with; and convened the Panel. The Panel met with SERs to collect their advice and recommendations; reviewed the EPA materials; and drafted a report of Panel findings. The EPA further disagrees with the commenter's assertion that the EPA's IRFA does not sufficiently consider impacts on small entities. The EPA's IRFA, which is included in chapter 10 of the RIA for the proposed rule, describes, among other things, the economic impact of the proposed rule on small entities and the Panel's findings.
      Several commenters are concerned that recommendations made by the SERs were ignored and not considered or discussed in the proposed rulemaking. Specifically, commenters cite SER recommendations regarding subcategorization and separate standards for area sources. The EPA disagrees with the commenters. The preamble to the proposed standards includes detailed discussion of how the EPA determined which subcategories and sources would be regulated (76 FR 25036-25037; May 3, 2011). In that discussion, the EPA explains the rationale for its proposed subcategories based on five unit design types. In addition, the EPA acknowledges the subcategorization suggestions from the SERs and explains its reasons for not subcategorizing on those bases. The preamble to the proposed standards also includes a discussion of the SERs' suggestion that area source EGUs be distinguished from major-source EGUs and the EPA's reasons for not making that distinction (76 FR 25020-25021; May 3, 2011).
      One commenter suggests that the EPA pursue an extension of the timeline for final rulemaking such that the SBAR Panel can be reconvened and a new IRFA can be prepared and released for public comment prior to the final rulemaking. The EPA entered into a Consent Decree to resolve litigation alleging that the EPA failed to perform a non-discretionary duty to promulgate CAA section 112(d) standards for EGUs. See American Nurses Ass'n v. EPA, 08-2198 (D.D.C.). That Decree required the EPA to sign the final MATS rule by November 16, 2011, unless the agency sought to extend the deadline consistent with the requirements of the modification provision of the Consent Decree. If plaintiffs in the American Nurses litigation objected to an extension request, which we believe they would have based on their comments on the proposed rule, the agency would have had to file a motion with the Court seeking an extension of the deadline. Consistent with governing case law, the agency would have been required to demonstrate in its motion for extension that it was impossible to finalize the rule by the deadline provided in the Consent Decree. See Sierra Club v. Jackson, Civil Action No. 01-1537 (D.D.C.) (Opinion of the Court denying EPA's motion to extend a consent decree deadline). The EPA negotiated a 30-day extension and was able to complete the rule by December 16, 2011; accordingly, the agency had no basis for seeking a further extension of time.
       A detailed description of the changes made to the rule since proposal, including those made as a result of feedback received during the public comment process can be found in sections VI (NESHAP) and X (NSPS) of this preamble. Changes explained in the identified sections include those related to applicability; subcategorization; work practices; periods of startup, shutdown, and malfunction; initial testing and compliance; continuous compliance; and notification, recordkeeping, and reporting.
4. Description and Estimate of the Affected Small Entities
      For the purposes of assessing the impacts of MATS on small entities, a small entity is defined as:
      (1)	A small business according to the Small Business Administration size standards by the North American Industry Classification System (NAICS) category of the owning entity. The range of small business size standards for electric utilities is 4 billion kilowatt hours (kWh) of production or less;
      (2)	A small government jurisdiction that is a government of a city, county, town, district, or special district with a population of less than 50,000; and
      (3)	A small organization that is any not for profit enterprise that is independently owned and operated and is not dominant in its field.
      The EPA examined the potential economic impacts to small entities associated with this rulemaking based on assumptions of how the affected entities will install control technologies in compliance with MATS. This analysis does not examine potential indirect economic impacts associated with this rule, such as employment effects in industries providing fuel and pollution control equipment, or the potential effects of electricity price increases on industries and households.
      The EPA used Velocity Suite's Ventyx data as a basis for identifying plant ownership and compiling the list of potentially affected small entities. The Ventyx dataset contains detailed ownership and corporate affiliation information. The analysis focused only on those EGUs affected by the rule, which includes units burning coal, oil, petroleum coke, or coal refuse as the primary fuel, and excludes any combustion turbine units or EGUs burning natural gas. Also, because the rule does not affect combustion units with an equivalent electricity generating capacity up to 25 MW, small entities that do not own at least one combustion unit with a capacity greater than 25 MW were removed from the dataset. For the affected units remaining, boiler and generator capacity, heat input, generation, and emissions data were aggregated by owner and then by parent company. Entities with more than 4 billion kWh of annual electricity generation were removed from the list, as were municipal owned entities with a population greater than 50,000. For cooperatives, investor owned utilities, and subdivisions that generate less than 4 billion kWh of electricity annually but which may be part of a large entity, additional research on power sales, operating revenues, and other business activities was performed to make a final determination regarding size. Finally, small entities for which the IPM does not project generation in 2015 in the base case were omitted from the analysis because they are not projected to be operating and, thus, are not projected to face the costs of compliance with the rule. After omitting entities for the reasons above, the EPA identified a total of 83 potentially affected small entities that are affiliated with 105 electric generating units.
5. Compliance Cost Impacts
	The number of potentially affected small entities by ownership type and potential impacts of MATS are presented in Chapter 7 of the RIA and summarized here. The EPA estimated the annualized net compliance cost to small entities to be approximately $79 million in 2015 (2007$).
      The EPA assessed the economic and financial impacts of the final rule using the ratio of compliance costs to the value of revenues from electricity generation, and our results focus on those entities for which this measure could be greater than 1 percent or 3 percent. Of the 83 small entities identified, The EPA's analysis shows 49 entities may experience compliance costs greater than 1 percent of base generation revenues in 2015, and 36 may experience compliance costs greater than 3 percent of base revenues. Also, all generating capacity at 3 small entities is projected to be uneconomic to maintain. In this analysis, the cost of withdrawing a unit as uneconomic is estimated as the base case profit that is forgone by not operating under the policy case. Because 36 of the 83 total units, or more than 40 percent, are estimated to incur compliance cost greater than 3 percent of base revenues, the EPA has concluded that it cannot certify that there will be no SISNOSE for this rule. Results for small entities discussed here do not account for the reality that electricity markets are regulated in parts of the country. Entities operating in regulated or cost-of-service markets should be able to recover all of their costs of compliance through rate adjustments.
      Note that the estimated costs for small entities are significantly lower than those estimated by the EPA for the MATS proposal (which were $379 million). This is driven by a small group of units (less than 6 percent) which were projected to be uneconomic to operate under the proposal (and hence incurred lost profits due to lost electricity revenues), but are now projected to continue their operations under MATS. In addition, the EPA's modeling indicates one unit that would have operated at a low capacity factor under the base case would find it economical to increase its generation significantly under MATS to meet electricity demand in its region. Excluding this unit, the total cost impacts across all entities would be roughly $169 million. Changes in compliance behavior for this small group of units, in particular the one unit which operates at a higher capacity factor, has a substantial impact on total costs as their increased generation revenues offsets a large portion of the compliance costs.
      The most significant components of incremental costs to these entities are changes in electricity revenues, followed by the increased capital and operating costs for retrofits. Capital and operating costs increase across all ownership types, but the direction of changes in electricity revenues vary among ownership types. All ownership types, with the exception of private entities, experience a net gain in electricity revenues under the MATS, unlike projections from the EPA's modeling during the proposal, where only municipals benefitted from higher electricity revenues. The change in electricity revenue takes into account both the profit lost from units that do not operate under the policy case and the difference in revenue for operating units under the policy case. According to the EPA's modeling, an estimated 274 MW of capacity owned by small entities are considered uneconomic to operate under the policy case, resulting in a net loss of $13 million (in 2007$) in profits. On the other hand, many operating units actually increase their electricity revenue due to higher electricity prices under MATS. In addition, as mentioned above, the EPA's modeling indicates one unit finds it economical to increase its capacity factor significantly under the policy case which results in significantly higher revenues offsetting the costs.
6. Description of Steps to Minimize Impacts on Small Entities
      Consistent with the requirements of the RFA and SBREFA, the EPA has taken steps to minimize the significant economic impact on small entities. Because this rule does not affect units with a generating capacity of less than 25 MW, small entities that do not own at least one generating unit with a capacity greater than 25 MW are not subject to the rule. According to the EPA's analysis, among the coal- and oil-fired EGUs (i.e., excluding combined cycle gas turbines and gas combustion turbines) about 26 potentially small entities only own EGUs with a capacity less than or equal to 25 MW, and none of those entities are subject to the final rule based on the statutory definition of potentially regulated units.
      For units affected by the proposed rule, the EPA considered a number of comments received, both during the Small Business Advocacy Review (SBAR) Panel and the public comment period. While none of the alternatives adopted are specifically applied to small entities, the EPA believes these modifications will make compliance less onerous for all regulated units, including those owned by small entities.
a. Work practice standards. The EPA proposed numerical emission standards that would apply at all times, including during periods of startup and shutdown. After reviewing comments and other data regarding the nature of these periods of operation, the EPA is finalizing a work practice standard for periods of startup and shutdown. The EPA is also finalizing work practice standards for organic HAP from all subcategories of EGUs. The EPA has chosen to finalize work practice standards because the significant majority of data for measured organic HAP emissions from EGUs are below the detection levels of the EPA test methods, and, as such, the Agency considers it impracticable to reliably measure emissions from these units. Descriptions of the work practice requirements for startup and shutdown, as well as organic HAP, can be found in Section VI.D-E. of the preamble.
b. Continuous compliance and notification, record-keeping, and reporting. The final rule greatly simplifies the continuous compliance requirements and provides two basic approaches for most situations: use of continuous monitoring and periodic testing. The frequency of periodic testing has been decreased from monthly in the proposal to quarterly in the final rule. In addition to simplifying compliance, the EPA believes these changes considerably reduce the overall burden associated with recordkeeping and reporting. These changes to the final rule are described in more detail in Section VI.G-H of this preamble.
c. Subcategorization. The Small Entity Representatives on the SBAR Panel were generally supportive of subcategorization and suggested a number of additional subcategories the EPA should consider when developing the final rule. Although it was not practicable to adopt the proposed subcategories, the EPA maintained the existing subcategories and spilt the "liquid oil-fired units" subcategory into two individual subcategories  -  continental and non-continental units.
d. MACT floor calculations. As recommended by the EPA SBAR Panel representative, the EPA established the MACT floors using all the available ICR data that was received to the maximum extent possible consistent with the CAA requirements. The Agency believes this approach reasonably ensures that the emission limits selected as the MACT floors adequately represent the level of emissions actually achieved by the average of the units in the top 12 percent, considering operational variability of those units. Additionally, following proposal, the EPA reviewed and revised the procedure intended to account for the contribution of measurement imprecision to data variability in establishing effective emissions limits.
e. Alternatives not adopted. The EPA chose not to adopt several of the suggestions posed either during the SBAR Panel or public comment period. The EPA did not propose a percent reduction standard as an alternative to the concentration-based MACT floor. The percent reduction format for Hg and other HAP emissions would not have addressed the EPA's desire to promote, and give credit for, coal preparation practices that remove Hg and other HAP before firing. Also, to account for the coal preparation practices, sources would be required to track the HAP concentrations in coal from the mine to the stack, and not just before and after the control device(s), and such an approach would be difficult to implement and enforce. Furthermore, the EPA does not believe the percent reduction standard is in line with the Court's interpretation of the CAA section 112 requirements. Even if we believed it was appropriate to establish a percent reduction standard, we do not have the data necessary to establish percent reduction standards for HAP, as explained further in the response to comments.
      The EPA chose not to establish GACT standards for area sources for a number of reasons. The data show that similar HAP emissions and control technologies are found on both major and area sources greater than 25 MW, and some large units are synthetic area sources. In fact, because of the significant number of well-controlled EGUs of all sizes, we believe it would be difficult to make a distinction between MACT and GACT. Moreover, the EPA believes the standards for area source EGUs should reflect MACT, rather than GACT, because there is no essential difference between area source and major source EGUs with respect to emissions of HAP.
      The EPA chose not to exercise its discretionary authority to establish health-based emission standards for HCl and other HAP acid gases. Given the limitations of the currently available information (e.g., the HAP mix where EGUs are located, and the cumulative impacts of respiratory irritants from nearby sources), the environmental effects of HCl and the other acid gas HAP, and the significant co-benefits from reductions in criteria pollutants the EPA determined that setting a conventional MACT standard for HCl and the other acid gas HAP was the appropriate course of action.
      As required by SBREFA section 212, the EPA also is preparing a Small Entity Compliance Guide to help small entities comply with this rule. Small entities will be able to obtain a copy of the Small Entity Compliance guide at the following Web site: http://www.epa.gov/airquality/powerplanttoxics/actions.html
D. Unfunded Mandates Reform Act of 1995
      Title II of the Unfunded Mandates Reform Act of 1995 (UMRA), 2 U.S.C. 1531-1538, requires Federal agencies, unless otherwise prohibited by law, to assess the effects of their regulatory actions on state, local, and tribal governments and the private sector. This rule contains a Federal mandate that may result in expenditures of $100 million or more for state, local, and tribal governments, in the aggregate, or the private sector in any one year. Accordingly, EPA has prepared under UMRA section 202 a written statement which is summarized below.
      Before promulgating an EPA rule for which a written statement is needed under UMRA section 202, UMRA section 205, 2 U.S.C. 1535, generally requires the EPA to identify and consider a reasonable number of regulatory alternatives and adopt the least costly, most cost effective, or least burdensome alternative that achieves the objectives of the rule. Moreover, UMRA section 205 allows the EPA to adopt an alternative other than the least costly, most cost-effective or least burdensome alternative if the Administrator publishes an explanation why that alternative was not adopted.
      In a manner consistent with the intergovernmental consultation provisions of UMRA section 204, the EPA carried out consultations with the governmental entities affected by this rule. The EPA held meetings with states and Tribal representatives in which the Agency presented its plan to develop a proposal and provided opportunities for participants to provide input as part of the rulemaking process. The EPA has also analyzed the economic impacts of the final MATS rule on government entities and this section presents the results of that analysis. This analysis does not examine potential indirect economic impacts associated with the final rule, such as employment effects in industries providing fuel and pollution control equipment, or the potential effects of electricity price increases on industries and households.
E. Executive Order 13132, Federalism
      Under EO 13132, the EPA may not issue an action that has federalism implications, that imposes substantial direct compliance costs, and that is not required by statute, unless the Federal government provides the funds necessary to pay the direct compliance costs incurred by state and local governments, or the EPA consults with state and local officials early in the process of developing the final action.
      The EPA has concluded that this action may have federalism implications, because it may impose substantial direct compliance costs on state or local governments, and the Federal government will not provide the funds necessary to pay those costs. Accordingly, the EPA provides the following federalism summary impact statement as required by section 6(b) of EO 13132.
      Based on estimates in the RIA, provided in the docket, the final rule may have federalism implications because the rule may impose approximately ${xx} in annual direct compliance costs on an estimated {xx} state or local governments. Specifically, we estimate that there are {xx} municipalities, {xx} states, and {xx} political subdivisions (i.e., a public district with territorial boundaries embracing an area wider than a single municipality and frequently covering more than one county for the purpose of generating, transmitting and distributing electric energy) that may be directly impacted by this final rule. Responses to the EPA's 2010 ICR were used to estimate the nationwide number of potentially impacted state or local governments. As previously explained, this 2010 survey was submitted to all coal- and oil-fired EGUs listed in the 2007 version of DOE/EIA's "Annual Electric Generator Report," and "Power Plant Operations Report."
      The EPA consulted with state and local officials in the process of developing the rule to permit them to have meaningful and timely input into its development. The EPA met with 10 national organizations representing state and local elected officials to provide general background on the rule, answer questions, and solicit input from state/local governments.
F. Executive Order 13175, Consultation and Coordination with Indian Tribal Governments
      Subject to EO 13175 (65 FR 67249; November 9, 2000) the EPA may not issue a regulation that has Tribal implications, that imposes substantial direct compliance costs, and that is not required by statute, unless the Federal government provides the funds necessary to pay the direct compliance costs incurred by Tribal governments, or the EPA consults with Tribal officials early in the process of developing the proposed regulation and develops a Tribal summary impact statement. Executive Order 13175 requires the EPA to develop an accountable process to ensure "meaningful and timely input by tribal officials in the development of regulatory policies that have tribal implications."
      The EPA has concluded that this action may have tribal implications, because it may impose substantial direct compliance costs on tribal governments, and the Federal government will not provide the funds necessary to pay those costs. Accordingly, EPA provides the following tribal summary impact statement as required by section 5(b).
      The EPA offered consultation with Tribal officials early in the process of developing this regulation to permit them to have meaningful and timely input into its development. Consultation letters were sent to 584 Tribal leaders. The letters provided information regarding the EPA's development of NESHAP for EGUs and offered consultation. Three consultation meetings were held on December 7, 2010, with the Upper Sioux Community of Minnesota; December 13, 2010, with Moapa Band of Paiutes, Forest County Potawatomi, Standing Rock Sioux Tribal Council, Fond du Lac Band of Chippewa; January 5, 2011, with the Forest County Potawatomi, and a representative from the National Tribal Air Association. In these meetings, the EPA presented the authority under the CAA used to develop these rules, and an overview of the industry and the industrial processes that have the potential for regulation. Tribes expressed concerns about the impact of EGUs on the reservations. Particularly, they were concerned about potential Hg deposition and the impact on the water resources of the Tribes, with particular concern about the impact on subsistence lifestyles for fishing communities, the cultural impact of impaired water quality for ceremonial purposes, and the economic impact on tourism. In light of these concerns, the tribes expressed interest in an expedited implementation of the rule. Other concerns expressed by tribes were about how the Agency would consider variability in setting the standards, the use of tribal-specific fish consumption data from the Tribes in our assessments, they were not supportive of using work practice standards as part of the rule, and asked the Agency to consider going beyond the floor to offer more protection for the tribal communities.
      In addition to these consultations, the EPA also conducted outreach on this rule through presentations at the National Tribal Forum in Milwaukee, WI, phone calls with the National Tribal Air Association, and a webinar for tribes on the proposed rule. The EPA specifically requested tribal data that could support the appropriate and necessary analyses and the RIA for this rule. In addition, the EPA held individual consultations with the Navajo Nation on October 12, 2011; as well as the Gila River Indian Community, Ak-Chin Indian Community, and the Hopi Nation on October 14, 2011. These tribes expressed concerns about the impact of the rule on the Navajo Generating Station (NGS), the impact on the cost of the water allotted to the tribes from the Central Arizona Project (CAP) the impact on tribal revenues from the coal mining operations, and the impacts on employment of tribal members at both the NGS and the mine. More specific comments can be found in the docket.
      As required by section 7(a), EPA's Tribal Consultation Official has certified that the requirements of the EO have been met in a meaningful and timely manner. A copy of the certification is included in the docket for this action.
G. Executive Order 13045, Protection of Children from Environmental Health Risks and Safety Risks
      This final rule is subject to EO 13045 (62 FR 19885; April 23, 1997) because it is an economically significant regulatory action as defined by EO 12866, and EPA believes that the environmental health or safety risk addressed by this action may have a disproportionate effect on children. Accordingly, we have evaluated the environmental health or safety effects of the standards on children.
      Although this final rule is based on technology performance, the standards are designed to protect against hazards to public health with an adequate margin of safety as described in Section III of this preamble. The protection offered by this rule may be especially important for children, especially the developing fetus. As referenced in Chapter 4 of the RIA, "Mercury and Other HAP Benefits Analysis" children are more vulnerable than adults to many HAP emitted by EGUs due to differential behavior patterns and physiology. These unique susceptibilities were carefully considered in a number of different ways in the analyses associated with this rulemaking, and are summarized in the RIA.
H. Executive Order 13211, Actions Concerning Regulations That Significantly Affect Energy Supply, Distribution, or Use
      Executive Order 13211 (66 FR 28355; May 22, 2001) requires EPA to prepare and submit a Statement of Energy Effects to the Administrator of the Office of Information and Regulatory Affairs, OMB, for actions identified as "significant energy actions." This action, which is a significant regulatory action under EO 12866, is likely to have a significant adverse effect on the supply, distribution, or use of energy. We have prepared a Statement of Energy Effects for this action as follows.
      We estimate a 3 percent price increase for electricity nationwide in 2016 and a less than 2 percent percentage fall in coal-fired power production. The EPA projects that delivered natural gas prices will increase by about 0.7 percent over the 2015 to 2030 timeframe. For more information on the estimated energy effects, please refer to the economic impact analysis for this final rule. The analysis is available in the RIA, which is in the public docket.
I. National Technology Transfer and Advancement Act
      Section 12(d) of the National Technology Transfer and Advancement Act (NTTAA) of 1995 (Public Law No. 104-113; 15 U.S.C. 272 note) directs the EPA to use voluntary consensus standards in its regulatory activities unless to do so would be inconsistent with applicable law or otherwise impractical. Voluntary consensus standards are technical standards (e.g., materials specifications, test methods, sampling procedures, business practices) that are developed or adopted by voluntary consensus standards bodies. The NTTAA directs the EPA to provide Congress, through OMB, explanations when the Agency decides not to use available and applicable voluntary consensus standards.
      This rulemaking involves technical standards. The EPA cites the following standards in the final rule: EPA Methods 1, 2, 2A, 2C, 2F, 2G, 3A, 3B, 4, 5, 5D, 17, 19, 23, 26, 26A, 29, 30B of 40 CFR Part 60 and Method 320 of 40 CFR Part 63. Consistent with the NTTAA, the EPA conducted searches to identify voluntary consensus standards in addition to these EPA methods. No applicable voluntary consensus standards were identified for EPA Methods 2F, 2G, 5D, and 19. The search and review results have been documented and are placed in the docket for the proposed rule.
      The three voluntary consensus standards described below were identified as acceptable alternatives to EPA test methods for the purposes of the final rule.
      The voluntary consensus standard American Society of Mechanical Engineers (ASME) PTC 19-10-1981-Part 10, "Flue and Exhaust Gas Analyses," is cited in the final rule for its manual method for measuring the O2, CO2, and CO content of exhaust gas. This part of ASME PTC 19-10-1981-Part 10 is an acceptable alternative to Method 3B.
      The voluntary consensus standard ASTM D6348-03(2010), "Determination of Gaseous Compounds by Extractive Direct Interface Fourier Transform (FTIR) Spectroscopy" is acceptable as an alternative to Method 320 and is cited in the final rule, but with several conditions: (1) The test plan preparation and implementation in the Annexes to ASTM D 6348-03, Sections A1 through A8 are mandatory; and (2) In ASTM D6348-03 Annex A5 (Analyte Spiking Technique), the percent (%) R must be determined for each target analyte (Equation A5.5). In order for the test data to be acceptable for a compound, %R must be 70 % >= R <= 130%. If the %R value does not meet this criterion for a target compound, the test data are not acceptable for that compound and the test must be repeated for that analyte (i.e., the sampling and/or analytical procedure should be adjusted before a retest). The %R value for each compound must be reported in the test report, and all field measurements must be corrected with the calculated %R value for that compound by using the following equation:  Reported Result = (Measured Concentration in the Stack x 100) / % R.
      The voluntary consensus standard ASTM D6784-20, "Standard Method for Elemental, Oxidized, Particle-Bound and Total Mercury in Flue Gas Generated from Coal-Fired Stationary Sources (Ontario Hydro Method)," is an acceptable alternative to use of EPA Method 29 for Hg only or Method 30B for the purpose of conducting relative accuracy tests of mercury continuous monitoring systems under this final rule. Because of the limitations of this method in terms of total sampling volume, it is not appropriate for use in performance testing under this rule.